diff --git a/raw/filings/0000077877/2000/0000077877-01-500003/filing.txt b/raw/filings/0000077877/2000/0000077877-01-500003/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..432ab0e77602e558b8a5e0efa27d007e0ef57b5e --- /dev/null +++ b/raw/filings/0000077877/2000/0000077877-01-500003/filing.txt @@ -0,0 +1,2690 @@ +10-K +1 +pdc10k.htm +PDC 10-K HTML +10Khtm +CONFORMED COPY +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +[] ANNUAL REPORT PURSUANT TO SECTION 13 or 15 (d) OF +THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2000 +Commission File Number 0-7246 +[] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transaction period from +to +PETROLEUM DEVELOPMENT CORPORATION +(Exact name of registrant as specified in its charter) +Nevada +95-2636730 +(State or other jurisdiction of +(I.R.S. Employer +incorporation or organization) +Identification No.) +103 East Main Street, Bridgeport, West Virginia 26330 +(Address of principal executive offices) (zip code) +Registrant's telephone number, including area code (304) 842-3597 +SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: NONE +SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: +Petroleum Development Corporation Common Stock, $.01 par value +(Title of class) +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 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 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. [ ] +As of March 15, 2001, 16,244,044 shares of the Registrant's Common Stock were issued and outstanding, and the aggregate market value of such shares held by non-affiliates of the Registrant on such date was $ 74,607,760 (based on the +last traded price of $6.375). +DOCUMENTS INCORPORATED BY REFERENCE +Document +Form 10-K Part III +Proxy +Items 11 and 12 +PART I +Item 1. Business +The Company is an independent energy company engaged primarily in the development, production and marketing of natural gas and oil. The Company has grown primarily through drilling and development +activities, the acquisition of natural gas and oil producing wells and the expansion of its natural gas marketing activities. As of December 31, 2000, the Company operates approximately 2,025 wells located in the Appalachian basin, Michigan, and the Rocky +Mountain Region, with gross proved reserves of 307 Bcfe of natural gas of which the Company's share is 132 Bcfe of natural gas. The wells operated by the Company currently produce an aggregate of approximately 47,000 thousand cubic feet equivalent +("Mcfe", based on one barrel of oil equals 6 thousand cubic feet "Mcf" of gas.) of natural gas per day, of which the Company's share is approximately 19,500 Mcfe. +The Company's operations are divided into three regions, the Appalachian Basin, Michigan, and the Rocky Mountains. The Company has conducted operations in Appalachia since its inception in 1969, in +Michigan since 1997, and the Rocky Mountains since 1999. As of the end of 2000 approximately 39% of production was generated by Appalachian Basin wells, 36% by Michigan wells, and 25% by Colorado wells. At the end of 2000 the Company's reserves were +divided almost equally among three regions, with all of the recorded proved undeveloped reserves in Michigan and Colorado. This reflects the planned drilling for 2001, which will be focused in Colorado and to a lesser extent in Michigan. +In all three regions the Company has historically targeted shallow, developmental natural gas reserves for development. In most areas of Colorado the wells also produce oil in conjunction with natural gas. +In one of our areas in Michigan, oil is the dominant economic product. The Company is also investigating the potential for deeper exploratory wells in the Rocky Mountain region, with plans to include several exploratory prospects in its 2001 drilling plans. +The Company owns Riley Natural Gas (RNG), an Appalachian Basin natural gas marketing company, which aggregates and resells natural gas developed by the Company and other producers. This allows the Company +to diversify its operations beyond natural gas drilling and production. RNG has established relationships with many of the small natural gas producers in the Appalachian Basin and has significant expertise in the natural gas end-user market. In addition, +RNG has extensive experience in the use of hedging strategies, which the Company utilizes to reduce the financial impact on the Company of changes in the price of natural gas. +Since 1984, the Company has sponsored limited partnerships formed to engage in drilling operations. The Company typically retains a 20% ownership interest in these drilling limited partnerships. In 2000, +the Company raised $55.6 million through four public drilling partnerships, making it the sponsor of the largest public oil and gas partnership program in the United States in that year. The drilling programs have provided the Company with access to the +capital resources necessary to expand its drilling opportunities and to maintain the infrastructure necessary to support such activities. +Industry Overview +Natural gas is the second largest energy source in the United States, after liquid petroleum. The 22.7 Tcf of natural gas consumed in 2000 represented approximately 23% of the total energy used in the United States. +Natural gas is consumed in the United States as follows: 45% by industrial end-users as feedstock for products such as plastic and fertilizer or as the energy source for producing products such as glass; 22% and 16% by residential and commercial +end-users, respectively, for uses including heating, cooling and cooking; 12% by utilities for the generation of electricity; and the remainder for transportation purposes. (Source U.S. Energy Information Administration) +-2- +The Company believes that the market for natural gas will grow in the future. The demand for natural gas has increased due to four main factors: +- Efficiency. Relative to other energy sources, natural gas losses during transportation from source to destination are slight, averaging only about 9% of the natural gas energy. +- Environmentally favorable. Natural gas is the cleanest and most environmentally safe of the fossil fuels. +- Safety. The delivery of natural gas is among the safest means of distributing energy to customers, as the natural gas transmission system is fixed and is located underground. +- Price. The deregulation of the natural gas industry and a favorable regulatory environment have resulted in end-users' ability to purchase natural gas on a competitive basis from a greater +variety of sources. +The Company believes that the foregoing factors, together with the increased availability of natural gas as a form of energy for residential, commercial and industrial uses, should increase the demand for natural gas as well as create +new markets for natural gas. +As local supplies of natural gas are inadequate to meet demand, the West Coast and the Northeast import natural gas from producing areas via interstate natural gas pipelines. The cost of transporting +natural gas from the major producing areas to markets creates a price advantage for production located closer to the consuming regions. The natural gas industry in the Appalachian Basin and Michigan benefit from proximity to the northeastern United States. +In the early 1980's, natural gas companies began exploiting the northern portion of Michigan's lower peninsula, when certain favorable tax credits for natural gas development were enacted. The result of +such development was new advances in drilling technology, which made natural gas drilling in this area profitable even after the expiration of these tax credits. In Michigan's lower peninsula, there is an abundance of shallow Antrim gas shale, which can +provide significant reserves per well drilled. Additionally, this area is close to certain end-user markets, which has provided favorable premiums. +During 1998 the Company began to establish a lease position in the Rocky Mountain producing region. The region is believed to hold substantial undeveloped natural gas resources. Recent additions to +pipeline capacity in the region have made the area more attractive for development. Gas from the region will generally sell for less than gas in the Appalachian and Michigan Basins, but costs of development are expected to be less. During 1998, the +Company leased 39,500 acres of oil and gas development rights acres in Utah. In 1999 the company drilled four unsuccessful exploratory wells, two in Moffatt County, Colorado and two in Carter County, Montana. In November and December 1999 the Company +acquired drilling rights to 20 locations in the Wattenberg field in Weld County, Colorado and a 7,400 acre lease in the Grand Valley field in Garfield County, Colorado. Prior to the end of 1999, the Company had drilled five successful wells in the +Wattenberg field and was prepared to drill its first Grand Valley test well. The Company expanded its operations in the Rocky Mountains in 2000, by drilling 52 successful wells and adding over 50,000 acres to its position in the Wattenberg and Grand +Valley fields. The Company plans to do the majority of its development work in these areas in 2001. +Business Strategy +The Company's objective is to expand its natural gas reserves, production and revenues through a strategy that includes the following key elements: +-3- +Expand drilling operations. The Company has had one of the most active drilling programs in the Northeast in the 1990's and will seek to continue to build on the experience developed. The Company drilled +97 wells in 2000, compared to 178 for the year of 1999. The decrease in the number of wells drilled results primarily from the greater cost of the Rocky Mountain wells compared to the Company's Appalachian and Michigan wells. The Company believes that it +will be able to drill a substantial number of new wells on its current undeveloped leased properties. As of December 31, 2000, the Company had 11,000 undeveloped acres in the Michigan Basin, 12,900 undeveloped acres in the Appalachian Basin and 164,600 +undeveloped acres in the Rocky Mountain Region. As drilling activity increases, the Company benefits as its fixed costs may be spread over a larger number of wells. +Acquire producing properties. The Company's acquisition efforts are focused on properties that fit well within existing operations or that help to build critical mass in areas where the Company is +establishing new operations. Acquisitions will likely offer economies in management and administration, and therefore the Company believes that it will be able to acquire more producing wells without incurring substantial increases in its costs of +operations. +Pursue geographic expansion. The Company has a proven ability to drill and operate shallow natural gas wells successfully. There are a number of areas outside the Appalachian Basin where drilling and +operating characteristics are similar to those in Appalachia. For example, since 1996, the Company expanded into the Michigan Basin, which permitted the Company to leverage its expertise developed in the Appalachian Basin because of the similarities in +methods of drilling, depth, equipment and operations. Moreover, reserves and production levels of two to three times that of Appalachian levels for a similar investment more than offset higher expected operating costs. The Company's Colorado development +projects also build on our shallow gas well operating experience. The Company will continue to evaluate opportunities to expand geographically on an ongoing basis. +Reduce risks inherent in natural gas development and marketing. An integral part of the Company's strategy has been and will continue to be to concentrate on shallow development, (rather than exploratory) +drilling, and geographical diversification to reduce risk levels associated with natural gas and oil production. Development drilling is less risky than exploratory drilling and is likely to generate cash returns more quickly. The focus on shallow wells +builds on the Company's knowledge and experience, and also provides greater investment diversification than an equal investment in a smaller number of deeper and/or more expensive wells. Geographical diversification can help to offset possible weakness in +the natural gas market or disappointing drilling results in one area. The Company believes that, as natural gas markets are deregulated, successful natural gas marketing is essential to profitable operations. To further this goal, the Company has the +expertise of RNG, an experienced natural gas marketer. The Company intends to continue to expand its marketing capacity to keep pace with the changing natural gas industry. +Exploration and Development Activities +The Company's development activities focus on the identification and drilling of new productive wells and the acquisition of existing producing wells from other producers. +Prospect Generation +The Company's staff of professional geologists is responsible for identifying areas with potential for economic production of natural gas and oil. These geologists have decades of cumulative drilling of +successful, economically feasible natural gas and oil wells. They utilize results from logs and other tools to evaluate existing wells and to predict the location of attractive new gas reserves. To further this process, the Company has collected and +continues to collect logs, core data, production information and other raw data available from state and private agencies, other companies and individuals actively drilling in the regions being evaluated. From this information the geologists develop +models of the subsurface structures and stratigraphy that are used to predict areas with above-average prospects for economic development. +-4- +On the basis of these models, the geologists instruct the Company's land department to obtain available natural gas leaseholds in these prospective areas. These leases are then obtained, if possible, by +the Company's land department or contract landmen under the direction of the Company's land manager. In most cases, the Company pays a lease bonus and annual rental payments, converting, upon initiation of production, to a 12.5% royalty on gross +production revenue in return for obtaining the leases. In some instances of particularly attractive properties, additional overriding royalty payments may be made to third parties or royalty owners. As of December 31, 2000, the Company had a total +leasehold inventory of approximately 294,040 acres. See--"Properties--Natural Gas Leases." +Drilling Activities +When prospects have been identified and leased, the Company develops these properties by drilling wells. In 2000, the Company drilled a total of 97 wells, with no dry holes. Typically, the Company will act +as driller-operator for these prospects, entering into contracts with partnerships, including Company-sponsored partnerships, and other entities that are interested in exploration or development of the prospects. The Company generally retains an interest +in each well it drills. See "Financing of Drilling Activities." +Much of the work associated with drilling, completing and connecting wells, including drilling, fracturing, logging and pipeline construction, is performed by subcontractors specializing in those +operations, as is common in the industry. A large part of the material and services used by the Company in the development process is acquired through competitive bidding by approved vendors. The Company also directly negotiates rates and costs for +services and supplies when conditions indicate that such an approach is warranted. As the prices paid to the Company by its investor partners for the Company's services are frequently fixed before the wells are drilled or are determined solely on the well +depth, the Company is subject to the risk that prices of goods or services used in the development process could increase, rendering its contracts with its investor partners less profitable or unprofitable. In addition, problems encountered in the process +can substantially increase development costs, sometimes without recourse for the Company to recover its costs from its partners. To minimize these risks, the Company seeks to lock in its development costs in advance of drilling and, when possible, at the +time of negotiation and execution of its investor partnership agreements. +Acquisitions of Producing Properties +In addition to drilling new wells, the Company continues to pursue opportunities to purchase existing wells from other producers and greater ownership interests in the wells it operates. Generally, outside +interests purchased include a majority interest in the wells and well operations. +During 1998 the Company purchased an 80% interest in 122 producing wells located in Pennsylvania from Pemco Gas, Inc. and a 100% working interest in 13 producing wells in Michigan. During 1999, the Company purchased a 100% working +interest in 53 producing wells in the D-J Basin of Colorado which added 3.6 Bcf of natural gas and 370,000 barrels of oil to the Company's reserves. During 2000, the Company purchased 100% of the working interest in 168 producing wells in the DJ Basin of +Colorado which added 4.9 Bcf of natural gas and 560,000 barrels of oil to the Company's reserves. Also purchased in 1998, 1999 and 2000 were certain well interests in its Company sponsored partnerships. +-5- +Production +The following table shows the Company's net production in Bbls of crude oil and in Mcf of natural gas and the costs and weighted average selling prices thereof, for the last five years. +Year Ended December 31, +2000 +1999 +1998 +1997 +1996 +Production(1): +Oil(MBbls) +109 +8 +8 +9 +7 +Natural Gas (MMcf) +5,737 +3,451 +2,453 +1,810 +1,495 +Equivalent MMcfs(2) +6,391 +3,499 +2,501 +1,864 +1,537 +Average sales price: +Oil (per Bbl) +$29.99 +$18.75 +$10.61 +$16.10 +$16.35 +Natural gas (per Mcf)(3) +$2.74 +$2.46 +$2.46 +$2.88 +$3.04 +Average production cost +(lifting cost) per +equivalent Mcf(4) +$0.66 +$0.69 +$0.61 +$0.65 +$0.63 +---------- +(1) Production as shown in the table is net to the Company and is determined by multiplying the gross production volume of properties in which the Company has an interest by the percentage of the leasehold or other property +interest owned by the Company. +(2) A ratio of energy content of natural gas and oil (six Mcf of natural gas equals one barrel of oil) was used to obtain a conversion factor to convert oil production into equivalent Mcfs of natural gas. +(3) The Company utilizes commodity-based derivative instruments as hedges to manage a portion of its exposure to price volatility of its natural gas sales. The effect of hedges on the average sales price of natural gas for the +years ended December 31, 2000, 1999 and 1998 was $(0.91), $(0.01) and $0.14, respectively. +(4) Production costs represent oil and gas operating expenses as reflected in the financial statements of the Company. +Well Operations +The Company currently operates approximately 1,538 wells in the Appalachian Basin, 209 wells in the Michigan Basin and 277 wells in the Rocky Mountain Region. The Company's ownership interest in these +wells ranges from 0% to 100%, and, on average, the Company has an approximate 52% ownership interest in the wells it operates. Currently these wells produce an aggregate of about 47,000 Mcfe of natural gas per day, including the Company's share of 19,500 +Mcfe per day. +The Company is paid a monthly operating charge for each well it operates for outside owners. The rate is competitive with rates charged by other operators in the area. The charge covers monthly operating +and accounting costs, insurance and other recurring costs. The Company may also receive additional compensation for special non-recurring activities, such as reworks and recompletions. +Transportation +Natural gas wells are connected by pipelines to natural gas markets. Over the years, the Company has developed extensive gathering systems in some of its areas of operations. The Company also continues to +construct new trunklines as necessary to provide for the marketing of natural gas being developed from new areas and to enhance or maintain its existing systems. +The Company is paid a transportation fee for natural gas that is moved by other producers through these pipeline systems. In many cases the Company has been able to receive higher natural gas prices as a result of its ability to move +natural gas to more attractive markets through this pipeline system, to the benefit of both the Company and its investor partners. +-6- +The Company had an Ohio subsidiary, Paramount Natural Gas Company ("PNG"), which commenced operations in October 1992 as a regulated Ohio distribution utility. In 2000, all of the assets of PNG were sold +and the Company ceased operations as an Ohio utility. +Item 2. Properties +Drilling Activity +The following table summarizes the Company's development drilling activity for the years ended December 31, 1996, 1997, 1998, 1999 and 2000. There is no correlation between the number of productive wells +completed during any period and the aggregate reserves attributable to those wells. The Company's exploratory wells drilled in the past five years consist of one dry hole (0.19 net) drilled in 1998 and five dry holes (2.44 net) drilled in 1999. +Development Wells Drilled +Total +Productive +Dry +Drilled +Net +Drilled +Net +Drilled +Net +1996 +97 +17.44 +92 +16.46 +5 +.98 +1997 +168 +40.72 +158 +38.00 +10 +2.72 +1998 +212 +56.99 +201 +54.22 +11 +2.77 +1999 +173 +54.64 +165 +53.10 +8 +1.54 +2000 +97 +27.39 +97 +27.39 +- +- +Total +747 +197.18 +713 +189.17 +34 +8.01 +Summary of Productive Wells +The table below shows the number of the Company's productive gross and net wells at December 31, 2000. +WELLS +Gas +Oil +Location +Gross +Net +Gross +Net +Colorado +277 +228.02 +- +- +Michigan +206 +110.20 +3 +1.42 +Ohio +16 +7.35 +5 +2.34 +Pennsylvania +539 +162.89 +- +- +Tennessee +1 +0.71 +39 +15.87 +West Virginia +932 +520.20 +6 +2.58 +Total +1,971 +1,029.37 +53 +22.21 +Reserves +All of the Company's oil and natural gas reserves are located in the United States. The Company's approximate net proved reserves were estimated by Wright & Company, Inc. independent petroleum +engineers ("Wright & Company"), to be 118,640,000 MCf of natural gas and 2,166,000 Bbls of oil at December 31, 2000, 101,245,000 Mcf of natural gas and 1,154,000 Bbls of oil at December 31, 1999, and 80,819,000 Mcf of natural gas and 29,000 Bbls of +oil at December 31, 1998. +The Company's approximate net proved developed reserves were estimated, by Wright & Company to be 92,131,000 Mcf of natural gas and 1,527,000 Bbls of oil at December 31, 2000, 82,628,000 Mcf of natural +gas and 798,000 Bbls of oil at December 31, 1999, and 64,562,000 Mcf of natural gas and 29,000 Bbls of oil at December 31, 1998. +-7- +The Company's reserves by region are as follows as of December 31, 2000: +Oil +(Mbbl) +Gas +(Mmcf) +MCFE +(Mmcfe) +% +Developed Reserves +Appalachian +60 +46,888 +47,248 +46.65% +Michigan +54 +30,777 +31,101 +30.70% +Rocky Mountains +1,413 +14,466 +22,944 +22.65% +Total Developed Reserves +1,527 +92,131 +101,293 +100.00% +Proved Undeveloped +Appalachian +0 +0 +0 +0.00% +Michigan +240 +8,292 +9,732 +32.08% +Rocky Mountains +399 +18,217 +20,611 +67.92% +Total Proved Undeveloped +639 +26,509 +30,343 +100.00% +Total Reserves +Appalachian +60 +46,888 +47,248 +35.89% +Michigan +294 +39,069 +40,833 +31.02% +Rocky Mountains +1,812 +32,683 +43,555 +33.09% +Total Reserves +2,166 +118,640 +131,636 +100.00% +No major discovery or other favorable or adverse event that would cause a significant change in estimated reserves is believed by the Company to have occurred since December 31, +2000. Reserves cannot be measured exactly, as reserve estimates involve subjective judgment. The estimates must be reviewed periodically and adjusted to reflect additional information gained from reservoir performance, new geological and geophysical data +and economic changes. +The standardized measure of discounted future net cash flows attributable to the Company's proved oil and gas reserves, giving effect to future estimated income tax expenses, was estimated by Wright & +Company in 2000, 1999 and 1998 to be $104.6 million as of December 31, 2000, $58.5 million as of December 31, 1999 and $30.2 million as of December 31, 1998. These amounts are based on year-end prices, adjusted for hedging contracts at the respective +dates. The values expressed are estimates only, and may not reflect realizable values or fair market values of the natural gas and oil ultimately extracted and recovered. The standardized measure of discounted future net cash flows may not accurately +reflect proceeds of production to be received in the future from the sale of natural gas and oil currently owned and does not necessarily reflect the actual costs that would be incurred to acquire equivalent natural gas and oil reserves. +-8- +Net Proved Natural Gas and Oil Reserves +The proved reserves of natural gas and oil of the Company as estimated by Wright & Company at December 31, 2000 are set forth below. These reserves have been prepared in compliance with the rules of +the Securities and Exchange Commission (the "SEC") based on year-end prices. An analysis of the change in estimated quantities of natural gas and oil reserves from January 1, 2000 to December 31, 2000, all of which are located within the United States, is +shown below: +Natural Gas (Mcf) +Oil (Bbls) +Proved developed and undeveloped reserves: +Beginning of year (January 1, 2000) +101,245,000 +1,154,000 +Revisions of previous estimates +(3,859,000 ) +10,000 +Beginning of year as revised +97,386,000 +1,164,000 +New discoveries and extensions +Michigan +14,191,000 +265,000 +Wattenberg field +5,681,000 +535,000 +Piceance basin +8,922,000 +- +Appalachian basin +266,000 +- +Dispositions to partnerships +(8,498,000) +(262,000) +Acquisitions +Michigan +- +- +Wattenberg field +5,761,000 +573,000 +Appalachian basin +668,000 +- +Production +(5,737,000 ) +(109,000 ) +End of period (December 31, 2000) +118,640,000 +2,166,000 +Proved developed reserves: +Beginning of year (January 1, 2000) +86,628,000 +1,154,000 +End of period (December 31, 2000) +92,131,000 +1,527,000 +Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Natural Gas and Oil Reserves +Summarized in the following table is information for the Company with respect to the standardized measure of discounted future net cash flows relating to proved natural gas and oil reserves. Future cash +inflows are computed by applying year-end prices of natural gas and oil relating to the Company's proved reserves to year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current +costs, assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the statutory rate in effect at December 31, 2000 to the future pretax net cash flows, less the tax basis of the properties, and gives effect +to permanent differences, tax credits and allowances related to the properties. +December 31, 2000 +Future estimated cash flows +$ 520,010,000 +Future estimated production costs +(144,505,000) +Future estimated development costs +(50,278,000) +Future estimated income tax expense +(80,982,000 ) +Future net cash flows +244,245,000 +10% annual discount for estimated timing of cash flows +(139,606,000 ) +Standardized measure of discounted +future estimated net cash flows +$ 104,639,000 +-9- +The following table summarizes the principal sources of change in the standardized measure of discounted future estimated net cash flows from January 1, 2000 through December 31, 2000: +Sales of oil and natural gas production, +net of production costs +$(14,816,000) +Net changes in prices and production costs +70,514,000 +Extensions, discoveries and improved recovery, +less related costs +73,636,000 +Dispositions to partnerships +(16,850,000) +Acquisitions +27,907,000 +Development costs incurred during the period +15,556,000 +Revisions of previous quantity estimates +(5,925,000) +Changes in estimated income taxes +(41,052,000) +Changes in discount +(59,731,000) +Changes in production rate (timing) and other +(3,054,000 ) +$ 46,185,000 +The foregoing data should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves, as the computations are based on a large +number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision, and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over +time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of +reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods and the limitations inherent therein. +Substantially all of the Company's natural gas and oil reserves have been mortgaged or pledged as security for the Company's credit agreement. See Note 3 of Notes to Consolidated Financial Statements. +Natural Gas Leases +The following table sets forth, as of December 31, 2000, the acres of developed and undeveloped oil and natural gas properties owned by the Company, listed alphabetically by state. +Developed +Areage +Undeveloped +Acreage +Colorado +11,100 +105,800 +Michigan +30,800 +11,000 +Ohio +740 +500 +Pennsylvania +8,900 +6,200 +Tennessee +5,400 +- +Utah +- +58,800 +West Virginia +48,600 +6,200 +Total +105,540 +188,500 +Title to Properties +The Company believes that it holds good and indefeasible title to its properties, in accordance with standards generally accepted in the natural gas industry, subject to such exceptions stated in the +opinion of counsel employed in the various areas in which the Company conducts its exploration activities, which exceptions, in the Company's judgment, do not detract substantially from the use of such property. As is customary in the natural gas +industry, only a perfunctory title examination is conducted at the time the properties believed to be suitable for drilling operations are acquired by the Company. Prior to the commencement of drilling operations, an extensive title examination is +conducted and curative work is performed with respect to defects which the Company deems to be significant. A title examination has been performed with respect to substantially all of the Company's producing properties. No single property owned by the +Company represents a material portion of the Company's holdings. The Company's properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens which the Company believes do not +materially interfere with the use of or affect the value of such properties. +-10- +The properties owned by the Company are subject to royalty, overriding royalty and other outstanding interests customary in the industry. The properties are also subject to burdens such as liens incident +to operating agreements, current taxes, development obligations under natural gas and oil leases, farm-out arrangements and other encumbrances, easements and restrictions. The Company does not believe that any of these burdens will materially interfere +with the use of the properties. +Natural Gas Sales +Natural gas is sold by the Company under contracts with terms ranging from one month to three years. Virtually all of the Company's contract pricing provisions are tied to a market index, with certain +adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other +available natural gas supplies. As a result, the Company's revenues from the sale of natural gas will suffer if market prices decline and benefit if they increase. The Company believes that the pricing provisions of its natural gas contracts are customary +in the industry. +The Company sells its natural gas to industrial end-users and utilities. One customer, Cinnabar Energy Services, accounted for 17.7% of the Company's revenues from oil and gas sales (11.3% of total +revenues) in 2000. No customer accounted for more than 10.0% of total revenues in 1999. One customer, Hope Gas, Inc., a regulated public utility ("Hope Gas"), accounted for 12.6% of the Company's revenues from oil and gas sales (5.4% of total revenues) in +1998. No other single purchaser of the Company's natural gas accounted for 10% or more of the Company's total revenues during 2000, 1999 or 1998. +At December 31, 2000, natural gas produced by the Company sold at prices per Mcf ranging from $0.90 to $7.73, depending upon well location, the date of the sales contract and whether the natural gas was +sold in interstate or intrastate commerce. The weighted net average price of natural gas sold by the Company during 2000 was $2.74 per Mcf. +In general, the Company, together with its marketing subsidiary, RNG, has been and expects to continue to be able to produce and sell natural gas from its wells without curtailment by providing natural gas +to purchasers at competitive prices. Open access transportation on the country's interstate pipeline system has greatly increased the range of potential markets. Whenever feasible the Company allows for multiple market possibilities from each of its +gathering systems, while seeking the best available market for its natural gas at any point in time. +Natural Gas Marketing +The Company's natural gas marketing activities involve the aggregation and reselling of natural gas produced by the Company and others. The Company believes that in a deregulated market, successful natural +gas marketing is essential to profitable operations. A variety of factors affect the market for natural gas, including the availability of other domestic production, natural gas imports, the availability and price of alterative fuels, the proximity and +capacity of natural gas pipelines, general fluctuations in the supply and demand for natural gas and the effects of state and federal regulations on natural gas production and sales. The natural gas industry also competes with other industries in +supplying the energy and fuel requirements of industrial, commercial and individual customers. +In 1996, the Company acquired RNG, an Appalachian Basin natural gas marketing company that specializes in the acquisition and aggregation of Appalachian Basin gas production. The owner/manager and +employees of RNG joined the Company, and RNG's operations were relocated to the Company's headquarters. RNG markets natural gas produced by the Company and also purchases natural gas from other producers and resells to utilities, end users or other +marketers. The employees of RNG have extensive knowledge of the natural gas market in the Company's areas of operations. Such knowledge assists the Company in maximizing its prices as it markets natural gas from Company-operated wells. RNG and its +management also brought to the Company specific knowledge and relationships with many producers in the Appalachian Basin region. +-11- +In West Virginia, Pennsylvania, Michigan and Colorado, the Company markets natural gas from its own wells and wells operated for its investment partnerships. The gas is marketed to natural gas utilities, +pipelines and industrial and commercial customers, either directly through the Company's gathering system, or utilizing transportation services provided by regulated interstate pipeline companies. +Hedging Activities +The Company utilizes commodity-based derivative instruments as hedges to manage a portion of its exposure to price volatility stemming from its natural gas sales and marketing activities. These instruments +consist of NYMEX-traded natural gas futures and option contracts. The contracts hedge committed and anticipated natural gas purchases and sales, generally forecasted to occur within a three to twelve-month period. Company policy prohibits the use of +natural gas futures or options for speculative purposes and permits utilization of hedges only if there is an underlying physical position. +The Company has extensive experience with the use of financial hedges to reduce the risk and impact of natural gas price changes. These hedges are used to coordinate fixed and variable priced purchases and +sales and to "lock in" fixed prices from time to time for the Company's share of production. In order for future contracts to serve as effective hedges, there must be sufficient correlation to the underlying hedged transaction. While hedging can help +provide price protection if spot prices drop, hedges can also limit upside potential. +Despite the measures taken by the Company to attempt to control price risk, the Company remains subject to price fluctuations for natural gas sold in the spot market. The Company continues to evaluate the +potential for reducing these risks by entering into hedge transactions. In addition, the Company may also close out any portion of hedges that may exist from time to time. +In late 1999 and the first several months of 2000, the Company established hedges on most of its 2000 production. As a result, the Company realized limited benefit from the rapid increase in natural gas prices during 2000. +Financing of Drilling Activities +The Company conducts development drilling activities for its own account and for other investors. In 1984, the Company began sponsoring private drilling limited partnerships, and, in 1989, the Company +began to register the partnership interests offered under public drilling programs with the SEC. The Company's public partnerships had $55.6 million in subscriptions in 2000, $36.1 million in 1999 and $40.9 million in 1998. The Company generally invests, +as its equity contribution to each drilling partnership, an additional sum approximating 20% of the aggregate subscriptions received for that particular drilling partnership. As a result, the Company is subject to substantial cash commitments at the +closing of each drilling partnership. The funds received from these programs are restricted to use in future drilling operations. While funds were received by the Company pursuant to drilling contracts in the years indicated, the Company recognizes +revenues from drilling operations on the percentage of completion method as the wells are drilled, rather than when funds are received. Most of the Company's drilling and development funds now are received from partnerships in which the Company serves as +managing general partner. However, because wells produce for a number of years, the Company continues to serve as operator for a large number of unaffiliated parties. In addition to the partnership structure, the Company also utilizes joint venture +arrangements for financing drilling activities. +The financing process begins when the Company enters into a development agreement with an investor partner, pursuant to which the Company agrees to assign its rights in the property to be drilled to the +partnership or other entity. The partnership or other entity thereby becomes owner of a working interest in the property. +-12- +The Company's development contracts with its investor partners have historically taken many different forms. Generally the agreements can be classified as on a "footage-based" rate, whereby the Company +receives drilling and completion payments based on the depth of the well; "cost-plus," in which the Company is reimbursed for its actual cost of drilling plus some additional amount for overhead and profit; or "turnkey," in which a specified amount is +paid for drilling and another amount for completion. As part of the compensation for its services, the Company also has received some interest in the production from the well in the form of an overriding royalty interest, working interest or other +proportionate share of revenue or profits. The Company's development contracts may provide for a combination of several of the foregoing payment options. Basic drilling and completion operations are performed on a footage-based rate, with leases and +gathering pipelines being contributed at Company cost. The Company may also purchase a working interest in the subject properties. +The level of the Company's drilling and development activity is dependent upon the amount of subscriptions in its public drilling partnerships and investments from other partnerships or other joint venture +partners. The use of partnerships and similar financing structures enables the Company to diversify its holdings, thereby reducing the risks of its development investments. Additionally, the Company benefits through such arrangements by its receipt of +fees for its management services and/or through an increased share in the revenues produced by the developed properties. The Company believes that investments in drilling activities, whether through Company-sponsored partnerships or other sources, are +influenced in part by the favorable treatment that such investments enjoy under the federal income tax laws. No assurance can be given that the Company will continue to have access to funds generated through these financing vehicles. +Oil Production +The Company's acquisition in December 1999 of 53 wells and in April 2000 of 108 wells in the Wattenberg field in Colorado and ongoing development activities in Colorado and Michigan are resulting in +significant increase in oil production and reserves. At the end of 2000 oil was about 10% of the Company's total equivalent reserves. Oil production in 2000 was 109,00 barrels, up from 8,000 barrels in 1999. +The Company is currently able to sell all the oil that it can produce under existing sales contracts with petroleum refiners and marketers. The Company does not refine any of its oil production. The Company's crude oil production is +sold to purchasers at or near the Company's wells under short-term purchase contracts at prices and in accordance with arrangements which are customary in the oil industry. No single purchaser of the Company's crude oil accounted for 10% or more of the +Company's revenues from oil and gas sales in 2000, 1999 or 1998. At December 31, 2000, oil produced by the Company sold at prices ranging from $23.25 to $33.43 per barrel, depending upon the location and quality of oil. In 2000, the weighted net average +price per barrel of oil sold by the Company was $29.99. +Oil production is subject to many of the same operating hazards and environmental concerns as natural gas production, but is also subject to the risk of oil spills. Federal regulations require certain +owners or operators of facilities that store or otherwise handle oil, such as the Company, to procure and implement spill prevention, control, counter-measures and response plans relating to the possible discharge of oil into surface waters. The Oil +Pollution Act of 1990 ("OPA") subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from oil spills. Noncompliance with OPA may result in varying civil and criminal +penalties and liabilities. Operations of the Company are also subject to the Federal Clean Water Act and analogous state laws relating to the control of water pollution, which laws provide varying civil and criminal penalties and liabilities for release +of petroleum or its derivatives into surface waters or into the ground. +-13- +Governmental Regulation +The Company's business and the natural gas industry in general are heavily regulated. The availability of a ready market for natural gas production depends on several factors beyond the Company's control. +These factors include regulation of natural gas production, federal and state regulations governing environmental quality and pollution control, the amount of natural gas available for sale, the availability of adequate pipeline and other transportation +and processing facilities and the marketing of competitive fuels. State and federal regulations generally are intended to prevent waste of natural gas, protect rights to produce natural gas between owners in a common reservoir and control contamination of +the environment. Pipelines are subject to the jurisdiction of various federal, state and local agencies. The Company takes the steps necessary to comply with applicable regulations both on its own behalf and as part of the services it provides to its +investor partnerships. The Company believes that it is in substantial compliance with such statutes, rules, regulations and governmental orders, although there can be no assurance that this is or will remain the case. The following discussion of the +regulation of the United States natural gas industry is not intended to constitute a complete discussion of the various statutes, rules, regulations and environmental orders to which the Company's operations may be subject. +Regulation of Oil and Natural Gas Exploration and Production +The Company's oil and natural gas operations are subject to various types of regulation at the federal, state and local levels. Prior to commencing drilling activities for a well, the Company must procure +permits and/or approvals for the various stages of the drilling process from the applicable state and local agencies in the state in which the area to be drilled is located. Such permits and approvals include those for the drilling of wells, and such +regulation includes maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties on which wells are drilled, the plugging +and abandoning of wells and the disposal of fluids used in connection with operations. The Company's operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or +proration units and the density of wells which may be drilled and the unitization or pooling of natural gas properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely +primarily or exclusively on voluntary pooling of lands and leases. In areas where pooling is voluntary, it may be more difficult to form units, and therefore, more difficult to develop a project if the operator owns less than 100% of the leasehold. In +addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these +regulations may limit the amount of oil and natural gas the Company can produce from its wells and may limit the number of wells or the locations at which the Company can drill. The regulatory burden on the oil and natural gas industry increases the +Company's costs of doing business and, consequently, affects its profitability. In as much as such laws and regulations are frequently expanded, amended and reinterpreted, the Company is unable to predict the future cost or impact of complying with such +regulations. +Regulation of Sales and Transportation of Natural Gas +Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 (the "NGPA") and +the regulations promulgated thereunder by FERC. Maximum selling prices of certain categories of natural gas sold in "first sales," whether sold in interstate or intrastate commerce, were regulated pursuant to the NGPA. The Natural Gas Wellhead Decontrol +Act (the "Decontrol Act") removed, as of January 1, 1993, all remaining federal price controls from natural gas sold in "first sales" on or after that date. FERC's jurisdiction over natural gas transportation was unaffected by the Decontrol Act. While +sales by producers of natural gas and all sales of crude oil, condensate and natural gas liquids can currently be made at market prices, Congress could reenact price controls in the future. +-14- +The Company's sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive regulation. In +recent years, FERC has undertaken various initiatives to increase competition within the natural gas industry. As a result of initiatives like FERC Order No.636, issued in April 1992, the interstate natural gas transportation and marketing system has been +substantially restructured to remove various barriers and practices that historically limited non-pipeline natural gas sellers, including producers, from effectively competing with interstate pipelines for sales to local distribution companies and large +industrial and commercial customers. The most significant provisions of Order No.636 require that interstate pipelines provide transportation separate or "unbundled" from their sales service, and require that pipelines provide firm and interruptible +transportation service on an open access basis that is equal for all natural gas suppliers. In many instances, the result of Order No.636 and related initiatives have been to substantially reduce or eliminate the interstate pipelines' traditional role as +wholesalers of natural gas in favor of providing only storage and transportation services. Another effect of regulatory restructuring is the greater transportation access available on interstate pipelines. In some cases, producers and marketers have +benefited from this availability. However, competition among suppliers has greatly increased and traditional long-term producer-pipeline contracts are rare. Furthermore, gathering facilities of interstate pipelines are no longer regulated by FERC, thus +allowing gatherers to charge higher gathering rates. +Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC, state commissions 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 FERC and Congress will continue. The Company cannot determine to what extent future operations and earnings of the Company will be affected +by new legislation, new regulations, or changes in existing regulation, at federal, state or local levels. +Environmental Regulations +The Company's operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Public interest in the +protection of the environment has increased dramatically in recent years. The trend of more expansive and stricter environmental legislation and regulations could continue. To the extent laws are enacted or other governmental action is taken that +restricts drilling or imposes environmental protection requirements that result in increased costs to the natural gas industry in general, the business and prospects of the Company could he adversely affected. +The Company generates wastes that may be subject to the Federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes. The U.S. Environmental Protection Agency ("EPA") and various +state agencies have limited the approved methods of disposal for certain hazardous and nonhazardous wastes. Furthermore, certain wastes generated by the Company's operations that are currently exempt from treatment as "hazardous wastes" may in the future +be designated as "hazardous wastes," and therefore be subject to more rigorous and costly operating and disposal requirements. +The Company currently owns or leases numerous properties that for many years have been used for the exploration and production of oil and natural gas. Although the Company believes that it has utilized +good operating and waste disposal practices, prior owners and operators of these properties may not have utilized similar practices, and hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by the +Company or on or under locations where such wastes have been taken for disposal. These properties and the wastes disposed thereon may be subject to the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), RCRA and analogous +state laws as well as state laws governing the management of oil and natural gas wastes. Under such laws, the Company 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) or to perform remedial plugging operations to prevent future contamination. +-15- +CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a +"hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed of or arranged for the disposal of the hazardous substances found at the site. +Persons who are or were responsible for release of 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, and 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. +The Company's operations may be subject to the Clean Air Act ("CAA") and comparable state and local requirements. Amendments to the CAA were adopted in 1990 and contain provisions that may result in the +gradual imposition of certain pollution control requirements with respect to air emissions from the operations of the Company. The EPA and states have been developing regulations to implement these requirements. The Company may be required to incur +certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues. +The Company's expenses relating to preserving the environment during 2000 were not significant in relation to operating costs and the Company expects no material change in 2001. Environmental regulations +have had no materially adverse effect on the Company's operations to date, but no assurance can be given that environmental regulations will not, in the future, result in a curtailment of production or otherwise have a materially adverse effect on the +Company's business, financial condition or results of operations. +As a matter of corporate policy and commitment, the Company attempts to minimize the adverse environmental impact of all its operations. For example, during 1999, the Company was one of the most active +drilling companies in the northeast. Even with this level of activity, the Company was able to maintain a high level of environmental sensitivity. During the 1990's, the Company was been a nine-time recipient of the West Virginia Department of +Environmental Protection's top award in recognition of the quality of the Company's environmental and reclamation work in its drilling activities. +Utility Regulation +PNG, which is an Ohio public utility, is subject to regulation by the Public Utilities Commission of Ohio (PUCO) in virtually all of its activities, including pricing and supply of services, addition of +and abandonment of service to customers, design and construction of facilities, and safety issues. All of the assets of PNG were sold during 2000 pursuant to approval by PUCO, and PNG ceased operations as an Ohio utility. +Operating Hazards and Insurance +The Company's exploration and production operations include a variety of operating risks, including the risk of fire, explosions, blowouts, craterings, pipe failure, casing collapse, abnormally pressured +formations, and environmental hazards such as gas leaks, ruptures and discharges of toxic gas, the occurrence of any of which could result in substantial losses to the Company due to injury and loss of life, severe damage to and destruction of property, +natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. The Company's pipeline, gathering and distribution operations are subject to the +many hazards inherent in the natural gas industry. These hazards include damage to wells, pipelines and other related equipment, and surrounding properties caused by hurricanes, floods, fires and other acts of God, inadvertent damage from construction +equipment, leakage of natural gas and other hydrocarbons, fires and explosions and other hazards that could also result in personal injury and loss of life, pollution and suspension of operations. +Any significant problems related to its facilities could adversely affect the Company's ability to conduct its operations. In accordance with customary industry practice, the Company maintains insurance +against some, but not all, potential risks; however, there can be no assurance that such insurance will be adequate to cover any losses or exposure for liability. The occurrence of a significant event not fully insured against could materially adversely +affect the Company's operations and financial condition. The Company cannot predict whether insurance will continue to be available at premium levels that justify its purchase or whether insurance will be available at all. +-16- +Competition +The Company believes that its exploration, drilling and production capabilities and the experience of its management generally enable it to compete effectively. The Company encounters competition from +numerous other oil and natural gas companies, drilling and income programs and partnerships in all areas of its operations, including drilling and marketing natural gas and obtaining desirable natural gas leases. Many of these competitors possess larger +staffs and greater financial resources than the Company, which may enable them to identify and acquire desirable producing properties and drilling prospects more economically. The Company's ability to explore for oil and natural gas prospects and to +acquire additional properties in the future depends upon its ability to conduct its operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. The Company competes with a number of other +companies which offer interests in drilling partnerships with a wide range of investment objectives and program structures. Competition for investment capital for both public and private drilling programs is intense. The Company also faces intense +competition in the marketing of natural gas from competitors including other producers as well as marketing companies. Also, international developments and the possible improved economics of domestic natural gas exploration may influence other companies +to increase their domestic oil and natural gas exploration. Furthermore, competition among companies for favorable prospects can be expected to continue, and it is anticipated that the cost of acquiring properties may increase in the future. Factors +affecting competition in the natural gas industry include price, location, availability, quality and volume of natural gas. The Company believes that it can compete effectively in the oil and natural gas industry on each of the foregoing factors. +Nevertheless, the Company's business, financial condition or results of operations could be materially adversely affected by competition. +Employees +As of December 31, 2000, the Company had 86 employees, including 15 in finance, 6 in administration, 14 in exploration and development, 46 in production and 5 in natural gas marketing. The Company's +engineers, supervisors and well tenders are generally responsible for the day-to-day operation of wells and pipeline systems. In addition, the Company retains subcontractors to perform drilling, fracturing, logging, and pipeline construction functions at +drilling sites. The Company's employees act as supervisors of the subcontractors. +The Company's employees are not covered by a collective bargaining agreement. The Company considers relations with its employees to be excellent. +Facilities +The Company owns and occupies three buildings in Bridgeport, West Virginia, two of which serve as the Company's headquarters and one which serves as a field operating site. The Company also owns a field +operating building in Gilmer County, West Virginia. The Company leases field operating offices in Colorado, Michigan and Pennsylvania under operating leases. The Company believes that its current facilities are sufficient for its current and anticipated +operations. +Item 3. Legal Proceedings +From time to time the Company is a party to various legal proceedings in the ordinary course of business. The Company is not currently a party to any litigation that it believes would materially affect +the Company's business, financial condition or results of operations. +Item 4. Submission of Matters to a Vote of Security Holders +No matters were submitted to a vote of security holders during the fourth quarter of the fiscal year covered by this report. +-17- +PART II +Item 5. Market for the Company's Common Stock and Related Security Holder Matters +The common stock of the Company is traded in the over-the-counter market under the symbol PETD. The following table sets forth, for the periods indicated, the high and low bid quotations per share of +the Company's common stock in the over-the-counter market, as reported by the National Quotation Bureau Incorporated. These quotations represent inter-dealer prices without retail markups, markdowns, commissions or other adjustments and may not represent +actual transactions. +High +Low +2000 +First Quarter +4 29/64 +3-3/4 +Second Quarter +6 1/32 +3-7/8 +Third Quarter +7 1/8 +4 23/32 +Fourth Quarter +7 +5 3/16 +1999 +First Quarter +3 15/16 +2 7/8 +Second Quarter +4 11/16 +3 5/16 +Third Quarter +5 3/8 +4 3/16 +Fourth Quarter +4 13/16 +3 23/32 +As of December 31, 2000, there were approximately 1,266 record holders of the Company's common stock. +The Company has not paid any dividends on its common stock and currently intends to retain earnings for use in its business. Therefore, it does not expect to declare cash dividends in the foreseeable +future. Further, the Company's Credit Agreement restricts the payment of dividends. +-18- +Item 6. Selected Financial Data (1) +Year Ended December 31, +2000 +1999 +1998 +1997 +1996 +Revenues +Oil and gas well +drilling operations +$43,194,700 +$42,115,600 +$40,447,100 +$34,405,400 +$18,698,200 +Oil and gas sales +90,419,700 +46,988,100 +35,560,300 +33,390,200 +26,051,100 +Well operations +Income +5,061,600 +5,314,500 +4,581,000 +4,509,300 +3,928,800 +Other income +2,540,500 +2,392,400 +2,385,200 +1,573,100 +935,600 +Total +$ 141,216,500 +$ 96,810,600 +$ 82,973,600 +$ 73,878,000 +$ 49,613,700 +Costs and Expenses +(excluding interest +and depreciation, +depletion and +amortization) +$ 118,813,300 +$ 82,496,500 +$ 71,094,900 +$ 61,219,600 +$ 42,274,100 +Interest Expense +$ 1,186,000 +$ 182,400 +$ - +$ 315,900 +$ 380,000 +Depreciation, +Depletion and +Amortization +$ 6,943,500 +$ 4,031,200 +$ 3,253,600 +$ 2,660,300 +$ 2,309,600 +Net Income +$ 10,681,000 +$ 7,824,300 +$ 6,658,000 +$ 7,586,800 +$ 3,549,400 +Basic earnings +per common share +$ .66 +$ .50 +$ .43 +$ .67 +$ .34 +Diluted earnings +per share +$ .65 +$ .48 +$ .41 +$ .67 +$ .34 +Average Common and +Common Equivalent +Shares Outstanding +During the Year +16,437,488 +16,286,852 +16,338,298 +12,540,165 +11,542,315 +December 31, +2000 +1999 +1998 +1997 +1996 +Total Assets +$ 187,684,500 +$ 132,083,600 +$ 111,409,000 +$ 98,411,600 +$ 63,604,200 +Working Capital +$ 780,700 +$ (2,503,900 ) +$ 1,633,400 +$ 16,483,200 +$ (2,357,200 ) +Long-Term Debt, +Excluding current +Maturities +$ 17,350,000 +$ 9,300,000 +$ - +$ - +$ 5,320,000 +Stockholders' Equity +$ 82,256,900 +$ 70,724,900 +$ 62,746,700 +$ 55,766,100 +$ 23,072,500 +(1) See Consolidated Financial Statements elsewhere herein. +-19- +Item 7. Management's Discussion and Analysis of Financial Condition and +Results of Operations +Safe Harbor Statement Under the Private Securities +Litigation Reform Act of 1995 +Statements, other than historical facts, contained in this Annual Report on Form 10-K, including statements of estimated oil and gas production and reserves, drilling plans, future cash flows, +anticipated capital expenditures and Management's strategies, plans and objectives, are "forward looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as +amended. Although the Company believes that its forward looking statements are based on reasonable assumptions, it cautions that such statements are subject to a wide range of risks and uncertainties incident to the exploration for, acquisition, +development and marketing of oil and gas, and it can give no assurance that its estimates and expectations will be realized. Important factors that could cause actual results to differ materially from the forward looking statements include, but are not +limited to, changes in production volumes, worldwide demand, and commodity prices for petroleum natural resources; the timing and extent of the Company's success in discovering, acquiring, developing and producing oil and gas reserves; risks incident to +the drilling and operation of oil and gas wells; future production and development costs; the effect of existing and future laws, governmental regulations and the political and economic climate of the United States; the effect of hedging activities; and +conditions in the capital markets. Other risk factors are discussed elsewhere in this Form 10-K. +Results of Operations +Year Ended December 31, 2000 Compared with December 31, 1999 +Revenues. Total revenues for the year ended December 31, 2000 were $141.2 million compared to $96.8 million for the year ended December 31, 1999, an increase of approximately $44.4 million, or 45.9%. +Drilling revenues for the year ended December 31, 2000 were $43.2 million compared to $42.1 for the year ended December 31, 1999, an increase of approximately $1.1 million, or 2.6%. Natural gas sales from the marketing activities of RNG for the year ended +December 31, 2000 were $71.4 million compared to $38.4 million for the year ended December 31, 1999, an increase of approximately $33.0 million or 85.9%. Such increase was due to increased volumes of gas sold with higher average sales prices. Oil and gas +sales from the Company's producing properties for the year ended December 31, 2000 were $19.0 million compared to $8.6 million for the year ended December 31, 1999, an increase of approximately $10.4 million or 120.9%. Such increase was due to increased +production which resulted from acquisitions of producing properties along with new wells drilled and higher average sales prices of natural gas and oil from the Company's producing properties. Financial results depend upon many factors, particularly the +price of natural gas and our ability to market our production on economically attractive terms. Price volatility in the natural gas market has remained prevalent in the last few years. From the third quarter of 1998 through the first quarter of 1999, we +experienced a decline in energy commodity prices. However, in the summer of 1999 and continuing into early 2000, prices improved. For the months of April through December, 2000, we had certain natural gas hedges in place that prevented us from realizing +the full impact of this price environment. Despite this limitation, our realized natural gas price for each month in the year 2000 was higher than the previous year. In the final months of 2000, the NYMEX futures market reported unprecedented natural gas +contract prices. During 2000, the hedging activities resulted in oil and gas sales being $5.2 million lower than if the Company had not hedged. Well operations and pipeline income for the year ended December 31, 2000 was $5.1 million compared to $5.3 +million for the year ended December 31, 1999, a decrease of approximately $200,000 or 3.8%. Other income for the year ended December 31, 2000 was $2.5 million compared to $2.4 million for the year ended December 31, 1999, an increase of approximately +$100,000 or 4.2%. +Costs and expenses. Costs and expenses for the year ended December 31, 2000 were $126.9 million compared to $86.7 million for the year ended December 31, 1999, an increase of approximately $40.2 million, +or 46.4%. Oil and gas well drilling operations costs for the year ended December 31, 2000 were $35.2 million compared to $35.5 million for the year ended December 31, 1999, a decrease of approximately $300,000 or 0.8%. +-20- +The costs of gas marketing activities for the year ended December 31, 2000 were $71.6 million compared to $38.5 million for the year ended December 31, 1999, an increase of $33.1 million or 86.0%. Such +increase was due to the increased gas marketing activity of RNG with increased volumes purchased at higher average sale prices. Based on the nature of the Company's gas marketing activities, hedging did not have a significant impact on the Company's net +margins from marketing activities during 2000. Oil and gas production costs from the Company's producing properties for the year ended December 31, 2000 were $8.3 million compared to $5.7 million for the year ended December 31, 1999 an increase of $2.6 +million or 45.6%. Such increase was due to the increased production volumes from the Company's producing properties. General and administrative expenses for the year ended December 31, 2000 were $3.6 million compared to $2.8 million for the year ended +December 31, 1999, an increase of approximately $800,000. Depreciation, depletion and amortization costs for the year ended December 31, 2000 were $6.9 million compared to $4.0 million for the year ended December 31, 1999, an increase of approximately +$2.9 million or 72.5%. Such increase was due to the increased amount of investment in oil and gas properties owned by the Company. Interest costs for the year ended December 31, 2000 were $1.2 compared to $200,000 for the year ended December 31, 1999 an +increase of approximately $1.0 million. The increase was due to the Company utilizing its credit agreement to purchase oil and gas properties. +Net income. Net income for the year ended December 31, 2000 was $10.7 million compared to $7.8 million for the year ended December 31, 1999, an increase of approximately $2.9 million or 37.2%. +Year Ended December 31, 1999 Compared with December 31, 1998 +Revenues. Total revenues for the year ended December 31, 1999 were $96.8 million compared to $83.0 million for the year ended December 31, 1998, an increase of approximately $13.8 million, or 16.6%. +Drilling revenues for the year ended December 31, 1999 were $42.1 million compared to $40.4 for the year ended December 31, 1998, an increase of approximately $1.7 million, or 4.2%. Such increase was due to an increase in drilling and completion +activities, which was a direct result of an increase in drilling funds from the Company's public drilling programs. Natural gas sales from the marketing activities of RNG for the year ended December 31, 1999 were $38.4 million compared to $29.2 million +for the year ended December 31, 1998, an increase of approximately $9.2 million or 31.5% Oil and gas sales from the Company's producing properties for the year ended December 31, 1999 were $8.6 million compared to $6.3 million for the year ended December +31, 1998, an increase of approximately $2.3 million or 36.5%. Such increase was due to increased production of natural gas and oil from the Company's producing properties which resulted from acquisitions of producing properties along with new wells +drilled. Well operations and pipeline income for the year ended December 31, 1999 was $5.3 million compared to $4.6 million for the year ended December 31, 1998, an increase of approximately $700,000 or 15.2%. Such increase resulted from an increase in +the number of wells operated by the Company. Other income remained constant at $2.4 million for the years ended December 31, 1999 and 1998. However for the year ended December 31, 1999 a gain on the sale of oil and gas property offset the decrease in +interest earned in 1999 compared to 1998 due to lower average cash balances. +Costs and expenses. Costs and expenses for the year ended December 31, 1999 were $86.7 million compared to $74.3 million for the year ended December 31, 1998, an increase of approximately $12.4 million, or +16.7%. Oil and gas well drilling operations costs for the year ended December 31, 1999 were $35.5 million compared to $35.0 million for the year ended December 31, 1998, an increase of approximately $500,000 or 1.4%. The cost of gas marketing activities +for the year ended December 31, 1999 were $38.5 million compared to $29.3 million for the year ended December 31, 1998, an increase of $9.2 million or 31.4%. Such increase was due to the increased gas marketing activity of RNG. Oil and gas production +costs from the Company's producing properties for the year ended December 31, 1999 were $5.7 million compared to $4.2 million for the year ended December 31, 1998, an increase of 1.5 million or 35.7%. Such increase was due to the increased production +volumes from the Company's producing properties. General and administrative expenses for the year ended December 31, 1999 were $2.8 million compared to $2.5 million for the year ended December 31, 1998, an increase of approximately $300,000. Depreciation, +depletion and amortization costs for the year ended December 31, 1999 were $4.0 million compared to $3.3 million for the year ended December 31, 1998, an increase of approximately $700,000 or 21.2%. Such increase was due to the increased amount of +investment in oil and gas properties owned by the Company. Interest costs were $182,000 for the year ended December 31, 1999 as the Company utilized its credit agreement during the third and fourth quarters of 1999. +-21- +Net income. Net income for the year ended December 31, 1999 was $7.8 million compared to $6.7 million for the year ended December 31, 1998, an increase of approximately $1.1 million or 16.4%. +Liquidity and Capital Resources +The Company funds its operations through a combination of cash flow from operations, capital raised through stock offerings and drilling partnerships, and use of the Company's credit facility. Operational +cash flow is generated by sales of natural gas from the Company's well interests, well drilling and operating activities for the Company's investor partners, natural gas gathering and transportation, and natural gas marketing. Cash payments from +Company-sponsored partnerships are used to drill and complete wells for the partnerships, with operating cash flow accruing to the Company to the extent payments exceed drilling costs. The Company utilizes its revolving credit arrangement to meet the cash +flow requirements of its operating and investment activities. +Sales volumes of natural gas have continued to increase while natural gas prices fluctuate monthly. The Company's natural gas sales prices are subject to increase and decrease based on various +market-sensitive indices. A major factor in the variability of these indices is the seasonal variation of demand for the natural gas, which typically peaks during the winter months. The volumes of natural gas sales are expected to continue to increase as +a result of continued drilling activities and additional investment by the Company in oil and gas properties. The Company utilizes commodity-based derivative instruments (natural gas futures and option contracts traded on the NYMEX) as hedges to manage a +portion of its exposure to this price volatility. The futures contracts hedge committed and anticipated natural gas purchases and sales, generally forecasted to occur within a three to twelve-month period. +The Company has a bank credit agreement with Bank One, formerly First National Bank of Chicago, which provides a borrowing base of $30.0 million, subject to adequate oil and natural gas reserves. As of +December 31, 2000, the balance outstanding on the line of credit is $17.35 million. Interest accrues at prime, with LIBOR (London Interbank Market Rate) alternatives available at the discretion of the Company. No principal payments are required until the +credit agreement expires on December 31, 2004. +The Company closed four public drilling partnerships during 2000. The total amount received during 2000 was $55.6 million compared to $36.1 million for 1999. The Company closed its fourth program of 2000 +on December 27, 2000 in the amount of $25.0 million and will drill the wells during the first quarter 2001. The Company generally invests, as its equity contribution to each drilling partnership, an additional sum approximating 20% of the aggregate +subscriptions received for that particular drilling partnership. As a result, the Company is subject to substantial cash commitments at the closing of each drilling partnership. The funds received from these programs are restricted to use in future +drilling operations. No assurance can be made that the Company will continue to receive this level of funding from these or future programs. +On January 29, 1999, the Company offered to purchase from Investors their units of investment in the Company's Drilling Programs formed prior to 1996. The Company purchased approximately $1.8 million of +limited partnership interest in producing oil and gas properties in conjunction with this offer, which expired on March 31, 1999. The Company utilized capital received from its 1997 public stock offering to fund this purchase. +On December 15, 1999, the Company purchased all of the working interest in 53 producing wells in the D-J Basin of Colorado. The Company estimates that the purchase includes proved developed reserves of +approximately 3.6 Bcf of natural gas and 370,000 barrels of oil or approximately 5.8 Bcf equivalent (Bcfe), along with 3.0 Bcfe of proved undeveloped reserves attributable to these locations. The total acquisition cost for the wells and locations was $5.2 +million. The Company utilized part of its existing line of credit to fund the transaction. The effective date of the transaction was December 1, 1999. +On June 6, 2000 the Company purchased all of the working interest in 168 producing wells in Colorado for $5,650,000. The transaction was effective April 1, 2000. The wells have net remaining reserves of +560,000 barrels of oil and 4.9 billion cubic feet of natural gas. The Company utilized its bank credit agreement to finance this purchase. +-22- +The Company continues to pursue capital investment opportunities in producing natural gas properties as well as its plan to participate in its sponsored natural gas drilling partnerships, while pursuing +opportunities for operating improvements and costs efficiencies. Management believes that the Company has adequate capital to meet its operating requirements. +New Accounting Standards +Statement of Accounting Standards No. 133 and No. 138, Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133/138), was issued by the Financial Accounting Standards Board. SFAS +No. 133/138 standardized the accounting for derivative instruments, including certain derivative instruments embedded in other contracts. The Company is required to adopt the provisions of SFAS 133/138 effective January 1, 2001. On adoption, the +provisions of SFAS No. 133/138 must be applied prospectively. The natural gas futures and options and the interest rate swap agreement discussed in note 12 are derivatives pursuant to SFAS 133/138. The Company's derivatives will be treated as hedges of +committed and/or anticipated transactions and have a total estimated fair value of $(20,131,800) on December 31, 2000. On January 1, 2001, the Company will record this estimated fair value as a liability with a corresponding adjustment to accumulated +other comprehensive income (AOCI). The adjustment to AOCI will be recorded net of the related tax effects. +Item 7.a. Quantitative and Qualitative Disclosure About Market Risk . +Market-Sensitive Instruments and Risk Management +The Company's primary market risk exposures are interest rate risk and commodity price risk. These exposures are discussed in detail below: +Interest Rate Risk +The Company's exposure to market risk for changes in interest rates relates primarily to the Company's interest-bearing cash and cash equivalents and long-term debt. Interest-bearing cash and cash +equivalents includes money market funds, certificates of deposit and checking and savings accounts with various banks. The amount of interest-bearing cash and cash equivalents as of December 31, 2000 is $46,872,000 with an average interest rate of 5.24 +percent. As of December 31, 2000, the Company has long-term debt of $17,350,000 of which $10,000,000 is subject to an interest rate swap at a rate of 8.39%, $5,000,000 at a LIBOR rate of 8.52% and $2,350,000 was subject to a prime rate of 9.50%. +Commodity Price Risk +The Company utilizes commodity-based derivative instruments as hedges to manage a portion of its exposure to price risk from its natural gas sales and marketing activities. These instruments consist of +NYMEX-traded natural gas futures contracts and option contracts. These hedging arrangements have the effect of locking in for specified periods (at predetermined prices or ranges of prices) the prices the Company will receive for the volume to which the +hedge relates. As a result, while these hedging arrangements are structured to reduce the Company's exposure to decreases in price associated with the hedging commodity, they also limit the benefit the Company might otherwise have received from price +increases associated with the hedged commodity. The Company's policy prohibits the use of natural gas future and option contracts for speculative purposes. As of December 31, 2000, PDC had entered into a series of natural gas future contracts and options +contracts. Open future contracts maturing in 2001 are for the sale of 4,923,320 dt of natural gas with a weighted average price of $4.07 dt resulting in a total contract amount of $20,134,300, and a fair market value of $(19,340,400). Open option +contracts maturing in 2001 are for the sale of 2,276,400 dt with a weighted average floor price of $3.68 dt and a fair value of $(757,600). As of December 31, 1999, PDC had entered into a series of natural gas future contracts. Open future contracts +maturing in 2000 were for the sale of 1,820,000 dt of natural gas with a weighted average price of $2.3725 dt resulting in a total contract amount of $4,317,950, and a fair market value of $350,500. The average NYMEX closing price for natural gas for the +years 2000, 1999, and 1998 was $3.88 dt, $2.27 dt and $2.11 dt. The average NYMEX closing price for oil for the years 2000, 1999, and 1998 was $30.95 bbl, $18.06 bbl and $14.64 bbl. Future near-term gas prices will be affected by various supply and demand +factors such as weather, government and environmental regulation and new drilling activities within the industry. +-23- +Disclosure of Limitations +As the information above incorporates only those exposures that exist at December 31, 2000, it does not consider those exposures or positions which could arise after that date. As a result, the Company's +ultimate realized gain or loss with respect to interest rate and commodity price fluctuations will depend on the exposures that arise during the period, the Company's hedging strategies at the time, and interest rates and commodity prices at the time. +PART III +Item 8. Financial Statements and Supplementary Data: +The response to this Item is set forth herein in a separate section of this Report, beginning on Page F-1. +Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. +None. +Item 10. Directors and Executive Officers of the Company +Directors and Executive Officers of the Company +The executive officers and directors of the Company, their principal occupations for the past five years and additional information are set forth below: +Name +Age +Positions and Offices Held +Held Current +Position Since +James N. Ryan +69 +Chairman, Chief Executive Officer +and Director +November 1983 +Steven R. Williams +49 +President and Director +March 1983 +Dale G. Rettinger +56 +Chief Financial Officer, Executive +Vice President, Treasurer and +Director +July 1980 +Roger J. Morgan +73 +Secretary and Director +November 1969 +Vincent F. D'Annunzio +48 +Director +February 1989 +Jeffrey C. Swoveland +45 +Director +March 1991 +Donald B. Nestor +52 +Director +March 2000 +James N. Ryan has served as President and Director of PDC from 1969 to 1983 and was elected Chairman and Chief Executive Officer in March 1983 +Steven R. Williams has served as President and Director of PDC since March 1983. Prior to joining PDC, Mr. Williams was employed by Exxon until 1979 and attended Stanford Graduate School of Business, graduating in 1981. He then worked +with Texas Oil and Gas until July 1982, when he joined Exco Enterprises, an oil and gas investment company as manager of operations. +Dale G. Rettinger has served as Vice President and Treasurer of PDC since July 1980, and was appointed Chief Financial Officer in September 1997. Mr. Rettinger was elected Director in 1985. Previously Mr. Rettinger was a partner with +Main Hurdman, Certified Public Accountants, having served in that capactiy since 1976. +Roger J. Morgan has been a member of the law firm of Young, Morgan & Cann, Clarksburg, West Virginia since 1955. Mr. Morgan is not active in the day-to-day business of PDC, but his law firm provides legal services to PDC. +Vincent F. D'Annunzio has served as president of Beverage Distributors, Inc. located in Clarksburg, West Virginia since 1985. +Jeffrey C. Swoveland has served as Chief Financial Officer of Body Media since September, 2000. Prior thereto, Mr. Swoveland was Vice President-Finance and Treasurer of Equitable Resources Inc since 1994. +-24- +Donald B. Nestor, elected as a director in March, 2000, is a Certified Public Accountant and a Partner in the CPA firm of Toothman Rice, P.L.L.C. and is in charge of the firm's Buckhannon, West Virginia office. Mr. Nestor has served in +that capacity since 1975. +The Company's By-Laws provide that the directors of the Company shall be divided into three classes and that, at each annual meeting of stockholders of the Company, successors to the class of directors whose term expires at the annual +meeting will be elected for a three-year term. The classes are staggered so that the term of one class expires each year. Mr. Ryan and Mr. D'Annunzio are members of the class whose term expires in 2001; and Mr. Rettinger and Mr. Swoveland are members of +the class whose term expires in 2002; and Mr Williams, Mr. Morgan and Mr. Nestor are members of the class whose term expires in 2003. There is no family relationship between any director or executive officer and any other director or executive officer of +the Company. There are no arrangements or understandings between any director or officer and any other person pursuant to which such person was selected as an officer. +Item 11. Management Remuneration and Transactions +There is incorporated by reference herein in response to this Item the material under the heading "Election of Directors - Remuneration of Directors and Officers", "Election of Directors - Stock +Options" and "Election of Directors - Interest of Management in Certain Transactions" in the Company's definitive proxy statement for its 2001 annual meeting of stockholders filed or to be filed with the Commission on or before April 30, 2001. +Item 12. Security Ownership of Certain Beneficial Owners and Management +There is incorporated by reference herein in response to this Item, the material under the heading "Election of Directors", in the Company's definitive proxy statement for its 2001 annual meeting of +stockholders filed or to be filed with the Commission on or before April 30, 2001. +Item 13. Certain Relationships and Related Transactions +The response to this item is set forth herein in Note 8 in the Notes to Consolidated Financial Statements. +PART IV +Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K +(a) (1) Financial Statements: +See Index to Financial Statements and Schedules on page F-1. +(2) Financial Statement Schedules: +See Index to Financial Statements and Schedules on page F-1. +Schedules and Financial Statements Omitted +All other financial statement schedules are omitted because they are not required, inapplicable, or the information is included in the Financial +Statements or Notes thereto. +(3) Exhibits: +See Exhibits Index on page E-1. +-25- +CONFORMED COPY +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 +. +PETROLEUM DEVELOPMENT CORPORATION +By /s/ James N. Ryan +James N. Ryan, Chairman +March 23, 2001 +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/ James N. Ryan +James N. Ryan +Chairman, Chief Executive +Officer and Director +March 23, 2001 +/s/ Steven R. Williams +Steven R. Williams +President and Director +March 23, 2001 +/s/ Dale G. Rettinger +Dale G. Rettinger +Chief Financial Officer +Executive Vice +President,Treasurer and +Director (principal financial +and accounting officer +March 23, 2001 +/s/ Roger J. Morgan +Roger J. Morgan +Secretary and Director +March 23, 2001 +-26- +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Index to Financial Statements and Financial Statement Schedules +1. +Financial Statements: +Independent Auditors' Report +F-2 +Consolidated Balance Sheets - December 31, 2000 and 1999 +F-3 & 4 +Consolidated Statements of Income - +Years Ended December 31, 2000, 1999 and 1998 +F-5 +Consolidated Statements of Stockholders' Equity - +Years Ended December 31, 2000, 1999 and 1998 +F-6 +Consolidated Statements of Cash Flows - +Years Ended December 31, 2000, 1999 and 1998 +F-7 +Notes to Consolidated Financial Statements +F-8 -22 +2. +Financial Statement Schedule: +Schedule II - Valuation and Qualifying Accounts and Reserves +F-23 +F-1 +Independent Auditors' Report +The Stockholders and Board of Directors +Petroleum Development Corporation: +We have audited the consolidated financial statements of Petroleum Development Corporation and subsidiaries as listed in the accompanying index. In connection with our audits of the consolidated financial statements, we also have +audited the financial statement schedule as listed in the accompanying index. These consolidated financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these +consolidated financial statements and financial statement schedule based on our audits. +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, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Petroleum Development Corporation and subsidiaries as of December 31, 2000 and 1999, and the +results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the related +financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. +KPMG LLP +Pittsburgh, Pennsylvania +March 8, 2001 +F-2 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Consolidated Balance Sheets +December 31, 2000 and 1999 +2000 +1999 +Assets +Current assets: +Cash and cash equivalents +$ 43,933,700 +28,444,900 +Restricted cash +2,938,300 +614,300 +Notes and accounts receivable +23,648,000 +10,263,200 +Inventories +1,097,900 +577,600 +Prepaid expenses +7,134,800 +2,360,100 +Total current assets +78,752,700 +42,260,100 +Properties and equipment: +Oil and gas properties (successful +efforts accounting method) +131,271,900 +105,837,900 +Pipelines +6,147,800 +8,643,400 +Transportation and other equipment +2,704,300 +2,686,800 +Land and buildings +1,174,600 +1,181,000 +141,298,600 +118,349,100 +Less accumulated depreciation, +depletion and amortization +35,344,700 +31,207,300 +105,953,900 +87,141,800 +Other assets +2,977,900 +2,681,700 +$ 187,684,500 +132,083,600 +(Continued) +F-3 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Consolidated Balance Sheets +December 31, 2000 and 1999 +2000 +1999 +Liabilities and Stockholders' Equity +Current liabilities: +Accounts payable +$ 27,742,600 +14,678,900 +Accrued taxes +- +276,400 +Other accrued expenses +3,979,900 +2,643,700 +Advances for future drilling contracts +43,809,400 +25,137,400 +Funds held for future distribution +2,440,100 +2,027,600 +Total current liabilities +77,972,000 +44,764,000 +Long-term debt +17,350,000 +9,300,000 +Other liabilities +4,396,800 +3,160,600 +Deferred income taxes +5,708,800 +4,134,100 +Commitments and contingencies +Stockholders' equity: +Common stock, par value $.01 per share; +authorized 50,000,000 shares; issued and +outstanding 16,244,044 and 15,737,795 shares +162,400 +157,400 +Additional paid-in capital +32,917,000 +32,071,000 +Retained earnings +49,177,500 +38,496,500 +Total stockholders' equity +82,256,900 +70,724,900 +$ 187,684,500 +132,083,600 +See accompanying notes to consolidated financial statements. +F-4 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Consolidated Statements of Income +Years Ended December 31, 2000, 1999 and 1998 +2000 +1999 +1998 +Revenues: +Oil and gas well drilling operations +$ 43,194,700 +42,115,600 +40,447,100 +Gas sales from marketing activities +71,402,400 +38,359,700 +29,244,900 +Oil and gas sales +19,017,300 +8,628,400 +6,315,400 +Well operations and pipeline income +5,061,600 +5,314,500 +4,581,000 +Other income +2,540,500 +2,392,400 +2,385,200 +141,216,500 +96,810,600 +82,973,600 +Costs and expenses: +Cost of oil and gas well +drilling operations +35,244,300 +35,507,300 +35,047,500 +Cost of gas marketing activities +71,648,500 +38,459,000 +29,350,200 +Oil and gas production costs +8,303,600 +5,729,200 +4,206,700 +General and administrative expenses +3,616,900 +2,801,000 +2,490,500 +Depreciation, depletion and amortization +6,943,500 +4,031,200 +3,253,600 +Interest +1,186,000 +182,400 +- +126,942,800 +86,710,100 +74,348,500 +Income before income taxes +14,273,700 +10,100,500 +8,625,100 +Income taxes +3,592,700 +2,276,200 +1,967,100 +Net income +$ 10,681,000 +7,824,300 +6,658,000 +Basic earnings per common share +$ .66 +.50 +.43 +Diluted earnings per common +and common equivalent share +$ .65 +.48 +.41 +See accompanying notes to consolidated financial statements. +F-5 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Consolidated Statements of Stockholders' Equity +Years Ended December 31, 2000, 1999 and 1998 +Common stock +Issued +Number +Of +Shares +Amount +Additional +Paid-in- +capital +Warrants +Out- +Standing +Retained +Earnings +Total +Balance December 31, 1997 +15,245,758 +$152,500 +31,553,100 +46,300 +24,014,200 +55,766,100 +Issuance of common stock: +Exercise of employee stock options +324,333 +3,200 +300,800 +- +- +304,000 +Amortization of stock award +- +- +12,200 +- +- +12,200 +Repurchase and cancellation of treasury stock +(59,329) +(600) +(303,400) +- +- +(304,000) +Income tax benefit from the exercise +of stock options +- +- +310,400 +- +- +310,400 +Net income +- +- +- +- +6,658,000 +6,658,000 +15,510,762 +$ 155,100 +31,873,100 +46,300 +30,672,200 +62,746,700 +Balance December 31, 1998 +Issuance of common stock: +Exercise of employee stock options +324,333 +3,200 +300,800 +- +- +304,000 +Amortization of stock award +- +- +12,200 +- +- +12,200 +Repurchase and cancellation of treasury stock +(97,300) +(900) +(303,100) +- +- +(304,000) +Income tax benefit from the exercise +of stock options +- +- +141,700 +- +- +141,700 +Warrants expired +- +- +46,300 +(46,300) +- +Net income +- +- +- +- +7,824,300 +7,824,300 +Balance December 31, 1999 +15,737,795 +$ 157,400 +32,071,000 +- +38,496,500 +70,724,900 +Issuance of common stock: +Exercise of employee stock options +511,584 +5,100 +511,700 +- +- +516,800 +Purchase of properties +100,000 +1,000 +549,000 +- +- +550,000 +Amortization of stock award +- +- +5,500 +- +- +5,500 +Repurchase and cancellation of treasury stock +(105,335) +(1,100) +(420,100) +- +- +(421,200) +Income tax benefit from the exercise +of stock options +- +- +199,900 +- +- +199,900 +Net income +- +- +- +- +10,681,000 +10,681,000 +Balance December 31, 2000 +16,244,044 +$ 162,400 +32,917,000 +- +49,177,500 +82,256,900 +See accompanying notes to consolidated financial statements. +F-6 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Consolidated Statements of Cash Flows +Years Ended December 31, 2000, 1999 and 1998 +2000 +1999 +1998 +Cash flows from operating activities: +Net income +$10,681,000 +7,824,300 +6,658,000 +Adjustment to net income to reconcile +to cash provided by operating activities: +Deferred income taxes +1,838,300 +108,900 +244,000 +Depreciation, depletion and amortization +6,943,500 +4,031,200 +3,253,600 +(Gain) loss from sale of assets +(199,200) +(501,800) +18,700 +Disposition of leasehold acreage +672,700 +618,100 +196,200 +Amortization of stock award +5,500 +12,200 +12,200 +Increase in notes and +accounts receivable +(13,384,800) +(4,239,100) +(1,100,700) +(Increase) decrease in inventories +(520,300) +124,800 +(404,500) +(Increase) decrease in prepaid expenses +(4,774,700) +312,600 +(600) +Increase in other assets +(375,700) +(750,900) +(911,200) +Increase in accounts payable +and accrued expenses +15,359,700 +5,347,300 +1,304,000 +Increase (decrease) in advances for +future drilling contracts +18,672,000 +(3,183,400) +5,029,200 +Increase (decrease) in funds held for +future distribution +412,500 +1,043,400 +(675,500 ) +Total adjustments +24,649,500 +2,923,300 +6,965,400 +Net cash provided by +operating activities +35,330,500 +10,747,600 +13,623,400 +Cash flows from investing activities: +Capital expenditures +(27,932,100) +(27,758,200) +(26,629,700) +Proceeds from sale of leases +1,588,700 +1,224,200 +1,283,600 +Proceeds from sale of fixed assets +680,100 +651,000 +56,300 +(Increase) decrease in restricted cash +(2,324,000 ) +(458,100 ) +769,900 +Net cash used in +investing activities +(27,987,300 ) +(26,341,100 ) +(24,519,900 ) +Cash flows from financing activities: +Proceeds from debt +8,050,000 +9,300,000 +- +Proceeds from issuance of stock +95,600 +- +- +Net cash provided by +financing activities +8,145,600 +9,300,000 +- +Net increase (decrease) in cash +and cash equivalents +15,488,800 +(6,293,500) +(10,896,500) +Cash and cash equivalents, +beginning of year +28,444,900 +34,738,400 +45,634,900 +Cash and cash equivalents, end of year +$ 43,933,700 +28,444,900 +34,738,400 +See accompanying notes to consolidated financial statements. +F-7 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +Years Ended December 31, 2000, 1999 and 1998 +(1) Summary of Significant Accounting Policies +Principles of Consolidation +The accompanying consolidated financial statements include the accounts of Petroleum Development Corporation and its wholly owned subsidiaries. All material intercompany accounts and transactions have been eliminated in +consolidation. The Company accounts for its investment in limited partnerships under the proportionate consolidation method. Under this method, the Company's financial statements include its prorata share of assets and liabilities and revenues and +expenses, respectively, of the limited partnerships in which it participates. +The Company is involved in three business segments. The segments are drilling and development, natural gas sales and well operations. (See Note 18) +The Company grants credit to purchasers of oil and gas and the owners of managed properties, substantially all of whom are located in West Virginia, Tennessee, Pennsylvania, Ohio, Michigan and Colorado. +Cash Equivalents +For purposes of the statement of cash flows, the Company considers all highly liquid debt instruments with original maturities of three months or less to be cash equivalents. +Inventories +Inventories of well equipment, parts and supplies are valued at the lower of average cost or market. An inventory of natural gas is recorded when gas is purchased in excess of deliveries to customers and is recorded at the lower of +cost or market. An inventory of oil located in stock tanks on well locations, is carried at market at the end of each period. +Oil and Gas Properties +Exploration and development costs are accounted for by the successful efforts method. +The Company assesses impairment of capitalized costs of proved oil and gas properties by comparing net capitalized costs to undiscounted future net cash flows on a field-by-field basis using expected prices. Prices utilized in each +year's calculation for measurement purposes and expected costs are held constant throughout the estimated life of the properties. If net capitalized costs exceed undiscounted future net cash flow, the measurement of impairment is based on estimated fair +value which would consider future discounted cash flows. +Property acquisition costs are capitalized when incurred. Geological and geophysical costs and delay rentals are expensed as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether the wells +have discovered economically producible reserves. If reserves are not discovered, such costs are expensed as dry holes. Development costs, including equipment and intangible drilling costs related to both producing wells and developmental dry holes, are +capitalized. +(Continued) +F-8 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +Unproved properties are assessed on a property-by-property basis and properties considered to be impaired are charged to expense when such impairment is deemed to have occurred. +Costs of proved properties, including leasehold acquisition, exploration and development costs and equipment, are depreciated or depleted by the unit-of-production method based on estimated proved +developed oil and gas reserves. +Upon sale or retirement of complete units of depreciable or depletable property, the net cost thereof, less proceeds or salvage value, is credited or charged to income. Upon retirement of a partial unit of +property, the cost thereof is charged to accumulated depreciation and depletion. +Based on the Company's experience, management believes site restoration, dismantlement and abandonment costs net of salvage to be immaterial in relation to operating costs. These costs are being expensed +when incurred. +Transportation Equipment, Pipelines and Other Equipment +Transportation equipment, pipelines and other equipment are carried at cost. Depreciation is provided principally on the straight-line method over useful lives of 3 to 17 years. These assets are +reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. An impairment loss based on estimated fair value is recorded when the review indicates that the related expected +future net cash flow (undiscounted and without interest charges) is less than the carrying amount of the asset. +Maintenance and repairs are charged to expense as incurred. Major renewals and betterments are capitalized. Upon the sale or other disposition of assets, the cost and related accumulated depreciation, +depletion and amortization are removed from the accounts, the proceeds applied thereto and any resulting gain or loss is reflected in income. +Buildings +Buildings are carried at cost and depreciated on the straight-line method over estimated useful lives of 30 years. +Advances for Future Drilling Contracts +Represents funds received from Partnerships and other joint ventures for drilling activities which have not been completed and accordingly have not yet been recognized as income in accordance with the +Company's income recognition policies. +Retirement Plans +The Company has a 401-K contributory retirement plan (401-K Plan) covering full-time employees. The Company provides a discretionary matching of employee contributions to the plan. +The Company also has a profit sharing plan covering full-time employees. The Company's contributions to this plan are discretionary. +The Company has a deferred compensation arrangement covering executive officers of the Company as a supplemental retirement benefit. +(Continued) +F-9 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +The Company has established split-dollar life insurance arrangements with certain executive officers. Under these arrangements, advances are made to these officers equal to the premiums due. The advances +are collateralized by the cash surrender value of the policies. The Company records as other assets its share of the cash surrender value of the policies. +Revenue Recognition +Oil and gas wells are drilled primarily on a contract basis. The Company follows the percentage-of-completion method of income recognition for drilling operations in progress. +Sales of natural gas are recognized when sold, oil revenues are recognized when produced into a stock tank. +Well operations income consists of operation charges for well upkeep, maintenance and operating lease income on tangible well equipment. +Income Taxes +Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and +their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax +assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. +Derivative Financial Instruments +Gains and losses related to qualifying hedges of firm commitments or anticipated transactions through the use of natural gas futures and option contracts are deferred and recognized in income or as +adjustments of carrying amounts when the underlying hedged transaction occurs. In order for futures contracts to qualify as a hedge, there must be sufficient correlation to the underlying hedged transaction. The change in the fair value of derivative +instruments which do not qualify for hedging are recognized into income currently. +The Company has entered into an interest rate swap agreement to reduce its exposure to market risks from changing interest rates. The interest rate differential to be paid or received is accrued and recognized currently +in interest expense. +Stock Compensation +The Company has adopted SFAS No. 123, "Accounting for Stock-Based Compensation," which permits entities to recognize as expense over the vesting period the fair value of all stock-based awards on the +date of grant. Alternatively, SFAS 123 allows entities to continue to measure compensation cost for stock-based awards using the intrinsic value based method of accounting prescribed by APB Opinion No. 25, "Accounting for Stock Issued to Employees," and +to provide pro forma net income and pro forma earnings per share disclosures as if the fair value based method defined in SFAS 123 had been applied. The Company has elected to continue to apply the provisions of APB 25 and provide the pro forma disclosure +provisions of SFAS 123. See note 5 to the financial statements. +(Continued) +F-10 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +Use of Estimates +Management of the Company has made a number of estimates and assumptions relating to the reporting of assets and liabilities and revenues and expenses and the disclosure of contingent assets and +liabilities to prepare these financial statements in conformity with generally accepted accounting principles. Actual results could differ from those estimates. Estimates which are particularly significant to the consolidated financial statements include +estimates of oil and gas reserves and future cash flows from oil and gas properties. +Reclassifications +Certain items and amounts reported in the 1999 and 1998 consolidated financial statements have been reclassified to conform to the current year's reporting format. +Fair Value of Financial Instruments +The carrying values and fair values of the Company's receivables, payables and debt obligations are estimated to be substantially the same as of December 31, 2000, 1999 and 1998. +New Accounting Standards +Statement of Accounting Standards No. 133 and No. 138, Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133/138), was issued by the Financial Accounting Standards Board. +SFAS No. 133/138 standardized the accounting for derivative instruments, including certain derivative instruments embedded in other contracts. The Company is required to adopt the provisions of SFAS 133/138 effective January 1, 2001. On adoption, the +provisions of SFAS No. 133/138 must be applied prospectively. The natural gas futures and options and the interest rate swap agreement discussed in note 12 are derivatives pursuant to SFAS 133/138. The Company's derivatives will be treated as hedges of +committed and/or anticipated transactions and have a total estimated fair value of $(20,131,800) on December 31, 2000. On January 1, 2001, the Company will record this estimated fair value as a liability with a corresponding adjustment to accumulated +other comprehensive income (AOCI). The adjustment to AOCI will be recorded net of the related tax effects. +(2) Notes and Accounts Receivable +Included in other assets are noncurrent accounts receivable as of December 31, 2000 and 1999, in the amounts of $245,300 and $494,000 net of the allowance for doubtful accounts of $183,000 and +$216,900, respectively. +The allowance for doubtful current accounts receivable as of December 31, 2000 and 1999 was $341,500 and $221,500, respectively. +(3) Long-Term Debt +On August 29, 2000 the Company executed an Amendment to its Credit Agreement with Bank One, formerly First National Bank of Chicago. The amendment provides and the Company has activated a $30.0 million +borrowing base, subject to adequate oil and gas reserves. The Company is required to pay a commitment fee of 1/4 percent on the unused portion of the activated credit facility. Interest accrues at prime, with LIBOR (London Interbank Market Rate) +alternatives available at the discretion of the Company. No principal payments are required until the credit agreement expires on December 31, 2004. +(Continued) +F-11 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +As of December 31, 2000 and 1999 the outstanding balance was $17,350,000 and $9,300,000, respectively. Any amounts outstanding under the credit agreement are secured by substantially all properties of the +Company. The credit agreement requires, among other things, the existence of satisfactory levels of natural gas reserves, maintenance of certain working capital and tangible net worth ratios along with a restriction on the payment of dividends. As of +December 31, 2000 and 1999 the Company was in compliance with all financial covenants in the credit agreement. +At December 31, 2000, $10,000,000 of the outstanding balance was subject to an interest rate swap at a rate of 8.39%, $5,000,000 at a LIBOR rate of 8.52% and $2,350,000 was subject to a prime rate of 9.50%. +(4) Income Taxes +The Company's provision for income taxes consisted of the following: +2000 +1999 +1998 +Current: +Federal +$1,182,000 +1,434,300 +1,197,800 +State +572,400 +733,000 +525,300 +Total current income taxes +1,754,400 +2,167,300 +1,723,100 +Deferred: +Federal +1,415,600 +(65,300) +(500) +State +422,700 +174,200 +244,500 +Total deferred income taxes +1,838,300 +108,900 +244,000 +Total taxes +$ 3,592,700 +2,276,200 +1,967,100 +Income tax expense differed from the amounts computed by applying the U.S. +federal income tax rate of 34 percent to pretax income as a result of +the following: +2000 +1999 +1998 +Amount +Amount +Amount +Computed "expected" tax +$4,853,100 +3,434,200 +2,932,500 +State income tax +656,800 +598,800 +508,100 +Percentage depletion +(758,300) +(612,000) +(343,400) +Nonconventional source fuel credit +(1,067,500) +(846,800) +(696,700) +Adjustments to valuation allowance +- +(375,000) +(473,200) +Other +(91,400 ) +77,000 +39,800 +$ 3,592,700 +2,276,200 +1,967,100 +(Continued) +F-12 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +The tax effects of temporary differences that give rise to significant +portions of the deferred tax assets and deferred tax liabilities at December 31, 2000 and 1999 are presented below: +2000 +1999 +Deferred tax assets: +Allowance for doubtful accounts +$ 209,800 +175,400 +Drilling notes +101,900 +105,700 +Alternative minimum tax credit +carryforwards (Section 29) +2,132,300 +1,982,300 +Future abandonment +347,200 +273,100 +Deferred compensation +1,729,200 +1,213,800 +Other +49,400 +51,600 +Total gross deferred tax assets +4,569,800 +3,801,900 +Less valuation allowance +- +- +Deferred tax assets +4,569,800 +3,801,900 +Less current deferred tax assets +(included in prepaid expenses) +(853,300 ) +(1,007,600 ) +Net non-current deferred +tax assets +3,716,500 +2,794,300 +Deferred tax liabilities: +Properties and equipment, principally +due to differences in depreciation +and amortization +(9,425,300 ) +(6,928,400 ) +Total gross deferred +tax liabilities +(9,425,300 ) +(6,928,400 ) +Net deferred tax liability +$ (5,708,800 ) +(4,134,100 ) +The valuation allowance for the deferred tax assets as of January 1, 2000 and 1999 was $0 and $375,000, respectively. The net changes in the total valuation allowance were +decreases of $375,000 and $473,200 for the years ended December 31, 1999 and 1998, respectively. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax +assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal +of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. +At December 31, 2000, the Company has alternative minimum tax credit carryforwards (Section 29) of approximately $2,132,300 which are available to reduce future federal regular income taxes over an +indefinite period. +(5) Common Stock +Options +Options amounting to 180,000, 145,000 and 20,000 shares were granted during 2000, 1999 and 1998, respectively, to certain employees and directors under the Company's Stock Option Plans. These options +were granted with an exercise price equal to market value as of the date of grant and vest over a six month period for the 2000 and 1999 grants and a two year period for the 1998 grant. The outstanding options expire from 2005 to 2010. +(Continued) +F-13 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +The estimated fair value of the options granted during 2000, 1999 and 1998 was $2.48, $2.44 and $3.92 per option, respectively. The fair value was estimated using the Black-Scholes option pricing model +with the following assumptions for the 2000, 1999 and 1998 grant, respectively: risk-free interest rate of 6.13%, 5.1% and 5.9%, expected dividend yield of 0%, expected volatility of 57.31%, 61.3% and 58.0% and expected life of 7 years. +Average +Range of +Number +Exercise +Exercise +of Shares +Price +Prices +Outstanding December 31, 1997 +1,872,650 +$ 2.10 +.94 - 5.13 +Granted +20,000 +$ 6.13 +6.13 - 6.13 +Exercised +(324,333) +$ 0.94 +.94 - .94 +Expired +- +$ - +- +Outstanding December 31, 1998 +1,568,317 +$ 2.39 +.94 - 6.13 +Granted +145,000 +$ 3.75 +3.75 - 3.75 +Exercised +(324,333) +$ 0.94 +.94 - .94 +Expired +- +$ - +- +Outstanding December 31, 1999 +1,388,984 +$ 2.87 +.94 - 6.13 +Granted +180,000 +$ 3.875 +3.875 - 3.875 +Exercised +(511,584) +$ 1.01 +.94 - 1.625 +Expired +(12,400 ) +$ 3.31 +1.50 - 3.75 +Outstanding December 31, 2000 +1,045,000 +$ 3.95 +1.125 - 6.125 +As of December 31, 2000, there were 210,000 options outstanding and exercisable at the $1.125 exercise price which have a weighted average remaining contractual life of 4.9 +years. Also as of December 31, 2000 there were 835,000 options outstanding and exercisable at a $3.75 to $6.13 exercise price range having a weighted average remaining contractual life of 7.4 years and weighted average exercise price of $4.66. +The Company accounts for its stock-based compensation plans under APB 25. For stock options granted, the option price was not less than the market value of shares on the grant date, therefore, no +compensation cost has been recognized. Had compensation cost been determined under the provisions of SFAS 123, the Company's net income and earnings per share would have been the following on a pro forma basis: +2000 +1999 +As Reported +Pro Forma +As Reported +Pro Forma +Net income +$ 10,681,000 +$ 10,346,700 +$ 7,824,300 +$ 7,336,200 +Basic earnings +per share +$ .66 +$ .64 +$ .50 +$ .47 +Diluted earnings +per share +$ .65 +$ .63 +$ .48 +$ .45 +(Continued) +F-14 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +Stock Redemption Agreement +The Company has stock redemption agreements with three officers of the Company. The agreements require the Company to maintain life insurance on each executive in the amount of $1,000,000. The +agreements provide that the Company shall utilize the proceeds from such insurance to purchase from such executives' estates or heirs, at their option, shares of the Company's stock. The purchase price for the outstanding common stock is to be based upon +the average closing asked price for the Company's stock as quoted by NASDAQ during a specified period. The Company is not required to purchase any shares in excess of the amount provided for by such insurance. +(6) Employee Benefit Plans +The Company made 401-K Plan contributions of $252,613, $217,400 and $202,600 for 2000, 1999 and 1998, respectively. +The Company has a profit sharing plan (the Plan) covering full-time employees. The Company contributed $1,000, $47,000 and $17,000, to the plan in cash during 2000, 1999 and 1998, respectively. +During 2000, 1999 and 1998 the Company expensed and established a liability for $90,000 each year under a deferred compensation arrangement with the executive officers of the Company. +In 1995, a total of 90,000 restricted shares of the Company's common stock were granted to certain employees and available to them upon retirement. The market value of shares awarded was $101,300. This +amount was recorded as unamortized stock award. The unamortized stock award is being amortized to expense over the employees' expected years to retirement and amounted to $5,500, $12,200 and $12,200 in 2000, 1999 and 1998, respectively. +At December 31, 2000 and 1999, the Company has recorded as other assets $360,000 and $300,000, respectively as its share of the cash surrender value of the life insurance pledged as collateral for the +payment of premiums on split-dollar life insurance policies owned by certain executive officers. +(7) Earnings Per Share +Basic earnings per share is based on the weighted average number of common shares outstanding of 16,157,532 for 2000, 15,734,063 for 1999 and 15,505,680 for 1998. +Diluted earnings per share is based on the weighted average number of common and common equivalent shares outstanding of 16,437,488 for 2000, 16,286,852 for 1999 and 16,338,298 for 1998. Stock options are +considered to be common stock equivalents and, to the extent appropriate, have been added to the weighted average common shares outstanding. +(8) Transactions with Affiliates +As part of its duties as well operator, the Company received $44,899,200 in 2000, $24,002,500 in 1999 and $22,997,300 in 1998 representing proceeds from the sale of oil and gas and made distributions +to investor groups according to their working interests in the related oil and gas properties. Funds held for future distribution on the consolidated balance sheet includes amounts owed to affiliated partnerships as of December 31, 2000 and 1999. +(Continued) +F-15 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +The Company provided oil and gas well drilling services to affiliated partnerships. Substantially all of the Company's oil and gas well drilling operations was for such partnerships. The Company also +provided related services of operation of wells, reimbursement of syndication costs, management fees, tax return preparation and other services relating to the operation of the partnerships. The Company received $15,713,300 in 2000, $10,322,500 in 1999 +and $9,621,700 in 1998 for those services. Amounts due from the partnerships as of December 31, 2000 and 1999 were $957,700 and $895,900, and are included in notes and accounts receivable. +During 2000, 1999 and 1998, the Company paid $40,400, $31,600 and $30,000, respectively to the Corporate Secretary's law firm for various legal services. +(9) Commitments and Contingencies +The nature of the independent oil and gas industry involves a dependence on outside investor drilling capital and involves a concentration of gas sales to a few customers. The Company sells natural gas +to various public utilities and industrial customers. One customer, Cinnabar Energy Services, accounted for 11.3% of total revenues in 2000. No customer accounted for more than 10.0% of total revenues in 1999 or 1998. +The Company would be exposed to natural gas price fluctuations on underlying purchase and sale contracts should the counterparties to the Company's hedging instruments or the counterparties to the +Company's gas marketing contracts not perform. Such nonperformance is not anticipated. There were no counterparty default losses in 2000, 1999 or 1998. +Substantially all of the Company's drilling programs contain a repurchase provision where Investors may tender their partnership units for repurchase at any time beginning with the third anniversary of the +first cash distribution. The provision provides that the Company is obligated to purchase an aggregate of 10% of the initial subscriptions per calendar year (at a minimum price of four times the most recent 12 months' cash distributions), only if such +units are tendered, subject to the Company's financial ability to do so. The maximum annual 10% repurchase obligation, if tendered by the investors, is currently approximately $1,188,000. The Company has adequate capital to meet this obligation. +The Company is not party to any legal action that would materially affect the Company's results of operations or financial condition. +(10) Supplemental Disclosure of Cash Flows +The Company paid $875,800, $124,200 and $0 for interest in 2000, 1999 and 1998, respectively. The Company paid income taxes in 2000, 1999 and 1998 in the amounts of $2,256,800, $1,327,800 and +$2,349,100, respectively. +The Company exchanged common stock in the amount of $550,000 and cash in the amount of $5,100,000 for the purchase of oil and gas properties in Colorado during 2000. +(11) Acquisitions and Divestitures +On January 29, 1999, the Company offered to purchase from Investors their units of investment in the Company's Drilling Programs formed prior to 1996. The Company purchased approximately $1.8 million +of producing oil and gas properties in conjunction with this offer, which expired on March 31, 1999. The Company utilized capital received from its Public Stock Offering to fund this purchase. +(Continued) +F-16 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +On December 15, 1999, the Company purchased all of the working interest in 53 producing wells in the D-J Basin of Colorado. At the date of acquisition, the Company estimates that the purchase includes +proved developed reserves of approximately 3.6 Bcf of natural gas and 370,000 barrels of oil or approximately 5.8 Bcf equivalent (Bcfe), along with 3.0 Bcfe of proved undeveloped reserves. Also included in the acquistion was 16.5 net development drilling +locations. The total acquisition cost for the wells and locations was $5.2 million. The company utiltized part of its existing line of credit to fund the transaction. The effective date of the transaction was December 1, 1999. +On June 6, 2000, the Company purchased all of the working interest in 168 producing wells in Colorado for $5,650,000. The transaction was effective April 1, 2000. At the date of acquisition, the wells had +net remaining reserves of 560,000 barrels of oil and 4.9 billion cubic feet of natural gas. The Company utilized its bank credit agreement to finance this purchase. +On December 31, 2000, the Company sold its Ohio gas gathering and sales systems. The result was a net gain of $109,600. +(12) Derivative Financial Instruments +The Company utilizes commodity based derivative instruments as hedges to manage a portion of its exposure to price volatility stemming from its integrated natural gas production and marketing activities. These +instruments consist of natural gas futures and option contracts traded on the New York Mercantile Exchange. The futures and option contracts hedge committed and anticipated natural gas purchases and sales, generally forecasted to occur within a 12 month +period. The Company does not hold or issue derivatives for trading or speculative purposes. +As of December 31, 2000 and 1999, the Company had futures contracts for the sale of 6,230,000 dt and 4,318,0000 dt of natural gas, respectively and option contracts for the sale of 2,276,400 dt as of December 31, +2000. While these contracts have nominal carrying value, their fair value, represented by the estimated amount that would be received (paid) upon termination of the contracts, based on market quotes, was a value of $(11,526,500) stemming from its +marketing activities at December 31, 2000 and $350,500 stemming from its marketing activities at December 31, 1999. Based on the nature of the Company's gas marketing activities, hedging is not expected to have a significant impact on the Company's net +margins from marketing activities during 2001.The fair value of these contracts was $(8,571,500) stemming from its natural gas production, $(5,142,900) net of tax at December 31, 2000. +The Company is required to maintain margin deposits with brokers for outstanding futures contracts. As of December 31, 2000 and 1999, cash in the amount of $2,938,300 and $614,300 was on deposit. +Interest rate swap agreements are used to reduce the potential impact of increases in interest rates on variable rate long-term debt. At December 31, 2000, the Company was a party to an interest rate swap agreement +expiring on October 11, 2004. The agreement entitles the Company, on a quarterly basis, to a fixed-rate interest payment of 6.89% plus its current LIBOR rate margin (+1.50% At December 31, 2000) on a $10,000,000 notional amount related to its outstanding +line of credit. +F-17 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +The fair value of the interest rate swap agreement was $(33,800), $(20,300) net of tax at December 31, 2000. Current market pricing models were used to estimate fair value. +By using derivative financial instruments to hedge exposures to changes in interest rates and commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to +perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates repayment risk. The Company minimizes the credit or repayment risk in derivative instruments by +entering into transactions with high-quality counterparties. +(13) Costs Incurred in Oil and Gas Property Acquisition, Exploration and +Development Activities +Costs incurred by the Company in oil and gas property acquisition, exploration and development are presented below: +Years Ended December 31, +2000 +1999 +1998 +Property acquisition cost: +Proved undeveloped properties +$3,397,500 +2,532,200 +1,903,200 +Producing properties +8,361,400 +6,997,500 +8,679,000 +Development costs +15,556,200 +17,168,000 +14,902,500 +$ 27,315,100 +26,697,700 +25,484,700 +Of the above development costs incurred for the years ended December 31, 2000, 1999 and 1998 the amounts of $2,379,300, $2,977,500 and $2,657,700, respectively were incurred to +develop proved undeveloped properties from the prior year end. The proved reserves attributable to these development costs were 1,388,200 Mcf and 83,900 bbls for 2000, 6,885,000 Mcf for 1999 and 5,787,000 Mcf for 1998 (amounts unaudited). +Property acquisition costs include costs incurred to purchase, lease or otherwise acquire a property. Development costs include costs incurred to gain access to and prepare development well locations for +drilling, to drill and equip development wells and to provide facilities to extract, treat, gather and store oil and gas. +(14) Oil and Gas Capitalized Costs +Aggregate capitalized costs for the Company related to oil and gas exploration and production activities with applicable accumulated depreciation, depletion and amortization are presented below: +December 31, +2000 +1999 +Proved properties: +Tangible well equipment +$82,304,400 +67,060,500 +Intangible drilling costs +44,944,000 +36,270,300 +Undeveloped properties +4,023,500 +2,507,100 +131,271,900 +105,837,900 +Less accumulated depreciation, +depletion and amortization +29,739,500 +23,652,000 +$ 101,532,400 +82,185,900 +F-18 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +(15) Results of Operations for Oil and Gas Producing Activities +The results of operations for oil and gas producing activities (excluding marketing) are presented below: +Years Ended December 31, +2000 +1999 +1998 +Revenue: +Oil and gas sales +$19,017,300 +8,628,400 +6,121,700 +Expenses: +Production costs +4,201,400 +2,422,000 +1,516,700 +Depreciation, depletion +and amortization +6,031,200 +3,220,900 +2,392,000 +10,232,600 +5,642,900 +3,908,700 +Results of operations for +oil and gas producing +activities before provision +for income taxes +8,874,700 +2,985,500 +2,213,000 +Provision for income taxes +2,713,900 +469,400 +398,600 +Results of operations for oil +and gas producing activities +(excluding corporate over- +head and interest costs) +$ 6,070,800 +2,516,100 +1,814,400 +Production costs include those costs incurred to operate and maintain productive wells and related equipment, including such costs as labor, repairs, maintenance, materials, +supplies, fuel consumed, insurance and other production taxes. In addition, production costs include administrative expenses and depreciation applicable to support equipment associated with these activities. +Depreciation, depletion and amortization expense includes those costs associated with capitalized acquisition, exploration and development costs, but does not include the depreciation applicable to support +equipment. +The provision for income taxes is computed at the statutory federal income tax rate and is reduced to the extent of permanent differences, such as investment tax and non-conventional source fuel tax +credits and statutory depletion allowed for income tax purposes. +(Continued) +F-19 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +(16) Net Proved Oil and Gas Reserves (Unaudited) +The proved reserves of oil and gas of the Company have been estimated by an independent petroleum engineer, Wright & Company, Inc. at December 31, 2000, 1999 and 1998. These reserves have been +prepared in compliance with the Securities and Exchange Commission rules based on year end prices. An analysis of the change in estimated quantities of oil and gas reserves, all of which are located within the United States, is shown below: +Oil (BBLS) +2000 +1999 +1998 +Proved developed and +undeveloped reserves: +Beginning of year +1,154,000 +29,000 +45,000 +Revisions of previous estimates +10,000 +67,000 +(10,000 ) +Beginning of year as revised +1,164,000 +96,000 +35,000 +New discoveries and extensions +Michigan +265,000 +- +- +Wattenberg field +535,000 +404,000 +- +Dispositions to partnerships +(262,000) +- +- +Acquisitions +Wattenberg field +573,000 +652,000 +- +Appalachian basin +- +10,000 +2,000 +Production +(109,000 ) +(8,000 ) +(8,000 ) +End of year +2,166,000 +1,154,000 +29,000 +Proved developed reserves: +Beginning of year +798,000 +29,000 +45,000 +End of year +1,527,000 +798,000 +29,000 +Gas (MCF) +2000 +1999 +1998 +Proved developed and +undeveloped reserves: +Beginning of year +101,245,000 +80,819,000 +57,243,000 +Revisions of previous estimates +(3,859,000 ) +(4,475,000 ) +(3,517,000 ) +Beginning of year as revised +97,386,000 +76,344,000 +53,726,000 +New discoveries and extensions +Michigan +14,191,000 +4,559,000 +17,383,000 +Wattenberg field +5,681,000 +4,070,000 +- +Pieance basin +8,922,000 +9,974,000 +- +Appalachian basin +266,000 +6,178,000 +6,169,000 +Dispositions to partnerships +(8,498,000) +(8,774,000) +(6,009,000) +Acquisitions +Michigan +- +- +2,842,000 +Wattenberg field +5,761,000 +5,546,000 +- +Appalachian basin +668,000 +6,799,000 +9,161,000 +Production +(5,737,000 ) +(3,451,000 ) +(2,453,000 ) +End of year +118,640,000 +101,245,000 +80,819,000 +Proved developed reserves: +Beginning of year +82,628,000 +64,562,000 +42,411,000 +End of year +92,131,000 +82,628,000 +64,562,000 +(17) Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves (Unaudited) +Summarized in the following table is information for the Company with respect to the standardized measure of discounted future net cash flows relating to proved oil and gas reserves. Future cash +inflows are computed by applying year-end prices, adjusted for hedging contracts, of oil and gas relating to the Company's proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs +are derived based on current costs assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the statutory rate in effect at the end of each year to the future pretax net cash flows, less the tax basis of +the properties and gives effect to permanent differences, tax credits and allowances related to the properties. +(Continued) +F-20 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +Years Ended December 31, +2000 +1999 +1998 +Future estimated cash flows +$520,010,000 +307,816,000 +186,598,000 +Future estimated production costs +(144,505,000) +(104,233,000) +(84,078,000) +Future estimated development costs +(50,278,000) +(25,324,000) +(11,592,000) +Future estimated income +tax expense +(80,982,000 ) +(39,930,000 ) +(20,322,000 ) +Future net cash flows +244,245,000 +138,329,000 +70,606,000 +10% annual discount for estimated +timing of cash flows +(139,606,000 ) +(79,875,000 ) +(40,412,000 ) +Standardized measure of +discounted future +estimated net cash flows +$ 104,639,000 +58,454,000 +30,194,000 +The following table summarizes the principal sources of change in the standardized measure of discounted future estimated net cash flows: +Years Ended December 31, +2000 +1999 +1998 +Sales of oil and gas +production, net of +production costs +$(14,816,000) +(6,206,000) +(4,605,000) +Net changes in prices +and production costs +70,514,000 +29,547,000 +(23,083,000) +Extensions, discoveries +and improved recovery, +less related cost +73,636,000 +39,653,000 +18,615,000 +Dispositions to partnerships +(16,850,000) +(6,152,000) +(5,762,000) +Acquisitions +27,907,000 +31,915,000 +13,938,000 +Development costs incurred +during the period +15,556,000 +17,168,000 +14,903,000 +Revisions of previous +quantity estimates +(5,925,000) +(4,944,000) +(5,605,000) +Changes in estimated +income taxes +(41,052,000) +(19,608,000) +459,000 +Changes in discount +(59,731,000) +(39,463,000) +1,224,000 +Changes in production rates +(timing) and other +(3,054,000 ) +(13,650,000 ) +(7,826,000 ) +$ 46,185,000 +28,260,000 +2,258,000 +It is necessary to emphasize that the data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the +computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of +production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the current prices and +costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein. +F-21 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +(18) Business Segments (Thousands) +PDC's operating activities can be divided into three major segments: drilling and development, natural gas sales, and well operations. The Company drills natural gas wells for Company-sponsored +drilling partnerships and retains an interest in each well. The Company also engages in oil and gas sales to residential, commercial and industrial end-users. The Company charges Company-sponsored partnerships and other third parties competitive industry +rates for well operations and gas gathering. Segment information for the years ended December 31, 2000, 1999 and 1998 is as follows: +2000 +1999 +1998 +REVENUES +Drilling and Development +$43,195 +42,116 +40,447 +Natural Gas Sales +90,420 +46,988 +35,560 +Well Operations +5,061 +5,314 +4,581 +Unallocated amounts (1) +2,540 +2,392 +2,385 +Total +$ 141,216 +96,810 +82,973 +(1) Includes interest on investments and partnership management fees in +2000, 1999 and 1998 and gain on sale of assets in 2000 and 1999 which +are not allocated in assessing segment performance. +2000 +1999 +1998 +SEGMENT INCOME BEFORE INCOME TAXES +Drilling and Development +$ 7,950 +6,608 +5,400 +Natural Gas Sales +7,364 +2,967 +2,064 +Well Operations +1,385 +1,219 +1,372 +Unallocated amounts (2) +General and Administrative expenses +(3,617) +(2,801) +(2,491) +Interest expense +(1,186) +(182) +- +Other (1) +2,378 +2,289 +2,280 +Total +$ 14,274 +10,100 +8,625 +(2) Items which are not allocated in assessing segment performance. +2000 +1999 +1998 +SEGMENT ASSETS +Drilling and Development +$ 31,592 +23,957 +27,288 +Natural Gas Sales +139,116 +93,073 +65,256 +Well Operations +8,490 +7,977 +7,136 +Unallocated amounts +Cash +1,567 +1,967 +7,814 +Other +6,920 +5,110 +3,915 +Total +$ 187,685 +132,084 +111,409 +2000 +1999 +1998 +EXPENDITURES FOR SEGMENT +LONG-LIVED ASSETS +Drilling and Development +$ 3,217 +1,710 +1,953 +Natural Gas Sales +23,958 +24,613 +23,645 +Well Operations +650 +1,328 +947 +Unallocated amounts +107 +107 +85 +Total +$ 27,932 +27,758 +26,630 +F-22 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +(19) Quarterly Financial Data (Unaudited ) +Summarized quarterly financial data for the years ended December 31, 2000 and 1999, are as follows: +2000 +Quarter +Year +First +Second +Third +Fourth +Revenues +$34,504,400 +$29,063,200 +$32,818,600 +$44,830,300 +$141,216,500 +Cost of operations +29,600,900 +25,225,800 +28,646,900 +38,666,300 +122,139,900 +Gross profit +4,903,500 +3,837,400 +4,171,700 +6,164,000 +19,076,600 +General and +administrative +expenses +679,200 +1,032,300 +1,038,300 +867,100 +3,616,900 +Interest expense +14,600 +275,400 +437,500 +458,500 +1,186,000 +693,800 +1,307,700 +1,475,800 +1,325,600 +4,802,900 +Income before +income taxes +4,209,700 +2,529,700 +2,695,900 +4,838,400 +14,273,700 +Income taxes +968,300 +581,900 +555,000 +1,487,500 +3,592,700 +Net income +$ 3,241,400 +$ 1,947,800 +$ 2,140,900 +$ 3,350,900 +$ 10,681,000 +Basic earnings +per share +$ .20 +$ .12 +$ .13 +$ .21 +$ .66 +Diluted earnings +per share +$ .20 +$ .12 +$ .13 +$ .20 +$ .65 +1999 +Quarter +Year +First +Second +Third +Fourth +Revenues +$27,666,300 +$21,064,000 +$23,841,700 +$24,238,600 +$96,810,600 +Cost of operations +23,837,400 +18,411,200 +20,038,900 +21,439,200 +83,726,700 +Gross profit +3,828,900 +2,652,800 +3,802,800 +2,799,400 +13,083,900 +General and +administrative +expenses +464,400 +595,800 +859,200 +881,600 +2,801,000 +Interest expense +- +- +88,100 +94,300 +182,400 +464,400 +595,800 +947,300 +975,900 +2,983,400 +Income before +income taxes +3,364,500 +2,057,000 +2,855,500 +1,823,500 +10,100,500 +Income taxes +753,700 +460,700 +842,000 +219,800 +2,276,200 +Net income +$ 2,610,800 +$ 1,596,300 +$ 2,013,500 +$ 1,603,700 +$ 7,824,300 +Basic earnings +per share +$ .17 +$ .10 +$ .13 +$ .10 +$ .50 +Diluted earnings +per share +$ .16 +$ .10 +$ .12 +$ .10 +$ .48 +Cost of operations include cost of oil and gas well drilling operations, oil and gas purchases and production costs and depreciation, depletion and amortization. +F-23 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS +AND RESERVES +Years Ended December 31, 2000, 1999 and 1998 +Column A +Column B +Column C +Column D +Column E +Additions, +Balance at +Charged to +Balance +Beginning +Costs and +at End +Description +of Period +Expenses +Deductions +of Period +Allowance for doubtful +accounts deducted from +accounts and notes receivable +in the balance sheet +2000 +$ 438,400 +$ 573,000 +$ 486,900 +$ 524,500 +1999 +$ 274,600 +$ 272,500 +$ 108,700 +$ 438,400 +1998 +$ 275,400 +$ 46,800 +$ 47,600 +$ 274,600 +F-24 \ No newline at end of file diff --git a/raw/filings/0000077877/2000/0000077877-01-500003/filing_metadata.csv b/raw/filings/0000077877/2000/0000077877-01-500003/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..e3f964c67f67f3296ba22f6b69e0e73d74c860b9 --- /dev/null +++ b/raw/filings/0000077877/2000/0000077877-01-500003/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 +0000077877,PDCE,"PDC ENERGY, INC.",10-K,2001-03-26,2000-12-31,2001-03-26T05:00:00.000Z,0000077877-01-500003,pdc10k.htm,PDC 10-K HTML,438578,0,0,https://www.sec.gov/Archives/edgar/data/77877/000007787701500003/pdc10k.htm,https://www.sec.gov/Archives/edgar/data/77877/000007787701500003/,2000,2000,1 diff --git a/raw/filings/0000077877/2000/0000077877-01-500003/item1.txt b/raw/filings/0000077877/2000/0000077877-01-500003/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..42622d3d22409c38194df6f13c4fda15952b34f4 --- /dev/null +++ b/raw/filings/0000077877/2000/0000077877-01-500003/item1.txt @@ -0,0 +1,157 @@ +Item 1. Business +The Company is an independent energy company engaged primarily in the development, production and marketing of natural gas and oil. The Company has grown primarily through drilling and development +activities, the acquisition of natural gas and oil producing wells and the expansion of its natural gas marketing activities. As of December 31, 2000, the Company operates approximately 2,025 wells located in the Appalachian basin, Michigan, and the Rocky +Mountain Region, with gross proved reserves of 307 Bcfe of natural gas of which the Company's share is 132 Bcfe of natural gas. The wells operated by the Company currently produce an aggregate of approximately 47,000 thousand cubic feet equivalent +("Mcfe", based on one barrel of oil equals 6 thousand cubic feet "Mcf" of gas.) of natural gas per day, of which the Company's share is approximately 19,500 Mcfe. +The Company's operations are divided into three regions, the Appalachian Basin, Michigan, and the Rocky Mountains. The Company has conducted operations in Appalachia since its inception in 1969, in +Michigan since 1997, and the Rocky Mountains since 1999. As of the end of 2000 approximately 39% of production was generated by Appalachian Basin wells, 36% by Michigan wells, and 25% by Colorado wells. At the end of 2000 the Company's reserves were +divided almost equally among three regions, with all of the recorded proved undeveloped reserves in Michigan and Colorado. This reflects the planned drilling for 2001, which will be focused in Colorado and to a lesser extent in Michigan. +In all three regions the Company has historically targeted shallow, developmental natural gas reserves for development. In most areas of Colorado the wells also produce oil in conjunction with natural gas. +In one of our areas in Michigan, oil is the dominant economic product. The Company is also investigating the potential for deeper exploratory wells in the Rocky Mountain region, with plans to include several exploratory prospects in its 2001 drilling plans. +The Company owns Riley Natural Gas (RNG), an Appalachian Basin natural gas marketing company, which aggregates and resells natural gas developed by the Company and other producers. This allows the Company +to diversify its operations beyond natural gas drilling and production. RNG has established relationships with many of the small natural gas producers in the Appalachian Basin and has significant expertise in the natural gas end-user market. In addition, +RNG has extensive experience in the use of hedging strategies, which the Company utilizes to reduce the financial impact on the Company of changes in the price of natural gas. +Since 1984, the Company has sponsored limited partnerships formed to engage in drilling operations. The Company typically retains a 20% ownership interest in these drilling limited partnerships. In 2000, +the Company raised $55.6 million through four public drilling partnerships, making it the sponsor of the largest public oil and gas partnership program in the United States in that year. The drilling programs have provided the Company with access to the +capital resources necessary to expand its drilling opportunities and to maintain the infrastructure necessary to support such activities. +Industry Overview +Natural gas is the second largest energy source in the United States, after liquid petroleum. The 22.7 Tcf of natural gas consumed in 2000 represented approximately 23% of the total energy used in the United States. +Natural gas is consumed in the United States as follows: 45% by industrial end-users as feedstock for products such as plastic and fertilizer or as the energy source for producing products such as glass; 22% and 16% by residential and commercial +end-users, respectively, for uses including heating, cooling and cooking; 12% by utilities for the generation of electricity; and the remainder for transportation purposes. (Source U.S. Energy Information Administration) +-2- +The Company believes that the market for natural gas will grow in the future. The demand for natural gas has increased due to four main factors: +- Efficiency. Relative to other energy sources, natural gas losses during transportation from source to destination are slight, averaging only about 9% of the natural gas energy. +- Environmentally favorable. Natural gas is the cleanest and most environmentally safe of the fossil fuels. +- Safety. The delivery of natural gas is among the safest means of distributing energy to customers, as the natural gas transmission system is fixed and is located underground. +- Price. The deregulation of the natural gas industry and a favorable regulatory environment have resulted in end-users' ability to purchase natural gas on a competitive basis from a greater +variety of sources. +The Company believes that the foregoing factors, together with the increased availability of natural gas as a form of energy for residential, commercial and industrial uses, should increase the demand for natural gas as well as create +new markets for natural gas. +As local supplies of natural gas are inadequate to meet demand, the West Coast and the Northeast import natural gas from producing areas via interstate natural gas pipelines. The cost of transporting +natural gas from the major producing areas to markets creates a price advantage for production located closer to the consuming regions. The natural gas industry in the Appalachian Basin and Michigan benefit from proximity to the northeastern United States. +In the early 1980's, natural gas companies began exploiting the northern portion of Michigan's lower peninsula, when certain favorable tax credits for natural gas development were enacted. The result of +such development was new advances in drilling technology, which made natural gas drilling in this area profitable even after the expiration of these tax credits. In Michigan's lower peninsula, there is an abundance of shallow Antrim gas shale, which can +provide significant reserves per well drilled. Additionally, this area is close to certain end-user markets, which has provided favorable premiums. +During 1998 the Company began to establish a lease position in the Rocky Mountain producing region. The region is believed to hold substantial undeveloped natural gas resources. Recent additions to +pipeline capacity in the region have made the area more attractive for development. Gas from the region will generally sell for less than gas in the Appalachian and Michigan Basins, but costs of development are expected to be less. During 1998, the +Company leased 39,500 acres of oil and gas development rights acres in Utah. In 1999 the company drilled four unsuccessful exploratory wells, two in Moffatt County, Colorado and two in Carter County, Montana. In November and December 1999 the Company +acquired drilling rights to 20 locations in the Wattenberg field in Weld County, Colorado and a 7,400 acre lease in the Grand Valley field in Garfield County, Colorado. Prior to the end of 1999, the Company had drilled five successful wells in the +Wattenberg field and was prepared to drill its first Grand Valley test well. The Company expanded its operations in the Rocky Mountains in 2000, by drilling 52 successful wells and adding over 50,000 acres to its position in the Wattenberg and Grand +Valley fields. The Company plans to do the majority of its development work in these areas in 2001. +Business Strategy +The Company's objective is to expand its natural gas reserves, production and revenues through a strategy that includes the following key elements: +-3- +Expand drilling operations. The Company has had one of the most active drilling programs in the Northeast in the 1990's and will seek to continue to build on the experience developed. The Company drilled +97 wells in 2000, compared to 178 for the year of 1999. The decrease in the number of wells drilled results primarily from the greater cost of the Rocky Mountain wells compared to the Company's Appalachian and Michigan wells. The Company believes that it +will be able to drill a substantial number of new wells on its current undeveloped leased properties. As of December 31, 2000, the Company had 11,000 undeveloped acres in the Michigan Basin, 12,900 undeveloped acres in the Appalachian Basin and 164,600 +undeveloped acres in the Rocky Mountain Region. As drilling activity increases, the Company benefits as its fixed costs may be spread over a larger number of wells. +Acquire producing properties. The Company's acquisition efforts are focused on properties that fit well within existing operations or that help to build critical mass in areas where the Company is +establishing new operations. Acquisitions will likely offer economies in management and administration, and therefore the Company believes that it will be able to acquire more producing wells without incurring substantial increases in its costs of +operations. +Pursue geographic expansion. The Company has a proven ability to drill and operate shallow natural gas wells successfully. There are a number of areas outside the Appalachian Basin where drilling and +operating characteristics are similar to those in Appalachia. For example, since 1996, the Company expanded into the Michigan Basin, which permitted the Company to leverage its expertise developed in the Appalachian Basin because of the similarities in +methods of drilling, depth, equipment and operations. Moreover, reserves and production levels of two to three times that of Appalachian levels for a similar investment more than offset higher expected operating costs. The Company's Colorado development +projects also build on our shallow gas well operating experience. The Company will continue to evaluate opportunities to expand geographically on an ongoing basis. +Reduce risks inherent in natural gas development and marketing. An integral part of the Company's strategy has been and will continue to be to concentrate on shallow development, (rather than exploratory) +drilling, and geographical diversification to reduce risk levels associated with natural gas and oil production. Development drilling is less risky than exploratory drilling and is likely to generate cash returns more quickly. The focus on shallow wells +builds on the Company's knowledge and experience, and also provides greater investment diversification than an equal investment in a smaller number of deeper and/or more expensive wells. Geographical diversification can help to offset possible weakness in +the natural gas market or disappointing drilling results in one area. The Company believes that, as natural gas markets are deregulated, successful natural gas marketing is essential to profitable operations. To further this goal, the Company has the +expertise of RNG, an experienced natural gas marketer. The Company intends to continue to expand its marketing capacity to keep pace with the changing natural gas industry. +Exploration and Development Activities +The Company's development activities focus on the identification and drilling of new productive wells and the acquisition of existing producing wells from other producers. +Prospect Generation +The Company's staff of professional geologists is responsible for identifying areas with potential for economic production of natural gas and oil. These geologists have decades of cumulative drilling of +successful, economically feasible natural gas and oil wells. They utilize results from logs and other tools to evaluate existing wells and to predict the location of attractive new gas reserves. To further this process, the Company has collected and +continues to collect logs, core data, production information and other raw data available from state and private agencies, other companies and individuals actively drilling in the regions being evaluated. From this information the geologists develop +models of the subsurface structures and stratigraphy that are used to predict areas with above-average prospects for economic development. +-4- +On the basis of these models, the geologists instruct the Company's land department to obtain available natural gas leaseholds in these prospective areas. These leases are then obtained, if possible, by +the Company's land department or contract landmen under the direction of the Company's land manager. In most cases, the Company pays a lease bonus and annual rental payments, converting, upon initiation of production, to a 12.5% royalty on gross +production revenue in return for obtaining the leases. In some instances of particularly attractive properties, additional overriding royalty payments may be made to third parties or royalty owners. As of December 31, 2000, the Company had a total +leasehold inventory of approximately 294,040 acres. See--"Properties--Natural Gas Leases." +Drilling Activities +When prospects have been identified and leased, the Company develops these properties by drilling wells. In 2000, the Company drilled a total of 97 wells, with no dry holes. Typically, the Company will act +as driller-operator for these prospects, entering into contracts with partnerships, including Company-sponsored partnerships, and other entities that are interested in exploration or development of the prospects. The Company generally retains an interest +in each well it drills. See "Financing of Drilling Activities." +Much of the work associated with drilling, completing and connecting wells, including drilling, fracturing, logging and pipeline construction, is performed by subcontractors specializing in those +operations, as is common in the industry. A large part of the material and services used by the Company in the development process is acquired through competitive bidding by approved vendors. The Company also directly negotiates rates and costs for +services and supplies when conditions indicate that such an approach is warranted. As the prices paid to the Company by its investor partners for the Company's services are frequently fixed before the wells are drilled or are determined solely on the well +depth, the Company is subject to the risk that prices of goods or services used in the development process could increase, rendering its contracts with its investor partners less profitable or unprofitable. In addition, problems encountered in the process +can substantially increase development costs, sometimes without recourse for the Company to recover its costs from its partners. To minimize these risks, the Company seeks to lock in its development costs in advance of drilling and, when possible, at the +time of negotiation and execution of its investor partnership agreements. +Acquisitions of Producing Properties +In addition to drilling new wells, the Company continues to pursue opportunities to purchase existing wells from other producers and greater ownership interests in the wells it operates. Generally, outside +interests purchased include a majority interest in the wells and well operations. +During 1998 the Company purchased an 80% interest in 122 producing wells located in Pennsylvania from Pemco Gas, Inc. and a 100% working interest in 13 producing wells in Michigan. During 1999, the Company purchased a 100% working +interest in 53 producing wells in the D-J Basin of Colorado which added 3.6 Bcf of natural gas and 370,000 barrels of oil to the Company's reserves. During 2000, the Company purchased 100% of the working interest in 168 producing wells in the DJ Basin of +Colorado which added 4.9 Bcf of natural gas and 560,000 barrels of oil to the Company's reserves. Also purchased in 1998, 1999 and 2000 were certain well interests in its Company sponsored partnerships. +-5- +Production +The following table shows the Company's net production in Bbls of crude oil and in Mcf of natural gas and the costs and weighted average selling prices thereof, for the last five years. +Year Ended December 31, +2000 +1999 +1998 +1997 +1996 +Production(1): +Oil(MBbls) +109 +8 +8 +9 +7 +Natural Gas (MMcf) +5,737 +3,451 +2,453 +1,810 +1,495 +Equivalent MMcfs(2) +6,391 +3,499 +2,501 +1,864 +1,537 +Average sales price: +Oil (per Bbl) +$29.99 +$18.75 +$10.61 +$16.10 +$16.35 +Natural gas (per Mcf)(3) +$2.74 +$2.46 +$2.46 +$2.88 +$3.04 +Average production cost +(lifting cost) per +equivalent Mcf(4) +$0.66 +$0.69 +$0.61 +$0.65 +$0.63 +---------- +(1) Production as shown in the table is net to the Company and is determined by multiplying the gross production volume of properties in which the Company has an interest by the percentage of the leasehold or other property +interest owned by the Company. +(2) A ratio of energy content of natural gas and oil (six Mcf of natural gas equals one barrel of oil) was used to obtain a conversion factor to convert oil production into equivalent Mcfs of natural gas. +(3) The Company utilizes commodity-based derivative instruments as hedges to manage a portion of its exposure to price volatility of its natural gas sales. The effect of hedges on the average sales price of natural gas for the +years ended December 31, 2000, 1999 and 1998 was $(0.91), $(0.01) and $0.14, respectively. +(4) Production costs represent oil and gas operating expenses as reflected in the financial statements of the Company. +Well Operations +The Company currently operates approximately 1,538 wells in the Appalachian Basin, 209 wells in the Michigan Basin and 277 wells in the Rocky Mountain Region. The Company's ownership interest in these +wells ranges from 0% to 100%, and, on average, the Company has an approximate 52% ownership interest in the wells it operates. Currently these wells produce an aggregate of about 47,000 Mcfe of natural gas per day, including the Company's share of 19,500 +Mcfe per day. +The Company is paid a monthly operating charge for each well it operates for outside owners. The rate is competitive with rates charged by other operators in the area. The charge covers monthly operating +and accounting costs, insurance and other recurring costs. The Company may also receive additional compensation for special non-recurring activities, such as reworks and recompletions. +Transportation +Natural gas wells are connected by pipelines to natural gas markets. Over the years, the Company has developed extensive gathering systems in some of its areas of operations. The Company also continues to +construct new trunklines as necessary to provide for the marketing of natural gas being developed from new areas and to enhance or maintain its existing systems. +The Company is paid a transportation fee for natural gas that is moved by other producers through these pipeline systems. In many cases the Company has been able to receive higher natural gas prices as a result of its ability to move +natural gas to more attractive markets through this pipeline system, to the benefit of both the Company and its investor partners. +-6- +The Company had an Ohio subsidiary, Paramount Natural Gas Company ("PNG"), which commenced operations in October 1992 as a regulated Ohio distribution utility. In 2000, all of the assets of PNG were sold +and the Company ceased operations as an Ohio utility. \ No newline at end of file diff --git a/raw/filings/0000077877/2000/0000077877-01-500003/item13.txt b/raw/filings/0000077877/2000/0000077877-01-500003/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..f17c031312401b7732ca9bea578ba0b22922501f --- /dev/null +++ b/raw/filings/0000077877/2000/0000077877-01-500003/item13.txt @@ -0,0 +1,2 @@ +Item 13. Certain Relationships and Related Transactions +The response to this item is set forth herein in Note 8 in the Notes to Consolidated Financial Statements. \ No newline at end of file diff --git a/raw/filings/0000077877/2000/0000077877-01-500003/item9a.txt b/raw/filings/0000077877/2000/0000077877-01-500003/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2000/0000077877-01-500003/rp_note.txt b/raw/filings/0000077877/2000/0000077877-01-500003/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2000/0000077877-01-500003/rpt_disclosure.txt b/raw/filings/0000077877/2000/0000077877-01-500003/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2001/0000077877-02-000003/filing.txt b/raw/filings/0000077877/2001/0000077877-02-000003/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..f84d8736f91a88a6a222dec1c73eef837e57bc0d --- /dev/null +++ b/raw/filings/0000077877/2001/0000077877-02-000003/filing.txt @@ -0,0 +1,2656 @@ +10-K +1 +pdc200110k1.htm +PDC 2001 10K HTML +CONFORMED COPY +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +[] ANNUAL REPORT PURSUANT TO SECTION 13 or 15 (d) OF +THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2001 +Commission File Number 0-7246 +[] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transaction period from to +PETROLEUM DEVELOPMENT CORPORATION +(Exact name of registrant as specified in its charter) +Nevada +95-2636730 +(State or other jurisdiction of +(I.R.S. Employer +incorporation or organization) +Identification No.) +103 East Main Street, Bridgeport, West Virginia 26330 +(Address of principal executive offices) (zip code) +Registrant's telephone number, including area code (304) 842-3597 +SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: NONE +SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: +Petroleum Development Corporation Common Stock, $.01 par value +(Title of class) +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 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 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. [ ] +As of March 11, 2002, 16,245,752 shares of the Registrant's Common Stock were issued and outstanding, and the aggregate market value of such shares held by non-affiliates of the Registrant on such date was $73,724,093 (based on the last traded price of $6.30). +DOCUMENTS INCORPORATED BY REFERENCE +Document +Form 10-K Part III +Proxy +Items 11 and 12 +PART I +Item 1. Business +The Company is an independent energy company engaged primarily in the development, production and marketing of natural gas and oil. The Company has grown primarily through drilling and development activities, the acquisition of natural gas and oil producing wells and the expansion of its natural gas marketing activities. As of December 31, 2001, the Company operates approximately 2,150 wells located in the Appalachian basin, Michigan, and the Rocky Mountain Region, with gross proved reserves of 328 billion cubic feet equivalent of natural gas ("Bcfe", based on one barrel of oil equals 6 thousand cubic feet equivalent of natural gas ("Mcfe")) of which the Company's share is 131 Bcfe. The wells operated by the Company currently produce an aggregate of approximately 50,000 thousand cubic feet equivalent of gas per day, of which the Company's share is approximately 21,400 Mcfe. +The Company's operations are divided into three regions, the Appalachian Basin, Michigan Basin, and the Rocky Mountain Region. The Company has conducted operations in Appalachian Basin since its inception in 1969, in Michigan Basin since 1997, and the Rocky Mountain Region since 1999. During 2001 approximately 31% of production was generated by Appalachian Basin wells, 34% by Michigan Basin wells and 35% by Rocky Mountain wells. As of the end of 2001, the Company's total proved reserves were located as follows: Appalachian Basin 32%, Michigan Basin 21% and Rocky Mountain Region 47%. The majority of the Company's undeveloped reserves are in the Rocky Mountain Region and the planned drilling for 2002 will be focused in that area. +In all three regions the Company has historically targeted shallow, developmental natural gas reserves for development. In some areas of the Rocky Mountain Region, Michigan and the Appalachian Basin the wells also produce oil in conjunction with natural gas. +The Company owns Riley Natural Gas (RNG), a natural gas marketing company, which aggregates and resells natural gas developed by the Company and other producers. This allows the Company to diversify its operations beyond natural gas drilling and production. RNG has established relationships with many of the natural gas producers in the Appalachian Basin and has significant expertise in the natural gas end-user market. In addition, RNG has extensive experience in the use of hedging strategies, which the Company utilizes to reduce the financial impact on the Company of changes in the price of natural gas. +Since 1984, the Company has sponsored limited partnerships formed to engage in drilling operations. The Company typically retains a 20% ownership interest in these drilling limited partnerships. In 2001, the Company raised $57.1 million through four public drilling partnerships, making it the sponsor of the largest public oil and gas partnership program in the United States in that year. The drilling programs have provided the Company with access to the capital resources necessary to expand its drilling opportunities and to maintain the infrastructure necessary to support such activities. +Industry Overview +Natural gas is the second largest energy source in the United States, after liquid petroleum. The 21.5 Tcf of natural gas consumed in 2001 represented approximately 23% of the total energy used in the United States. Natural gas is consumed in the United States as follows: 42% by industrial end-users as feedstock for products such as plastic and fertilizer or as the energy source for producing products such as glass; 22% and 15% by residential and commercial end-users, respectively, for uses including heating, cooling and cooking; 14% by utilities for the generation of electricity; and the remainder for transportation purposes. (Source U.S. Energy Information Administration) +-2- +The Company believes that the market for natural gas will grow in the future. The demand for natural gas has increased due to four main factors: +- Efficiency. Relative to other energy sources, natural gas losses during transportation from source to destination are slight, averaging only about 9% of the natural gas energy. +- Environmentally favorable. Natural gas is the cleanest and most environmentally safe of the fossil fuels. +- Safety. The delivery of natural gas is among the safest means of distributing energy to customers, as the natural gas transmission system is fixed and is located underground. +- Price. The deregulation of the natural gas industry and a favorable regulatory environment have resulted in end-users' ability to purchase natural gas on a competitive basis from a greater variety of sources. +The Company believes that the foregoing factors, together with the increased availability of natural gas as a form of energy for residential, commercial and industrial uses, should increase the demand for natural gas as well as create new markets for natural gas. +As local supplies of natural gas are inadequate to meet demand, the West Coast and the Northeast import natural gas from producing areas via interstate natural gas pipelines. The cost of transporting natural gas from the major producing areas to markets creates a price advantage for production located closer to the consuming regions. The natural gas industry in the Appalachian Basin and Michigan benefit from proximity to the northeastern United States. +In the early 1980's, natural gas companies began exploiting the northern portion of Michigan's lower peninsula, when certain favorable tax credits for natural gas development were enacted. The result of such development was new advances in drilling technology, which made natural gas drilling in this area profitable even after the expiration of these tax credits. In Michigan's lower peninsula, there is an abundance of shallow Antrim gas shale, which can provide significant reserves per well drilled. Additionally, this area is close to certain end-user markets, which has provided favorable premiums. +During 1998 the Company began to establish a lease position in the Rocky Mountain producing region. The region is believed to hold substantial undeveloped natural gas resources. Recent additions to pipeline capacity in the region have made the area more attractive for development. Gas from the region will generally sell for less than gas in the Appalachian and Michigan Basins, but costs of development are expected to be less. The Company currently has over 200 development locations in Wattenberg field, and 58,000 acres available for development in the Piceance Basin. +Business Strategy +The Company's objective is to expand its natural gas reserves, production and revenues through a strategy that includes the following key elements: +-3- +Expand drilling operations. For its size, the Company has had one of the most active drilling programs in the country. The Company drilled 141 wells in 2001, compared to 97 wells in 2000. The Company believes that it will be able to drill a substantial number of new wells on its current undeveloped leased properties. As of December 31, 2001, the Company had development rights to 4,200 undeveloped acres in the Michigan Basin, 5,400 undeveloped acres in the Appalachian Basin and 125,600 undeveloped acres in the Rocky Mountain Region. As drilling activity increases, the Company benefits as its fixed costs may be spread over a larger number of wells. +Acquire producing properties. The Company's acquisition efforts are focused on properties that fit well within existing operations or that help to build critical mass in areas where the Company is establishing new operations. Acquisitions will likely offer economies in management and administration, and therefore the Company believes that it will be able to acquire more producing wells without incurring substantial increases in its administrative costs. +Pursue geographic expansion. The Company has proven its ability to drill and operate in geographically diverse domestic areas. Since 1996, the Company expanded its operations from the Appalachian Basin, first to Michigan, and more recently to the Rocky Mountains. Currently, the Company's production is divided almost equally among the three areas. The Company plans to conduct the majority of its drilling activities in the Rocky Mountain region during 2002, but will continue to seek additional opportunities for expansion to areas where the Company's experience and expertise can be applied successfully. +Reduce risks inherent in natural gas development and marketing. An integral part of the Company's strategy has been and will continue to be to concentrate on shallow development, (rather than exploratory) drilling, and geographical diversification to reduce risk levels associated with natural gas and oil production. Development drilling is less risky than exploratory drilling and is likely to generate cash returns more quickly. The focus on shallow wells builds on the Company's knowledge and experience, and also provides greater investment diversification than an equal investment in a smaller number of deeper and/or more expensive wells. Geographical diversification can help to offset possible weakness in the natural gas market or disappointing drilling results in one area. The Company believes that successful natural gas marketing is essential to profitable operations in a deregulated gas market. To further this goal, the Company has the expertise of RNG, an experienced natural gas marketer. The Company intends to continue to expand its marketing capabilities to keep pace with the changing natural gas industry. +Exploration and Development Activities +The Company's development activities focus on the identification and drilling of new productive wells and the acquisition of existing producing wells from other producers. +Prospect Generation +The Company's staff of professional geologists is responsible for identifying areas with potential for economic production of natural gas and oil. These geologists have decades of cumulative experience drilling natural gas and oil wells. They utilize results from logs and other tools to evaluate existing wells and to predict the location of attractive new gas reserves. To further this process, the Company has collected and continues to collect logs, core data, production information and other raw data available from state and private agencies, other companies and individuals actively drilling in the regions being evaluated. From this information the geologists develop models of the subsurface structures and stratigraphy that are used to predict areas with above-average prospects for economic development. +-4- +On the basis of these models, the geologists instruct the Company's land department to obtain available natural gas leaseholds in these prospective areas. These leases are then obtained, if possible, by the Company's land department or contract landmen under the direction of the Company's land manager. In most cases, the Company pays a lease bonus and annual rental payments, converting, upon initiation of production, to a royalty on gross production revenue in return for obtaining the leases. In addition overriding royalty payments may be made to third parties in conjunction with the acquisition of drilling rights initially leased by others. As of December 31, 2001, the Company had a total leasehold inventory of approximately 246,080 acres. See--"Properties--Natural Gas Leases." +Drilling Activities +When prospects have been identified and leased, the Company develops these properties by drilling wells. In 2001, the Company drilled a total of 141 wells, with six dry holes. Typically, the Company will act as driller-operator for these prospects, entering into contracts with partnerships, including Company-sponsored partnerships, and other entities that are interested in exploration or development of the prospects. The Company generally retains an interest in each well it drills. See "Financing of Drilling Activities." +Much of the work associated with drilling, completing and connecting wells, including drilling, fracturing, logging and pipeline construction, is performed by subcontractors specializing in those operations, as is common in the industry. A large part of the material and services used by the Company in the development process is acquired through competitive bidding by approved vendors. The Company also directly negotiates rates and costs for services and supplies when conditions indicate that such an approach is warranted. As the prices paid to the Company by its investor partners for the Company's services are frequently fixed before the wells are drilled or are determined solely on the well depth, the Company is subject to the risk that prices of goods or services used in the development process could increase, rendering its contracts with its investor partners less profitable or unprofitable. In addition, problems encountered in the process can substantially increase development costs, sometimes without recourse for the Company to recover its costs from its partners. To minimize these risks, the Company seeks to lock in its development costs in advance of drilling and, when possible, at the time of negotiation and execution of its investor partnership agreements. +Acquisitions of Producing Properties +In addition to drilling new wells, the Company continues to pursue opportunities to purchase existing wells from other producers and greater ownership interests in the wells it operates. Generally, outside interests purchased include a majority interest in the wells and well operations. +During 1999, the Company purchased a 100% working interest in 53 producing wells in the D-J Basin of Colorado which added 3.6 Bcf of natural gas and 370,000 barrels of oil to the Company's reserves. During 2000, the Company purchased 100% of the working interest in 168 producing wells in the DJ Basin of Colorado which added 4.9 Bcf of natural gas and 560,000 barrels of oil to the Company's reserves. Certain well interests in its Company sponsored partnerships were also purchased in 1999, 2000 and 2001. +-5- +Production +The following table shows the Company's net production in Bbls of crude oil and in Mcf of natural gas and the costs and weighted average selling prices thereof, for the last five years. +Year Ended December 31, +2001 +2000 +1999 +1998 +1997 +Production(1): +Oil(MBbls) +195 +109 +8 +8 +9 +Natural Gas (MMcf) +6,085 +5,737 +3,451 +2,453 +1,810 +Equivalent MMcfs(2) +7,255 +6,391 +3,499 +2,501 +1,864 +Average sales price: +Oil (per Bbl) +$22.53 +$29.99 +$18.75 +$10.61 +$16.10 +Natural gas (per Mcf)(3) +$3.53 +$2.74 +$2.46 +$2.46 +$2.88 +Average production cost (lifting cost) +per equivalent Mcf(4) +$0.83 +$0.66 +$0.69 +$0.61 +$0.65 +---------- +(1) Production as shown in the table is net to the Company and is determined by multiplying the gross production volume of properties in which the Company has an interest by the percentage of the leasehold or other property interest owned by the Company. +(2) A ratio of energy content of natural gas and oil (six Mcf of natural gas equals one barrel of oil) was used to obtain a conversion factor to convert oil production into equivalent Mcfs of natural gas. +(3) The Company utilizes commodity-based derivative instruments as hedges to manage a portion of its exposure to price volatility of its natural gas sales. The effect of hedges on the average sales price of natural gas for the years ended December 31, 2001, 2000, 1999 and 1998 was $(0.56), $(0.91), $(0.01) and $0.14, respectively. +(4) Production costs represent oil and gas operating expenses as reflected in the financial statements of the Company. +Well Operations +The Company currently operates approximately 1,523 wells in the Appalachian Basin, 219 wells in the Michigan Basin and 400 wells in the Rocky Mountain Region. The Company's ownership interest in these wells ranges from 0% to 100%, and, on average, the Company has an approximate 51% ownership interest in the wells it operates. Currently these wells produce an aggregate of about 50,000 Mcfe of natural gas per day, including the Company's share of 21,400 Mcfe per day. +The Company is paid a monthly operating charge for each well it operates for outside owners. The rate is competitive with rates charged by other operators in the area. The charge covers monthly operating and accounting costs, insurance and other recurring costs. The Company may also receive additional compensation for special non-recurring activities, such as reworks and recompletions. +Transportation +Natural gas wells are connected by pipelines to natural gas markets. Over the years, the Company has developed extensive gathering systems in some of its areas of operations. The Company also continues to construct new trunklines as necessary to provide for the marketing of natural gas being developed from new areas and to enhance or maintain its existing systems. +The Company is paid a transportation fee for natural gas that is moved by other producers through these pipeline systems. In many cases the Company has been able to receive higher natural gas prices as a result of its ability to move natural gas to more attractive markets through this pipeline system, to the benefit of both the Company and its investor partners. +-6- +Item 2. Properties +Drilling Activity +The following table summarizes the Company's development drilling activity for the years ended December 31, 1997, 1998, 1999, 2000 and 2001. There is no correlation between the number of productive wells completed during any period and the aggregate reserves attributable to those wells. The Company's exploratory wells drilled in the past five years consist of one dry hole (0.19 net) drilled in 1998 and five dry holes (2.44 net) drilled in 1999. +Development Wells Drilled +Total +Productive +Dry +Drilled +Net +Drilled +Net +Drilled +Net +1997 +168 +40.72 +158 +38.00 +10 +2.72 +1998 +212 +56.99 +201 +54.22 +11 +2.77 +1999 +173 +54.64 +165 +53.10 +8 +1.54 +2000 +97 +27.39 +97 +27.39 +- +- +2001 +141 +40.00 +135 +37.94 +6 +2.06 +Total +791 +219.74 +756 +210.65 +35 +9.09 +=== +===== +=== +===== +== +=== +Summary of Productive Wells +The table below shows the number of the Company's productive gross and net wells at December 31, 2001. +Productive Wells +Gas +Oil +Location +Gross +Net +Gross +Net +Colorado +392 +255.91 +- +- +Michigan +212 +113.60 +7 +2.66 +North Dakota +- +- +6 +2.38 +Ohio +16 +7.42 +5 +2.34 +Pennsylvania +532 +163.95 +- +- +Tennessee +1 +0.71 +39 +15.87 +Utah +2 +1.50 +- +- +West Virginia +924 +519.61 +6 +2.58 +Total +2,079 +1,062.70 +63 +25.83 +===== +====== +=== +====== +Reserves +All of the Company's oil and natural gas reserves are located in the United States. The Company's approximate net proved reserves were estimated by Wright & Company, Inc. independent petroleum engineers ("Wright & Company"), to be 118,608,000 Mcf of natural gas and 2,126,000 Bbls of oil at December 31, 2001, 118,640,000 MCf of natural gas and 2,166,000 Bbls of oil at December 31, 2000 and 101,245,000 Mcf of natural gas and 1,154,000 Bbls of oil at December 31, 1999. +The Company's approximate net proved developed reserves were estimated, by Wright & Company to be 88,477,000 Mcf of natural gas and 1,801,000 Bbls of oil at December 31, 2001, 92,131,000 Mcf of natural gas and 1,527,000 Bbls of oil at December 31, 2000 and 82,628,000 Mcf of natural gas and 798,000 Bbls of oil at December 31, 1999. +-7- +The Company's reserves by region are as follows as of December 31, 2001: +Oil +(Mbbl) +Gas +(Mmcf) +MCFE +(Mmcfe) +% +Proved Developed Reserves +Appalachian Basin +35 +42,296 +42,506 +42.81% +Michigan Basin +17 +25,448 +25,550 +25.73% +Rocky Mountain Region +1,749 +20,733 +31,227 +31.46 % +Total Proved Developed Reserves +1,801 +88,477 +99,283 +100.00% +Proved Undeveloped Reserves +Appalachian Basin +0 +0 +0 +0.00% +Michigan Basin +0 +1,488 +1,488 +4.63% +Rocky Mountain Region +325 +28,643 +30,593 +95.37 % +Total Proved Undeveloped +325 +30,131 +32,081 +100.00% +Total Proved Reserves +Appalachian Basin +35 +42,296 +42,506 +32.36% +Michigan Basin +17 +26,936 +27,038 +20.58% +Rocky Mountain Region +2,074 +49,376 +61,820 +47.06 % +Total Proved Reserves +2,126 +118,608 +131,364 +100.00% +No major discovery or other favorable or adverse event that would cause a significant change in estimated reserves is believed by the Company to have occurred since December 31, 2001. Reserves cannot be measured exactly, as reserve estimates involve subjective judgment. The estimates must be reviewed periodically and adjusted to reflect additional information gained from reservoir performance, new geological and geophysical data and economic changes. +The standardized measure of discounted future net cash flows attributable to the Company's proved oil and gas reserves, giving effect to future estimated income tax expenses, was estimated by Wright & Company in 2001, 2000 and 1999 to be $46.4 million as of December 31, 2001, $104.6 million as of December 31, 2000 and $58.5 million as of December 31, 1999. These amounts are based on year-end prices, adjusted for hedging contracts at the respective dates. The values expressed are estimates only, and may not reflect realizable values or fair market values of the natural gas and oil ultimately extracted and recovered. The standardized measure of discounted future net cash flows may not accurately reflect proceeds of production to be received in the future from the sale of natural gas and oil currently owned and does not necessarily reflect the actual costs that would be incurred to acquire equivalent natural gas and oil reserves. +-8- +Net Proved Natural Gas and Oil Reserves +The proved reserves of natural gas and oil of the Company as estimated by Wright & Company at December 31, 2001 are set forth below. These reserves have been prepared in compliance with the rules of the Securities and Exchange Commission (the "SEC") based on year-end prices. An analysis of the change in estimated quantities of natural gas and oil reserves from January 1, 2001 to December 31, 2001, all of which are located within the United States, is shown below: +Natural Gas (Mcf) +Oil (Bbls) +Proved developed and undeveloped reserves: +Beginning of year +118,640,000 +2,166,000 +Revisions of previous estimates +(8,694,000 ) +(176,000 ) +Beginning of year as revised +109,946,000 +1,990,000 +New discoveries and extensions +Rocky Mountain region +23,896,000 +- +Other +- +715,000 +Dispositions to partnerships +(9,263,000) +(384,000) +Acquisitions +Rocky Mountain region +2,000 +- +Appalachian basin +112,000 +- +Production +(6,085,000 ) +(195,000 ) +End of year +118,608,000 +2,126,000 +========== +======== +Proved developed reserves: +Beginning of year +92,131,000 +1,527,100 +========== +======== +End of year +88,477,000 +1,801,000 +========== +======== +Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Natural Gas and Oil Reserves +Summarized in the following table is information for the Company with respect to the standardized measure of discounted future net cash flows relating to proved natural gas and oil reserves. Future cash inflows are computed by applying year-end prices, adjusted for any hedging contracts, of natural gas and oil relating to the Company's proved reserves to year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs, assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the statutory rate in effect at December 31, 2001 to the future pretax net cash flows, less the tax basis of the properties, and gives effect to permanent differences, tax credits and allowances related to the properties. +For the year ended +December 31, 2001 +Future estimated cash flows +$ 317,515,000 +Future estimated production costs +(98,538,000) +Future estimated development costs +(45,323,000) +Future estimated income tax expense +(50,360,000 ) +Future net cash flows +123,294,000 +10% annual discount for estimated timing of cash flows +(76,855,000 ) +Standardized measure of discounted +future estimated net cash flows +$ 46,439,000 +========= +-9- +The following table summarizes the principal sources of change in the standardized measure of discounted future estimated net cash flows from January 1, 2001 through December 31, 2001: +Sales of oil and natural gas production, net of production costs +$(19,876,000) +Net changes in prices and production costs +(140,487,000) +Extensions, discoveries and improved recovery, less related costs +25,942,000 +Dispositions to partnerships +(28,935,000) +Acquisitions +189,000 +Development costs incurred during the period +35,412,000 +Revisions of previous quantity estimates +(23,818,000) +Changes in estimated income taxes +30,622,000 +Accretion in discount +62,751,000 +$(58,200,000 ) +========= +The foregoing data should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves, as the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision, and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods and the limitations inherent therein. +Substantially all of the Company's natural gas and oil reserves have been mortgaged or pledged as security for the Company's credit agreement. See Note 3 of Notes to Consolidated Financial Statements. +Natural Gas Leases +The following table sets forth, as of December 31, 2001, the acres of developed and undeveloped oil and natural gas acreage leased and available to the Company, listed alphabetically by state. +Developed +Acreage +Undeveloped +Acreage +Colorado +15,900 +106,200 +Michigan +27,700 +4,200 +North Dakota +2,300 +3,400 +Ohio +740 +- +Pennsylvania +9,000 +2,900 +Tennessee +5,400 +- +Utah +640 +16,000 +West Virginia +49,200 +2,500 +Total +110,880 +135,200 +====== +====== +Title to Properties +The Company believes that it holds good and indefeasible title to its properties, in accordance with standards generally accepted in the natural gas industry, subject to such exceptions stated in the opinion of counsel employed in the various areas in which the Company conducts its exploration activities, which exceptions, in the Company's judgment, do not detract substantially from the use of such property. As is customary in the natural gas industry, only a perfunctory title examination is conducted at the time the properties believed to be suitable for drilling operations are acquired by the Company. Prior to the commencement of drilling operations, an extensive title examination is conducted and curative work is performed with respect to defects which the Company deems to be significant. A title examination has been performed with respect to substantially all of the Company's producing properties. No single property owned by the Company represents a material portion of the Company's holdings. +-10- +The properties owned by the Company are subject to royalty, overriding royalty and other outstanding interests customary in the industry. The properties are also subject to burdens such as liens incident to operating agreements, current taxes, development obligations under natural gas and oil leases, farm-out arrangements and other encumbrances, easements and restrictions. The Company does not believe that any of these burdens will materially interfere with the use of the properties. +Natural Gas Sales +Natural gas is sold by the Company under contracts with terms ranging from one month to three years. Virtually all of the Company's contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. As a result, the Company's revenues from the sale of natural gas will suffer if market prices decline and benefit if they increase. The Company believes that the pricing provisions of its natural gas contracts are customary in the industry. +The Company sells its natural gas to industrial end-users and utilities. One customer, Cinnabar Energy Services, accounted for 25.2% and 17.7% of the Company's revenues from oil and gas sales (13.1% and 11.3% of total revenues) in 2001 and 2000, respectively. No customer accounted for more than 10.0% of total revenues in 1999. No other single purchaser of the Company's natural gas accounted for 10% or more of the Company's total revenues during 2001, 2000 or 1999. +At December 31, 2001, natural gas produced by the Company sold at prices per Mcf ranging from $0.90 to $6.15, depending upon well location, the date of the sales contract and other factors. The weighted net average price of natural gas sold by the Company during 2001 was $3.53 per Mcf. +In general, the Company, together with its marketing subsidiary, RNG, has been and expects to continue to be able to produce and sell natural gas from its wells without curtailment by providing natural gas to purchasers at competitive prices. Open access transportation on the country's interstate pipeline system has greatly increased the range of potential markets. Whenever feasible the Company allows for multiple market possibilities from each of its gathering systems, while seeking the best available market for its natural gas at any point in time. +Natural Gas Marketing +The Company's natural gas marketing activities involve the aggregation and reselling of natural gas produced by the Company and others. The Company believes that in a deregulated market, successful natural gas marketing is essential to profitable operations. A variety of factors affect the market for natural gas, including the availability of other domestic production, natural gas imports, the availability and price of alternative fuels, the proximity and capacity of natural gas pipelines, general fluctuations in the supply and demand for natural gas and the effects of state and federal regulations on natural gas production and sales. The natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual customers. +RNG, a wholly owned subsidiary, is a natural gas marketing company that specializes in the acquisition, aggregation and marketing of natural gas production in the Company's operating areas. RNG markets natural gas produced by the Company and also purchases natural gas from other producers and resells to utilities, end users or other marketers. The employees of RNG have extensive knowledge of natural gas markets in the Company's areas of operations. Such knowledge assists the Company in maximizing its prices as it markets natural gas from Company-operated wells. The gas is marketed to natural gas utilities, pipelines and industrial and commercial customers, either directly through the Company's gathering system, or utilizing transportation services provided by regulated interstate pipeline companies. +-11- +Hedging Activities +The Company utilizes commodity-based derivative instruments as hedges to manage a portion of its exposure to price volatility stemming from its natural gas sales and marketing activities. These instruments consist of NYMEX-traded natural gas futures and option contracts. The contracts hedge committed and anticipated natural gas purchases and sales, generally forecasted to occur within a three to twelve-month period. Company policy prohibits the use of natural gas futures or options for speculative purposes and permits utilization of hedges only if there is an underlying physical position. +The Company has extensive experience with the use of financial hedges to reduce the risk and impact of natural gas price changes. These hedges are used by RNG to coordinate fixed and variable priced purchases and sales, and by the Company to "lock in" fixed prices from time to time for the Company's share of production. In order for future contracts to serve as effective hedges, there must be sufficient correlation to the underlying hedged transaction. While hedging can help provide price protection if spot prices drop, hedges can also limit upside potential. +For unhedged natural gas sales not subject to fixed price contracts, the Company is subject to price fluctuations for natural gas sold in the spot market. The Company continues to evaluate the potential for reducing these risks by entering into hedge transactions. In addition, the Company may also close out any portion of hedges that may exist from time to time. +Financing of Drilling Activities +The Company conducts development drilling activities for its own account and for other investors. In 1984, the Company began sponsoring private drilling limited partnerships, and, in 1989, the Company began to register the partnership interests offered under public drilling programs with the SEC. The Company's public partnerships had $57.1 million in subscriptions in 2001, $55.6 million in 2000 and $36.1 million in 1999. The Company generally invests, as its equity contribution to each drilling partnership, an additional sum approximating 20% of the aggregate subscriptions received for that particular drilling partnership. As a result, the Company is subject to substantial cash commitments at the closing of each drilling partnership. The funds received from these programs are restricted to use in future drilling operations. While funds were received by the Company pursuant to drilling contracts in the years indicated, the Company recognizes revenues from drilling operations on the percentage of completion method as the wells are drilled, rather than when funds are received. Most of the Company's drilling and development funds now are received from partnerships in which the Company serves as managing general partner. However, because wells produce for a number of years, the Company continues to serve as operator for a large number of unaffiliated parties. In addition to the partnership structure, the Company also utilizes joint venture arrangements for financing drilling activities. +The financing process begins when the Company enters into a development agreement with an investor partner, pursuant to which the Company agrees to assign its rights in the property to be drilled to the partnership or other entity. The partnership or other entity thereby becomes owner of a working interest in the property. +-12- +The Company's development contracts with its investor partners have historically taken many different forms. Generally the agreements can be classified as on a "footage-based" rate, whereby the Company receives drilling and completion payments based on the depth of the well; "cost-plus," in which the Company is reimbursed for its actual cost of drilling plus some additional amount for overhead and profit; or "turnkey," in which a specified amount is paid for drilling and another amount for completion. As part of the compensation for its services, the Company also has received some interest in the production from the well in the form of an overriding royalty interest, working interest or other proportionate share of revenue or profits. The Company's development contracts may provide for a combination of several of the foregoing payment options. Basic drilling and completion operations are performed on a footage-based rate, with leases and gathering pipelines being contributed at Company cost. The Company may also purchase a working interest in the subject properties. +The level of the Company's drilling and development activity is dependent upon the amount of subscriptions in its public drilling partnerships and investments from other partnerships or other joint venture partners. The use of partnerships and similar financing structures enables the Company to diversify its holdings, thereby reducing the risks of its development investments. Additionally, the Company benefits through such arrangements by its receipt of fees for its management services and/or through an increased share in the revenues produced by the developed properties. The Company believes that investments in drilling activities, whether through Company-sponsored partnerships or other sources, are influenced in part by the favorable treatment that such investments enjoy under the federal income tax laws. No assurance can be given that the Company will continue to have access to funds generated through these financing vehicles. +Oil Production +The Company's acquisition in December 1999 of 53 wells and in April 2000 of 108 wells in the Wattenberg field in Colorado and ongoing development activities in the Rocky Mountains added to oil production and reserves. At the end of 2001 oil was about 10% of the Company's total equivalent reserves. Oil production in 2001 was 195,000 barrels, up from 109,000 in 2000 and up from 8,000 barrels in 1999. +The Company is currently able to sell all the oil that it can produce under existing sales contracts with petroleum refiners and marketers. The Company does not refine any of its oil production. The Company's crude oil production is sold to purchasers at or near the Company's wells under short-term purchase contracts at prices and in accordance with arrangements that are customary in the oil industry. No single purchaser of the Company's crude oil accounted for 10% or more of the Company's revenues from oil and gas sales in 2001, 2000 or 1999. At December 31, 2001, oil produced by the Company sold at prices ranging from $12.75 to $18.75 per barrel, depending upon the location and quality of oil. In 2001, the weighted net average price per barrel of oil sold by the Company was $22.53. +Oil production is subject to many of the same operating hazards and environmental concerns as natural gas production, but is also subject to the risk of oil spills. Federal regulations require certain owners or operators of facilities that store or otherwise handle oil, such as the Company, to procure and implement spill prevention, control, counter-measures and response plans relating to the possible discharge of oil into surface waters. The Oil Pollution Act of 1990 ("OPA") subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from oil spills. Noncompliance with OPA may result in varying civil and criminal penalties and liabilities. Operations of the Company are also subject to the Federal Clean Water Act and analogous state laws relating to the control of water pollution, which laws provide varying civil and criminal penalties and liabilities for release of petroleum or its derivatives into surface waters or into the ground. +-13- +Governmental Regulation +The Company's business and the natural gas industry in general are heavily regulated. The availability of a ready market for natural gas production depends on several factors beyond the Company's control. These factors include regulation of natural gas production, federal and state regulations governing environmental quality and pollution control, the amount of natural gas available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. State and federal regulations generally are intended to prevent waste of natural gas, protect rights to produce natural gas between owners in a common reservoir and control contamination of the environment. Pipelines are subject to the jurisdiction of various federal, state and local agencies. The Company takes the steps necessary to comply with applicable regulations both on its own behalf and as part of the services it provides to its investor partnerships. The Company believes that it is in substantial compliance with such statutes, rules, regulations and governmental orders, although there can be no assurance that this is or will remain the case. The following discussion of the regulation of the United States natural gas industry is not intended to constitute a complete discussion of the various statutes, rules, regulations and environmental orders to which the Company's operations may be subject. +Regulation of Oil and Natural Gas Exploration and Production +The Company's oil and natural gas operations are subject to various types of regulation at the federal, state and local levels. Prior to commencing drilling activities for a well, the Company must procure permits and/or approvals for the various stages of the drilling process from the applicable state and local agencies in the state in which the area to be drilled is located. Such permits and approvals include those for the drilling of wells, and such regulation includes maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties on which wells are drilled, the plugging and abandoning of wells and the disposal of fluids used in connection with operations. The Company's operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units and the density of wells which may be drilled and the unitization or pooling of natural gas properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely primarily or exclusively on voluntary pooling of lands and leases. In areas where pooling is voluntary, it may be more difficult to form units, and therefore, more difficult to develop a project if the operator owns less than 100% of the leasehold. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations may limit the amount of oil and natural gas the Company can produce from its wells and may limit the number of wells or the locations at which the Company can drill. The regulatory burden on the oil and natural gas industry increases the Company's costs of doing business and, consequently, affects its profitability. In as much as such laws and regulations are frequently expanded, amended and reinterpreted, the Company is unable to predict the future cost or impact of complying with such regulations. +Regulation of Sales and Transportation of Natural Gas +Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 (the "NGPA") and the regulations promulgated thereunder by FERC. Maximum selling prices of certain categories of natural gas sold in "first sales," whether sold in interstate or intrastate commerce, were regulated pursuant to the NGPA. The Natural Gas Wellhead Decontrol Act (the "Decontrol Act") removed, as of January 1, 1993, all remaining federal price controls from natural gas sold in "first sales" on or after that date. FERC's jurisdiction over natural gas transportation was unaffected by the Decontrol Act. While sales by producers of natural gas and all sales of crude oil, condensate and natural gas liquids can currently be made at market prices, Congress could reenact price controls in the future. +-14- +The Company's sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive regulation. In recent years, FERC has undertaken various initiatives to increase competition within the natural gas industry. As a result of initiatives like FERC Order No.636, issued in April 1992, the interstate natural gas transportation and marketing system has been substantially restructured to remove various barriers and practices that historically limited non-pipeline natural gas sellers, including producers, from effectively competing with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. The most significant provisions of Order No.636 require that interstate pipelines provide transportation separate or "unbundled" from their sales service, and require that pipelines provide firm and interruptible transportation service on an open access basis that is equal for all natural gas suppliers. In many instances, the result of Order No.636 and related initiatives have been to substantially reduce or eliminate the interstate pipelines' traditional role as wholesalers of natural gas in favor of providing only storage and transportation services. Another effect of regulatory restructuring is the greater transportation access available on interstate pipelines. In some cases, producers and marketers have benefited from this availability. However, competition among suppliers has greatly increased and traditional long-term producer-pipeline contracts are rare. Furthermore, gathering facilities of interstate pipelines are no longer regulated by FERC, thus allowing gatherers to charge higher gathering rates. +Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC, state commissions 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 FERC and Congress will continue. The Company cannot determine to what extent future operations and earnings of the Company will be affected by new legislation, new regulations, or changes in existing regulation, at federal, state or local levels. +Environmental Regulations +The Company's operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stricter environmental legislation and regulations could continue. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the natural gas industry in general, the business and prospects of the Company could be adversely affected. +The Company generates wastes that may be subject to the Federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes. The U.S. Environmental Protection Agency ("EPA") and various state agencies have limited the approved methods of disposal for certain hazardous and nonhazardous wastes. Furthermore, certain wastes generated by the Company's operations that are currently exempt from treatment as "hazardous wastes" may in the future be designated as "hazardous wastes," and therefore be subject to more rigorous and costly operating and disposal requirements. +The Company currently owns or leases numerous properties that for many years have been used for the exploration and production of oil and natural gas. Although the Company believes that it has utilized good operating and waste disposal practices, prior owners and operators of these properties may not have utilized similar practices, and hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by the Company or on or under locations where such wastes have been taken for disposal. These properties and the wastes disposed thereon may be subject to the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), RCRA and analogous state laws as well as state laws governing the management of oil and natural gas wastes. Under such laws, the Company 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) or to perform remedial plugging operations to prevent future contamination. +-15- +CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed of or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for release of 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, and 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. +The Company's operations may be subject to the Clean Air Act ("CAA") and comparable state and local requirements. Amendments to the CAA were adopted in 1990 and contain provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from the operations of the Company. The EPA and states have been developing regulations to implement these requirements. The Company may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues. +The Company's expenses relating to preserving the environment during 2001 were not significant in relation to operating costs and the Company expects no material change in 2002. Environmental regulations have had no materially adverse effect on the Company's operations to date, but no assurance can be given that environmental regulations will not, in the future, result in a curtailment of production or otherwise have a materially adverse effect on the Company's business, financial condition or results of operations. +As a matter of corporate policy and commitment, the Company attempts to minimize the adverse environmental impact of all its operations. During the 1990's, the Company was a nine-time recipient of the West Virginia Department of Environmental Protection's top award in recognition of the quality of the Company's environmental and reclamation work in its drilling activities. +Operating Hazards and Insurance +The Company's exploration and production operations include a variety of operating risks, including the risk of fire, explosions, blowouts, craterings, pipe failure, casing collapse, abnormally pressured formations, and environmental hazards such as gas leaks, ruptures and discharges of toxic gas, the occurrence of any of which could result in substantial losses to the Company due to injury and loss of life, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. The Company's pipeline, gathering and distribution operations are subject to the many hazards inherent in the natural gas industry. These hazards include damage to wells, pipelines and other related equipment, and surrounding properties caused by hurricanes, floods, fires and other acts of God, inadvertent damage from construction equipment, leakage of natural gas and other hydrocarbons, fires and explosions and other hazards that could also result in personal injury and loss of life, pollution and suspension of operations. +Any significant problems related to its facilities could adversely affect the Company's ability to conduct its operations. In accordance with customary industry practice, the Company maintains insurance against some, but not all, potential risks; however, there can be no assurance that such insurance will be adequate to cover any losses or exposure for liability. The occurrence of a significant event not fully insured against could materially adversely affect the Company's operations and financial condition. The Company cannot predict whether insurance will continue to be available at premium levels that justify its purchase or whether insurance will be available at all. +-16- +Competition +The Company believes that its exploration, drilling and production capabilities and the experience of its management generally enable it to compete effectively. The Company encounters competition from numerous other oil and natural gas companies, drilling and income programs and partnerships in all areas of its operations, including drilling and marketing natural gas and obtaining desirable natural gas leases. Many of these competitors possess larger staffs and greater financial resources than the Company, which may enable them to identify and acquire desirable producing properties and drilling prospects more economically. The Company's ability to explore for oil and natural gas prospects and to acquire additional properties in the future depends upon its ability to conduct its operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. The Company competes with a number of other companies which offer interests in drilling partnerships with a wide range of investment objectives and program structures. Competition for investment capital for both public and private drilling programs is intense. The Company also faces intense competition in the marketing of natural gas from competitors including other producers as well as marketing companies. Also, international developments and the possible improved economics of domestic natural gas exploration may influence other companies to increase their domestic oil and natural gas exploration. Furthermore, competition among companies for favorable prospects can be expected to continue, and it is anticipated that the cost of acquiring properties may increase in the future. Factors affecting competition in the natural gas industry include price, location, availability, quality and volume of natural gas. The Company believes that it can compete effectively in the oil and natural gas industry on each of the foregoing factors. Nevertheless, the Company's business, financial condition or results of operations could be materially adversely affected by competition. +Employees +As of December 31, 2001, the Company had 90 employees, including 15 in finance, and data processing, 6 in administration, 14 in exploration and development, 50 in production and 5 in natural gas marketing. The Company's engineers, supervisors and well tenders are generally responsible for the day-to-day operation of wells and pipeline systems. In addition, the Company retains subcontractors to perform drilling, fracturing, logging, and pipeline construction functions at drilling sites. The Company's employees act as supervisors of the subcontractors. +The Company's employees are not covered by a collective bargaining agreement. The Company considers relations with its employees to be excellent. +Facilities +The Company owns and occupies three buildings in Bridgeport, West Virginia, two of which serve as the Company's headquarters and one which serves as a field operating site. The Company also owns a field operating building in Gilmer County, West Virginia. The Company leases field operating offices in Colorado, Michigan and Pennsylvania under operating leases. The Company believes that its current facilities are sufficient for its current and anticipated operations. +Item 3. Legal Proceedings +From time to time the Company is a party to various legal proceedings in the ordinary course of business. The Company is not currently a party to any litigation that it believes would materially affect the Company's business, financial condition or results of operations. +Item 4. Submission of Matters to a Vote of Security Holders +No matters were submitted to a vote of security holders during the fourth quarter of the fiscal year covered by this report. +-17- +PART II +Item 5. Market for the Company's Common Stock and Related Security Holder Matters +The common stock of the Company is traded in the over-the-counter market under the symbol PETD. The following table sets forth, for the periods indicated, the high and low bid quotations per share of the Company's common stock in the over-the-counter market, as reported by the National Quotation Bureau Incorporated. These quotations represent inter-dealer prices without retail markups, markdowns, commissions or other adjustments and may not represent actual transactions. +High +Low +2001 +First Quarter +7 15/16 +5 23/32 +Second Quarter +8 27/32 +5 15/16 +Third Quarter +6 15/32 +4 3/8 +Fourth Quarter +6 19/64 +4 23/32 +2000 +First Quarter +4 29/64 +3-3/4 +Second Quarter +6 1/32 +3-7/8 +Third Quarter +7 1/8 +4 23/32 +Fourth Quarter +7 +5 3/16 +As of December 31, 2001, there were approximately 1,194 record holders of the Company's common stock. +The Company has not paid any dividends on its common stock and currently intends to retain earnings for use in its business. Therefore, it does not expect to declare cash dividends in the foreseeable future. Further, the Company's Credit Agreement restricts the payment of dividends. +-18- +Item 6. Selected Financial Data (1) +Year Ended December 31, +2001 +2000 +1999 +1998 +1997 +Revenues +Oil and gas well +drilling operations +$76,291,200 +$43,194,700 +$42,115,600 +$40,447,100 +$34,405,400 +Oil and gas sales +92,095,300 +90,419,700 +46,988,100 +35,560,300 +33,390,200 +Well operations income +5,604,200 +5,061,600 +5,314,500 +4,581,000 +4,509,300 +Other income +3,132,400 +2,540,500 +2,392,400 +2,385,200 +1,573,100 +Total +$177,123,100 +$141,216,500 +$96,810,600 +$82,973,600 +$73,878,000 +========= +========= +========= +========= +======== +Costs and Expenses (excluding +interest and depreciation, +depletion and amortization) +$144,468,600 +$118,813,300 +$82,496,500 +$71,094,900 +$61,219,600 +========= +========= +========= +========= +======== +Interest Expense +$ 993,400 +$1,186,000 +$ 182,400 +$ - +$ 315,900 +========= +========= +========= +========= +======== +Depreciation, depletion and +amortization +$10,578,300 +$6,943,500 +$ 4,031,200 +$ 3,253,600 +$ 2,660,300 +========= +========= +========= +========= +======== +Net Income +$14,967,800 +$10,681,000 +$ 7,824,300 +$ 6,658,000 +$ 7,586,800 +========= +========= +========= +========= +======== +Basic earnings per common +share +$.92 +$.66 +$.50 +$.43 +$ .67 +== +== +== +== +Diluted earnings per share +$.90 +$.65 +$.48 +$.41 +$ .67 +== +== +== +== +== +Average Common and Common +Equivalent Shares Outstanding +During the Year +16,639,634 +16,437,488 +16,286,852 +16,338,298 +12,540,165 +========= +========= +========= +========= +======== +December 31, +2001 +2000 +1999 +1998 +1997 +Total Assets +$199,852,100 +$187,684,500 +$132,083,600 +$111,409,000 +$98,411,600 +========= +========= +========= +========= +======== +Working Capital +$ 3,419,600 +$ 780,700 +$ (2,503,900) +$ 1,633,400 +$16,483,200 +========= +========= +========= +========= +======== +Long-Term Debt, excluding +current maturities +$ 28,000,000 +$ 17,350,000 +$ 9,300,000 +$ - +$ - +========= +========= +========= +========= +======== +Stockholders' Equity +$ 96,772,800 +$ 82,256,900 +$70,724,900 +$ 62,746,700 +$55,766,100 +========= +========= +========= +========= +======== +See Consolidated Financial Statements elsewhere herein. +-19- +Item 7. Management's Discussion and Analysis of Financial Condition and +Results of Operations +Safe Harbor Statement Under the Private Securities +Litigation Reform Act of 1995 +Statements, other than historical facts, contained in this Annual Report on Form 10-K, including statements of estimated oil and gas production and reserves, drilling plans, future cash flows, anticipated capital expenditures and Management's strategies, plans and objectives, are "forward looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Although the Company believes that its forward looking statements are based on reasonable assumptions, it cautions that such statements are subject to a wide range of risks and uncertainties incidental to the exploration for, acquisition, development and marketing of oil and gas, and it can give no assurance that its estimates and expectations will be realized. Important factors that could cause actual results to differ materially from the forward looking statements include, but are not limited to, changes in production volumes, worldwide demand, and commodity prices for petroleum natural resources; the timing and extent of the Company's success in discovering, acquiring, developing and producing oil and gas reserves; risks incident to the drilling and operation of oil and gas wells; future production and development costs; the effect of existing and future laws, governmental regulations and the political and economic climate of the United States; the effect of hedging activities; and conditions in the capital markets. Other risk factors are discussed elsewhere in this Form 10-K. +Results of Operations +Year Ended December 31, 2001 Compared with December 31, 2000 +Revenues. Total revenues for the year ended December 31, 2001 were $177.1 million compared to $141.2 million for the year ended December 31, 2000, an increase of approximately $35.9 million, or 25.4%. Drilling revenues for the year ended December 31, 2001 were $76.3 million compared to $43.2 for the year ended December 31, 2000, an increase of approximately $33.1 million, or 76.6%. Such increase was due to an increase in drilling and completion activities, which was a direct result of an increase in the availability of drilling rigs which allowed us to reduce the drilling backlog from $43.8 million as of December 31, 2000 to $31.6 million as of December 31, 2001. Natural gas sales from the marketing activities of RNG for the year ended December 31, 2001 were $66.2 million compared to $71.4 million for the year ended December 31, 2000, a decrease of approximately $5.2 million or 7.3%. Such decrease was due to decreased volumes of natural gas sold. Oil and gas sales from the Company's producing properties for the year ended December 31, 2001 were $25.9 million compared to $19.0 million for the year ended December 31, 2000, an increase of approximately $6.9 million or 36.3%. Such increase was due to increased production of producing properties along with new wells drilled and higher average sales prices of natural gas offset in part by lower average oil sales prices from the Company's producing properties. Financial results depend upon many factors, particularly the price of natural gas and our ability to market our production on economically attractive terms. Price volatility in the natural gas market has remained prevalent in the last few years. From late 1998 through the first quarter of 1999, we experienced a decline in energy commodity prices. However, in the summer of 2000 and continuing into 2001, prices improved. For the months of April, 2000 through October, 2001, we had certain natural gas hedges in place that prevented us from realizing the full impact of this price environment. Despite this limitation, our realized natural gas sales price for the year ended December 31, 2001 was $3.53 per Mcf compared to $2.74 for the year ended December 31, 2000. In the final months of 2000 and the first quarter of 2001, the NYMEX futures market reported unprecedented natural gas contract prices. During the year ended December 31, 2001, the hedging activities resulted in oil and gas sales being $3.4 million lower than if the Company had not hedged. As of December 31, 2001, the Company has no hedges or option contracts in place for its oil and gas production. RNG in its normal course of business has natural gas hedges and option contracts as of December 31, 2001. However, based on its gas marketing activities, hedging and option contracts did not have a significant impact on RNG's net margins from gas marketing activities in 2001. Well operations and pipeline income for the year ended December 31, 2001 was $5.6 million compared to $5.1 million for the year ended December 31, 2000, an increase of approximately $500,000 or 9.8%. Such increase resulted from an increase in the number of wells operated by the Company. Other income for the year ended December 31, 2001 was $3.1 million compared to $2.5 million for the year ended December 31, 2000, an increase of approximately $600,000 or 24.0%. Such increase resulted from interest earned on higher average cash balances. +20 +Costs and expenses. Costs and expenses for the year ended December 31, 2001 were $156.0 million compared to $126.9 million for the year ended December 31, 2000, an increase of approximately $29.1 million, or 22.9%. Oil and gas well drilling operations costs for the year ended December 31, 2001 were $66.0 million compared to $35.2 million for the year ended December 31, 2000, an increase of approximately $30.8 million or 87.5%. Such increase was due to the increased drilling activity referred to above. The costs of gas marketing activities of RNG for the year ended December 31, 2001 were $65.7 million compared to $71.6 million for the year ended December 31, 2000, a decrease of $4.9 million or 6.8%. Such decrease was due to lower volumes of natural gas purchased for resale. Based on the nature of RNG's gas marketing activities, hedging and option contracts did not have a significant impact on RNG's net margins from marketing activities during 2001. Oil and gas production costs from the Company's producing properties for the year ended December 31, 2001 were $8.6 million compared to $8.3 million for the year ended December 31, 2000 an increase of approximately $300,000 or 3.6%. General and administrative expenses for the year ended December 31, 2001 were $4.1 million compared to $3.6 million for the year ended December 31, 2000, an increase of approximately $500,000. Depreciation, depletion and amortization costs for the year ended December 31, 2001 were $10.6 million compared to $6.9 million for the year ended December 31, 2000, an increase of approximately $3.7 million or 53.6%. Such increase was due to the increased amount of production and investment in oil and gas properties owned by the Company. Interest costs for the year ended December 31, 2001 were $1.0 million compared to $1.2 million for the year ended December 31, 2000 a decrease of approximately $200,000. Such decrease was due to lower average debt balances along with lower average interest rates. +Net income. Net income for the year ended December 31, 2001 was $15.0 million compared to $10.7 million for the year ended December 31, 2000, an increase of approximately $4.3 million or 40.2%. +Year Ended December 31, 2000 Compared with December 31, 1999 +Revenues. Total revenues for the year ended December 31, 2000 were $141.2 million compared to $96.8 million for the year ended December 31, 1999, an increase of approximately $44.4 million, or 45.9%. Drilling revenues for the year ended December 31, 2000 were $43.2 million compared to $42.1 for the year ended December 31, 1999, an increase of approximately $1.1 million, or 2.6%. Natural gas sales from the marketing activities of RNG for the year ended December 31, 2000 were $71.4 million compared to $38.4 million for the year ended December 31, 1999, an increase of approximately $33.0 million or 85.9%. Such increase was due to increased volumes of gas sold with higher average sales prices. Oil and gas sales from the Company's producing properties for the year ended December 31, 2000 were $19.0 million compared to $8.6 million for the year ended December 31, 1999, an increase of approximately $10.4 million or 120.9%. Such increase was due to increased production which resulted from acquisitions of producing properties along with new wells drilled and higher average sales prices of natural gas and oil from the Company's producing properties. Financial results depend upon many factors, particularly the price of natural gas and our ability to market our production on economically attractive terms. Price volatility in the natural gas market has remained prevalent in the last few years. From the third quarter of 1998 through the first quarter of 1999, we experienced a decline in energy commodity prices. However, in the summer of 1999 and continuing into early 2000, prices improved. For the months of April through December, 2000, we had certain natural gas hedges in place that prevented us from realizing the full impact of this price environment. Despite this limitation, our realized natural gas price for each month in the year 2000 was higher than the previous year. In the final months of 2000, the NYMEX futures market reported unprecedented natural gas contract prices. During 2000, the hedging activities resulted in oil and gas sales being $5.2 million lower than if the Company had not hedged. Well operations and pipeline income for the year ended December 31, 2000 was $5.1 million compared to $5.3 million for the year ended December 31, 1999, a decrease of approximately $200,000 or 3.8%. Other income for the year ended December 31, 2000 was $2.5 million compared to $2.4 million for the year ended December 31, 1999, an increase of approximately $100,000 or 4.2%. +Costs and expenses. Costs and expenses for the year ended December 31, 2000 were $126.9 million compared to $86.7 million for the year ended December 31, 1999, an increase of approximately $40.2 million, or 46.4%. Oil and gas well drilling operations costs for the year ended December 31, 2000 were $35.2 million compared to $35.5 million for the year ended December 31, 1999, a decrease of approximately $300,000 or 0.8%. +21 +The costs of gas marketing activities for the year ended December 31, 2000 were $71.6 million compared to $38.5 million for the year ended December 31, 1999, an increase of $33.1 million or 86.0%. Such increase was due to the increased gas marketing activity of RNG with increased volumes purchased at higher average sale prices. Based on the nature of the Company's gas marketing activities, hedging did not have a significant impact on the Company's net margins from marketing activities during 2000. Oil and gas production costs from the Company's producing properties for the year ended December 31, 2000 were $8.3 million compared to $5.7 million for the year ended December 31, 1999 an increase of $2.6 million or 45.6%. Such increase was due to the increased production volumes from the Company's producing properties. General and administrative expenses for the year ended December 31, 2000 were $3.6 million compared to $2.8 million for the year ended December 31, 1999, an increase of approximately $800,000. Depreciation, depletion and amortization costs for the year ended December 31, 2000 were $6.9 million compared to $4.0 million for the year ended December 31, 1999, an increase of approximately $2.9 million or 72.5%. Such increase was due to the increased amount of investment in oil and gas properties owned by the Company. Interest costs for the year ended December 31, 2000 were $1.2 compared to $200,000 for the year ended December 31, 1999 an increase of approximately $1.0 million. The increase was due to the Company utilizing its credit agreement to purchase oil and gas properties. +Net income. Net income for the year ended December 31, 2000 was $10.7 million compared to $7.8 million for the year ended December 31, 1999, an increase of approximately $2.9 million or 37.2%. +Liquidity and Capital Resources +The Company funds its operations through a combination of cash flow from operations, capital raised through stock offerings and drilling partnerships, and use of the Company's credit facility. Operational cash flow is generated by sales of natural gas from the Company's well interests, well drilling and operating activities for the Company's investor partners, and natural gas marketing. Cash payments from Company-sponsored partnerships are used to drill and complete wells for the partnerships, with operating cash flow accruing to the Company to the extent payments exceed drilling costs. The Company utilizes its revolving credit arrangement to meet the cash flow requirements of its operating and investment activities. +Sales volumes of natural gas have continued to increase while natural gas prices fluctuate monthly. The Company's natural gas sales prices are subject to increase and decrease based on various market-sensitive indices. A major factor in the variability of these indices is the seasonal variation of demand for the natural gas, which typically peaks during the winter months. The volumes of natural gas sales are expected to continue to increase as a result of continued drilling activities and additional investment by the Company in oil and gas properties. The Company utilizes commodity-based derivative instruments (natural gas futures and option contracts traded on the NYMEX) as hedges to manage a portion of its exposure to this price volatility. The futures contracts hedge committed and anticipated natural gas purchases and sales, generally forecasted to occur within a three to twelve-month period. +The Company has a bank credit agreement with Bank One, which provides a borrowing base of $40.0 million, subject to adequate oil and natural gas reserves. As of December 31, 2001, the balance outstanding on the line of credit is $28 million of which $10 million was subject to an interest rate swap at a rate of 8.39% and the remaining $18 million was subject to prime rate of 4.75%. The line of credit is at prime, with LIBOR (London Interbank Market Rate) alternatives available at the discretion of the Company. No principal payments are required until the credit agreement expires on December 31, 2004. +The Company closed four public drilling partnerships during 2001. The total amount received during 2001 was $57.1 million compared to $55.6 million for 2000. The Company closed its fourth program of 2001 on December 31, 2001 in the amount of $24.4 million and will drill the wells during the first quarter 2002. The Company generally invests, as its equity contribution to each drilling partnership, an additional sum approximating 20% of the aggregate subscriptions received for that particular drilling partnership. As a result, the Company is subject to substantial cash commitments at the closing of each drilling partnership. The funds received from these programs are restricted to use in future drilling operations. No assurance can be made that the Company will continue to receive this level of funding from these or future programs. +22 +Substantially all of the Company's drilling programs contain a repurchase provision where Investors may tender their partnership units for repurchase at any time beginning with the third anniversary of the first cash distribution. The provision provides that the Company is obligated to purchase an aggregate of 10% of the initial subscriptions per calendar year (at a minimum price of four times the most recent 12 months' cash distributions), only if such units are tendered, subject to the Company's financial ability to do so. The maximum annual 10% repurchase obligation, if tendered by the investors, is currently approximately $2,085,600. The Company has adequate capital to meet this obligation. +On June 6, 2000 the Company purchased all of the working interest in 168 producing wells in Colorado for $5,650,000. The transaction was effective April 1, 2000. The wells have net remaining reserves of 560,000 barrels of oil and 4.9 billion cubic feet of natural gas. The Company utilized its bank credit agreement to finance this purchase. +The Company continues to pursue capital investment opportunities in producing natural gas properties as well as its plan to participate in its sponsored natural gas drilling partnerships, while pursuing opportunities for operating improvements and costs efficiencies. Management believes that the Company has adequate capital to meet its operating requirements. +A summary of Company's debt and lease obligations and commitments is as follows : +Yea r +Debt +Operating Leases +2002 +$1,346,600 +2003 +1,061,500 +2004 +$28,000,000 +397,800 +2005 +120,400 +2006 +50,200 +Critical Accounting Policies +Certain accounting policies are very important to the portrayal of Company's financial condition and results of operations and require management's most subjective or complex judgments. The policies are as follows: +Revenue Recognition +Oil and gas wells are drilled primarily on a contract basis. The Company follows the percentage-of-completion method of income recognition for drilling operations in progress. +Sales of natural gas are recognized when sold, oil revenues are recognized when produced into a stock tank. +Well operations income consists of operation charges for well upkeep, maintenance and operating lease income on tangible well equipment. +Valuation of Accounts Receivable +Management reviews accounts receivable to determine which are doubtful of collection. In making the determination of the appropriate allowance for doubtful accounts, management considers Company's history of write-offs, relationships and overall credit worthiness of its customers, and well production data for receivables related to well operations. +Impairment of Long-Lived Assets +Exploration and development costs are accounted for by the successful efforts method. +The Company assesses impairment of capitalized costs of proved oil and gas properties by comparing net capitalized costs to undiscounted future net cash flows on a field-by-field basis using expected prices. Prices utilized in each year's calculation for measurement purposes and expected costs are held constant throughout the estimated life of the properties. If net capitalized costs exceed undiscounted future net cash flow, the measurement of impairment is based on estimated fair value which would consider future discounted cash flows. +23 +Unproved properties are assessed on a property-by-property basis and properties considered to be impaired are charged to expense when such impairment is deemed to have occurred. +Deferred Tax Asset Valuation Allowance +Deferred tax assets are recognized for deductible temporary differences, net operating loss carryforwards, and credit carryforwards if it is more likely than not that the tax benefits will be realized. To the extent a deferred tax asset cannot be recognized under the preceding criteria, a valuation allowance has been established. +The judgments used in applying the above policies are based on management's evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results may differ from those estimates. See additional discussions in this Management's Discussion and Analysis. +New Accounting Standards +Statement of Financial Accounting Standards No. 141, "Business Combinations" ("SFAS No. 141") and Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets" ("SFAS No. 142") were issued in July 2001. SFAS No. 141 requires that all business combinations entered into subsequent to June 30, 2001 be accounted for under the purchase method of accounting and establishes specific criteria for the recognition of intangible assets separately from goodwill. SFAS No. 142 requires that goodwill and intangible assets with indefinite useful lives no longer be amortized, but instead tested for impairment at least annually in accordance with the provisions of SFAS 142. SFAS 142 also requires that intangible assets with definite useful lives be amortized over their respective estimated useful lives to their estimated residual value, and subsequently reviewed for impairment. The Company does not believe that the adoption of these statements will have a material effect on its financial position, results of operations, or cash flows. +In June 2001, the FASB issued SFAS 143, Accounting for Asset Retirement Obligations (SFAS No. 143). SFAS No. 143 requires the Company to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development and/or normal use of the assets. The Company also records a corresponding asset which is depreciated over the life of the asset. Subsequent to the initial measurement of the asset retirement obligation, the obligation will be adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. The Company is required to adopt SFAS No. 143 on January 1, 2003. At this time, the Company cannot reasonably estimate the effect of the adoption of this Statement on either its financial position, results of operations, or cash flows. +In August, 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (SFAS No. 144). SFAS No. 144 addresses financial accounting and reporting for the impairment or disposal of long-lived assets. This Statement requires that long-lived assets be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future net cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset. SFAS No. 144 requires companies to separately report discontinued operations and extends that reporting to a component of an entity that either has been disposed of (by sale, abandonment, or in a distribution to owners) or is classified as held for sale. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell. The Company is required to adopt SFAS No. 144 on January 1, 2002. The Company does not believe that the adoption of this statement will have a material effect on its financial position, results of operations or cash flows. +Item 7.a. Quantitative and Qualitative Disclosure About Market Risk . +Market-Sensitive Instruments and Risk Management +The Company's primary market risk exposures are interest rate risk and commodity price risk. These exposures are discussed in detail below: +24 +Interest Rate Risk +The Company's exposure to market risk for changes in interest rates relates primarily to the Company's interest-bearing cash and cash equivalents and long-term debt. Interest-bearing cash and cash equivalents includes money market funds, certificates of deposit and checking and savings accounts with various banks. The amount of interest-bearing cash and cash equivalents as of December 31, 2001 is $53,646,000 with an average interest rate of 1.13 percent. As of December 31, 2001, the Company has long-term debt of $28,000,000 of which $10,000,000 is subject to an interest rate swap at a rate of 8.39% and $18,000,000 was subject to a prime rate of 4.75%. +Commodity Price Risk +The Company utilizes commodity-based derivative instruments as hedges to manage a portion of its exposure to price risk from its natural gas sales and marketing activities. These instruments consist of NYMEX-traded natural gas futures contracts and option contracts. These hedging arrangements have the effect of locking in for specified periods (at predetermined prices or ranges of prices) the prices the Company will receive for the volume to which the hedge relates and, in the case of RNG, the cost of gas supplies purchased for marketing activities. As a result, while these hedging arrangements are structured to reduce the Company's exposure to changes in price associated with the hedged commodity, they also limit the benefit the Company might otherwise have received from price changes associated with the hedged commodity. The Company's policy prohibits the use of natural gas future and option contracts for speculative purposes. +Riley Natural Gas, the Company's marketing subsidiary, as of December 31, 2001, has entered into a series of natural gas future contracts and option contracts stemming from its marketing activities. Open future contracts maturing in 2002 are for the sale of 1,680,000 dt of natural gas with a weighted average price of $3.18 dt resulting in a total contract amount of $5,343,500 and a fair market value of $479,300. Open option contracts maturing in 2002 are for the sale of 20,000 dt with a weighted average floor price of $2.85 dt and a fair value of $9,000. As of December 31, 2000 RNG had entered into a series of natural gas future contracts stemming from its marketing activities. Open future contracts maturing in 2001 were for the sale of 4,220,000 dt of natural gas with a weighted average price of $4.39 dt resulting in a total contract amount of $18,525,300 and a fair market value of $(11,526,500). There were no open option contracts stemming from RNG's marketing activities as of December 31, 2000. +As of December 31, 2001 PDC had no natural gas future contracts or option contracts stemming from its natural gas production. As of December 31, 2000, PDC had entered into a series of natural gas future contracts and option contracts stemming from its natural gas production. Open future contracts maturing in 2001 were for the sale of 2,010,000 dt of natural gas with a weighted average price of $4.26 dt resulting in a total contract amount of $8,545,900 and a fair market value of $(7,813,900). Open option contracts maturing in 2001 were for the sale of 2,276,400 dt with a weighted average floor price of $3.68 dt and a fair value of $(757,600). +The average NYMEX closing price for natural gas for the years 2001, 2000 and 1999 was $4.27 dt, $3.88 dt and $2.27 dt. The average NYMEX closing price for oil for the years 2001, 2000 and 1999 was $26.60 bbl, $30.95 bbl and $18.06 bbl. Future near-term gas prices will be affected by various supply and demand factors such as weather, government and environmental regulation and new drilling activities within the industry. +Disclosure of Limitations +As the information above incorporates only those exposures that exist at December 31, 2001, it does not consider those exposures or positions which could arise after that date. As a result, the Company's ultimate realized gain or loss with respect to interest rate and commodity price fluctuations will depend on the exposures that arise during the period, the Company's hedging strategies at the time, and interest rates and commodity prices at the time. +PART III +Item 8. Financial Statements and Supplementary Data: +The response to this Item is set forth herein in a separate section of this Report, beginning on Page F-1. +25 +Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. +None. +Item 10. Directors and Executive Officers of the Company +Directors and Executive Officers of the Company +The executive officers and directors of the Company, their principal occupations for the past five years and additional information are set forth below: +Name +Age +Positions and Offices Held +Held Current +Position Since +James N. Ryan +70 +Chairman, Chief Executive Officer +and Director +November 1983 +Steven R. Williams +50 +President and Director +March 1983 +Dale G. Rettinger +57 +Chief Financial Officer, Executive +Vice President, Treasurer and +Director +July 1980 +Roger J. Morgan +74 +Secretary and Director +November 1969 +Vincent F. D'Annunzio +49 +Director +February 1989 +Jeffrey C. Swoveland +46 +Director +March 1991 +Donald B. Nestor +53 +Director +March 2000 +James N. Ryan has served as President and Director of PDC from 1969 to 1983 and was elected Chairman and Chief Executive Officer in March 1983. +Steven R. Williams has served as President and Director of PDC since March 1983. Prior to joining PDC, Mr. Williams was employed by Exxon until 1979 and attended Stanford Graduate School of Business, graduating in 1981. He then worked with Texas Oil and Gas until July 1982, when he joined Exco Enterprises, an oil and gas investment company as manager of operations. +Dale G. Rettinger has served as Vice President and Treasurer of PDC since July 1980, and was appointed Chief Financial Officer in September 1997. Mr. Rettinger was elected Director in 1985. Previously Mr. Rettinger was a partner with Main Hurdman, Certified Public Accountants, having served in that capacity since 1976. +Roger J. Morgan has been a member of the law firm of Young, Morgan & Cann, Clarksburg, West Virginia since 1955. Mr. Morgan is not active in the day-to-day business of PDC, but his law firm provides legal services to PDC. +Vincent F. D'Annunzio has served as president of Beverage Distributors, Inc. located in Clarksburg, West Virginia since 1985. +Jeffrey C. Swoveland has served as Chief Financial Officer of Body Media since September, 2000. Prior thereto, Mr. Swoveland was Vice President-Finance and Treasurer of Equitable Resources Inc since 1994. +Donald B. Nestor, elected as a director in March, 2000, is a Certified Public Accountant and a Partner in the CPA firm of Toothman Rice, P.L.L.C. and is in charge of the firm's Buckhannon, West Virginia office. Mr. Nestor has served in that capacity since 1975. +The Company's By-Laws provide that the directors of the Company shall be divided into three classes and that, at each annual meeting of stockholders of the Company, successors to the class of directors whose term expires at the annual meeting will be elected for a three-year term. The classes are staggered so that the term of one class expires each year. Mr. Rettinger and Mr. Swoveland are members of the class whose term expires in 2002; and Mr. Williams, Mr. Morgan and Mr. Nestor are members of the class whose term expires in 2003; and Mr. Ryan and Mr. D'Annunzio are members of the class whose term expires in 2004. There is no family relationship between any director or executive officer and any other director or executive officer of the Company. There are no arrangements or understandings between any director or officer and any other person pursuant to which such person was selected as an officer. +26 +Item 11. Management Remuneration and Transactions +There is incorporated by reference herein in response to this Item the material under the heading "Election of Directors - Remuneration of Directors and Officers", "Election of Directors - Stock Options" and "Election of Directors - Interest of Management in Certain Transactions" in the Company's definitive proxy statement for its 2002 annual meeting of stockholders filed or to be filed with the Commission on or before April 30, 2002. +Item 12. Security Ownership of Certain Beneficial Owners and Management +There is incorporated by reference herein in response to this Item, the material under the heading "Election of Directors", in the Company's definitive proxy statement for its 2002 annual meeting of stockholders filed or to be filed with the Commission on or before April 30, 2002. +Item 13. Certain Relationships and Related Transactions +The response to this item is set forth herein in Note 8 in the Notes to Consolidated Financial Statements. +PART IV +Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K +(a) (1) Financial Statements: +See Index to Financial Statements and Schedules on page F-1. +(2) Financial Statement Schedules: +See Index to Financial Statements and Schedules on page F-1. +Schedules and Financial Statements Omitted +All other financial statement schedules are omitted because they are not required, inapplicable, or the information is included in the Financial Statements or Notes thereto. +(3) Exhibits: +See Exhibits Index on page E-1. +27 +CONFORMED COPY +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. +PETROLEUM DEVELOPMENT CORPORATION +By /s/ James N. Ryan +James N. Ryan, Chairman +March 15, 2002 +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/ James N. Ryan +James N. Ryan +Chairman, Chief Executive +Officer and Director +March 15, 2002 +/s/ Steven R. Williams +Steven R. Williams +President and Director +March 15, 2002 +/s/ Dale G. Rettinger +Dale G. Rettinger +Chief Financial Officer +Executive Vice +President,Treasurer and +Director (principal financial +and accounting officer +March 15, 2002 +/s/ Roger J. Morgan +Roger J. Morgan +Secretary and Director +March 15, 2002 +28 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Index to Financial Statements and Financial Statement Schedules +1. +Financial Statements: +Independent Auditors' Report +F-2 +Consolidated Balance Sheets - December 31, 2001 and 2000 +F-3 & 4 +Consolidated Statements of Income - +Years Ended December 31, 2001, 2000 and 1999 +F-5 +Consolidated Statements of Stockholders' Equity - +Years Ended December 31, 2001, 2000 and 1999 +F-6 +Consolidated Statements of Cash Flows - +Years Ended December 31, 2001, 2000 and 1999 +F-7 +Notes to Consolidated Financial Statements +F-8 +2. +Financial Statement Schedule: +Schedule II - Valuation and Qualifying Accounts and Reserves +F-25 +F-1 +Independent Auditors' Report +The Stockholders and Board of Directors +Petroleum Development Corporation: +We have audited the consolidated financial statements of Petroleum Development Corporation and subsidiaries as listed in the accompanying index. In connection with our audits of the consolidated financial statements, we also have audited the financial statement schedule as listed in the accompanying index. These consolidated financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits. +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, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Petroleum Development Corporation and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. +As discussed in note 13 to the consolidated financial statements, the Company changed its method of accounting for derivative instruments and hedging activities in 2001. +KPMG LLP +Pittsburgh, Pennsylvania +February 27, 2002 +F-2 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Consolidated Balance Sheets +December 31, 2001 and 2000 +2001 +2000 +Assets +Current assets: +Cash and cash equivalents +$ 47,892,300 +43,933,700 +Restricted cash +283,300 +2,938,300 +Notes and accounts receivable +10,752,600 +23,648,000 +Inventories +1,117,900 +1,097,900 +Prepaid expenses +4,659,300 +7,134,800 +Total current assets +64,705,400 +78,752,700 +Properties and equipment: +Oil and gas properties (successful +efforts accounting method) +167,244,600 +131,271,900 +Pipelines +6,501,500 +6,147,800 +Transportation and other equipment +3,201,500 +2,704,300 +Land and buildings +1,402,400 +1,174,600 +178,350,000 +141,298,600 +Less accumulated depreciation, +depletion and amortization +45,809,500 +35,344,700 +132,540,500 +105,953,900 +Other assets +2,606,200 +2,977,900 +$199,852,100 +187,684,500 +========= +========= +(Continued) +F-3 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Consolidated Balance Sheets +December 31, 2001 and 2000 +2001 +2000 +Liabilities and Stockholders' Equity +Current liabilities: +Accounts payable +$ 17,118,600 +27,742,600 +Other accrued expenses +7,924,200 +3,979,900 +Advances for future drilling contracts +31,592,200 +43,809,400 +Funds held for future distribution +4,650,800 +2,440,100 +Total current liabilities +61,285,800 +77,972,000 +Long-term debt +28,000,000 +17,350,000 +Other liabilities +4,082,700 +4,396,800 +Deferred income taxes +9,710,800 +5,708,800 +Commitments and contingencies +Stockholders' equity: +Common stock, par value $.01 per share; +authorized 50,000,000 shares; issued and +outstanding 16,245,752 and 16,244,044 shares +162,400 +162,400 +Additional paid-in capital +32,922,500 +32,917,000 +Retained earnings +64,145,300 +49,177,500 +Accumulated other comprehensive loss, net of tax +(457,400 ) +- +Total stockholders' equity +96,772,800 +82,256,900 +$199,852,100 +187,684,500 +========= +========== +See accompanying notes to consolidated financial statements. +F-4 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Consolidated Statements of Income +Years Ended December 31, 2001, 2000 and 1999 +2001 +2000 +1999 +Revenues: +Oil and gas well drilling operations +$ 76,291,200 +43,194,700 +42,115,600 +Gas sales from marketing activities +66,207,400 +71,402,400 +38,359,700 +Oil and gas sales +25,887,900 +19,017,300 +8,628,400 +Well operations and pipeline income +5,604,200 +5,061,600 +5,314,500 +Other income +3,132,400 +2,540,500 +2,392,400 +177,123,100 +141,216,500 +96,810,600 +Costs and expenses: +Cost of oil and gas well +drilling operations +65,999,900 +35,244,300 +35,507,300 +Cost of gas marketing activities +65,740,300 +71,648,500 +38,459,000 +Oil and gas production costs +8,582,700 +8,303,600 +5,729,200 +General and administrative expenses +4,145,700 +3,616,900 +2,801,000 +Depreciation, depletion and amortization +10,578,300 +6,943,500 +4,031,200 +Interest +993,400 +1,186,000 +182,400 +156,040,300 +126,942,800 +86,710,100 +Income before income taxes +21,082,800 +14,273,700 +10,100,500 +Income taxes +6,115,000 +3,592,700 +2,276,200 +Net income +$ 14,967,800 +10,681,000 +7,824,300 +======== +========= +======== +Basic earnings per common share +$.92 +.66 +.50 +=== +== +== +Diluted earnings per common +and common equivalent share +$.90 +.65 +.48 +== +== +== +See accompanying notes to consolidated financial statements. +F-5 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Consolidated Statements of Stockholders' Equity +Years Ended December 31, 2001, 2000 and 1999 +Common stock +Issued +Number +Of Shares +Amount +Additional +Paid-in- +capital +Warrants +Out- +Standing +Retained +Earnings +Accumulated +Other +Comprehensive +Income +Total +Balance, December 31, 1998 +15,510,762 +$ 155,100 +31,873,100 +46,300 +30,672,200 +- +62,746,700 +Issuance of common stock: +Exercise of employee stock options +324,333 +3,200 +300,800 +- +- +- +304,000 +Amortization of stock award +- +- +12,200 +- +- +- +12,200 +Repurchase and cancellation of treasury stock +(97,300) +(900) +(303,100) +- +- +- +(304,000) +Income tax benefit from the exercise of stock options +- +- +141,700 +- +- +- +141,700 +Warrants expired +- +- +46,300 +(46,300) +- +- +Net income +- +- +- +- +7,824,300 +- +7,824,300 +Balance, December 31, 1999 +15,737,795 +$ 157,400 +32,071,000 +- +38,496,500 +- +70,724,900 +Issuance of common stock: +Exercise of employee stock options +511,584 +5,100 +511,700 +- +- +- +516,800 +Purchase of properties +100,000 +1,000 +549,000 +- +- +- +550,000 +Amortization of stock award +- +- +5,500 +- +- +- +5,500 +Repurchase and cancellation of treasury stock +(105,335) +(1,100) +(420,100) +- +- +- +(421,200) +Income tax benefit from the exercise of stock options +- +- +199,900 +- +- +- +199,900 +Net income +- +- +- +- +10,681,000 +- +10,681,000 +Balance, December 31, 2000: +16,244,044 +$ 162,400 +32,917,000 +- +49,177,500 +- +82,256,900 +Issuance of common stock +1,708 +- +- +- +- +- +- +Amortization of stock award +- +- +5,500 +- +- +- +5,500 +Net income +14,967,800 +14,967,800 +Comprehensive income: +Cumulative effect of change in accounting principle - +January 1, 2001 (net of tax of $8,052,700) +- +- +- +- +- +(12,079,100) +- +Reclassification adjustment for settlement of contracts +included in net income (net of tax of 3,046,900) +- +- +- +- +- +4,971,200 +- +Changes in fair value of outstanding hedging positions +(net of tax of $4,076,100) +- +- +- +- +- +6,650,500 +- +Other comprehensive loss +(457,400 ) +(457,400 ) +Comprehensive income +_________ +___________ +_________ +_________ +___________ +________ +14,510,400 +Balance, December 31, 2001 +16,245,752 +$ 162,400 +32,922,500 +- +64,145,300 +(457,400) +96,772,800 +======== +========== +======== +======== +========= +======= +======== +See accompanying notes to consolidated financial statements. +F-6 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Consolidated Statements of Cash Flows +Years Ended December 31, 2001, 2000 and 1999 +2001 +2000 +1999 +Cash flows from operating activities: +Net income +$14,967,800 +10,681,000 +7,824,300 +Adjustment to net income to reconcile +to cash provided by operating activities: +Deferred income taxes +4,002,300 +1,838,300 +108,900 +Depreciation, depletion and amortization +10,578,300 +6,943,500 +4,031,200 +Gain from sale of assets +(132,400) +(199,200) +(501,800) +Disposition of leasehold acreage +919,200 +672,700 +618,100 +Amortization of stock award +5,500 +5,500 +12,200 +Decrease (increase) in notes and accounts receivable +12,895,400 +(13,384,800) +(4,239,100) +(Increase) decrease in inventories +(20,000) +(520,300) +124,800 +Decrease (increase) in prepaid expenses +3,243,900 +(4,774,700) +312,600 +Decrease (increase) in other assets +336,700 +(375,700) +(750,900) +(Decrease) increase in accounts payable and accrued expenses +(8,219,900) +15,359,700 +5,347,300 +(Decrease) increase in advances for future drilling contracts +(12,217,200) +18,672,000 +(3,183,400) +Increase in funds held for future distribution +2,210,700 +412,500 +1,043,400 +Total adjustments +13,602,500 +24,649,500 +2,923,300 +Net cash provided by operating activities +28,570,300 +35,330,500 +10,747,600 +Cash flows from investing activities: +Capital expenditures +(42,661,100) +(27,932,100) +(27,758,200) +Proceeds from sale of leases +4,732,200 +1,588,700 +1,224,200 +Proceeds from sale of fixed assets +12,200 +680,100 +651,000 +Decrease (increase) in restricted cash +2,655,000 +(2,324,000 ) +(458,100 ) +Net cash used in investing activities +(35,261,700 ) +(27,987,300 ) +(26,341,100 ) +Cash flows from financing activities: +Proceeds from debt, net +10,650,000 +8,050,000 +9,300,000 +Proceeds from issuance of stock +- +95,600 +- +Net cash provided by financing activities +10,650,000 +8,145,600 +9,300,000 +Net increase (decrease) in cash and cash equivalents +3,958,600 +15,488,800 +(6,293,500) +Cash and cash equivalents, beginning of year +43,933,700 +28,444,900 +34,738,400 +Cash and cash equivalents, end of year +$47,892,300 +43,933,700 +28,444,900 +======== +======== +========= +See accompanying notes to consolidated financial statements. +F-7 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +Years Ended December 31, 2001, 2000 and 1999 +(1) Summary of Significant Accounting Policies +Principles of Consolidation +The accompanying consolidated financial statements include the accounts of Petroleum Development Corporation and its wholly owned subsidiaries. All material intercompany accounts and transactions have been eliminated in consolidation. The Company accounts for its investment in limited partnerships under the proportionate consolidation method. Under this method, the Company's financial statements include its prorata share of assets and liabilities and revenues and expenses, respectively, of the limited partnerships in which it participates. +The Company is involved in three business segments. The segments are drilling and development, natural gas sales and well operations. (See Note 19) +The Company grants credit to purchasers of oil and gas and the owners of managed properties, substantially all of whom are located in West Virginia, Tennessee, Pennsylvania, Ohio, Michigan, North Dakota and Colorado. +Cash Equivalents +For purposes of the statement of cash flows, the Company considers all highly liquid debt instruments with original maturities of three months or less to be cash equivalents. +Inventories +Inventories of well equipment, parts and supplies are valued at the lower of average cost or market. An inventory of natural gas is recorded when gas is purchased in excess of deliveries to customers and is recorded at the lower of cost or market. An inventory of oil located in stock tanks on well locations, is carried at market at the end of each period. +Oil and Gas Properties +Exploration and development costs are accounted for by the successful efforts method. +The Company assesses impairment of capitalized costs of proved oil and gas properties by comparing net capitalized costs to undiscounted future net cash flows on a field-by-field basis using expected prices. Prices utilized in each year's calculation for measurement purposes and expected costs are held constant throughout the estimated life of the properties. If net capitalized costs exceed undiscounted future net cash flow, the measurement of impairment is based on estimated fair value which would consider future discounted cash flows. +Property acquisition costs are capitalized when incurred. Geological and geophysical costs and delay rentals are expensed as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether the wells have discovered economically producible reserves. If reserves are not discovered, such costs are expensed as dry holes. Development costs, including equipment and intangible drilling costs related to both producing wells and developmental dry holes, are capitalized. +(Continued) +F-8 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +Unproved properties are assessed on a property-by-property basis and properties considered to be impaired are charged to expense when such impairment is deemed to have occurred. +Costs of proved properties, including leasehold acquisition, exploration and development costs and equipment, are depreciated or depleted by the unit-of-production method based on estimated proved developed oil and gas reserves. +Upon sale or retirement of complete units of depreciable or depletable property, the net cost thereof, less proceeds or salvage value, is credited or charged to income. Upon retirement of a partial unit of property, the cost thereof is charged to accumulated depreciation and depletion. +Based on the Company's experience, management believes site restoration, dismantlement and abandonment costs net of salvage to be immaterial in relation to operating costs. These costs are being expensed when incurred. +Transportation Equipment, Pipelines and Other Equipment +Transportation equipment, pipelines and other equipment are carried at cost. Depreciation is provided principally on the straight-line method over useful lives of 3 to 17 years. These assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. An impairment loss based on estimated fair value is recorded when the review indicates that the related expected future net cash flow (undiscounted and without interest charges) is less than the carrying amount of the asset. +Maintenance and repairs are charged to expense as incurred. Major renewals and betterments are capitalized. Upon the sale or other disposition of assets, the cost and related accumulated depreciation, depletion and amortization are removed from the accounts, the proceeds applied thereto and any resulting gain or loss is reflected in income. +Buildings +Buildings are carried at cost and depreciated on the straight-line method over estimated useful lives of 30 years. +Advances for Future Drilling Contracts +Represents funds received from Partnerships and other joint ventures for drilling activities which have not been completed and accordingly have not yet been recognized as income in accordance with the Company's income recognition policies. +Retirement Plans +The Company has a 401-K contributory retirement plan (401-K Plan) covering full-time employees. The Company provides a discretionary matching of employee contributions to the plan. +The Company also has a profit sharing plan covering full-time employees. The Company's contributions to this plan are discretionary. +The Company has a deferred compensation arrangement covering executive officers of the Company as a supplemental retirement benefit. +The Company has established split-dollar life insurance arrangements with certain executive officers. Under these arrangements, advances are made to these officers equal to the premiums due. The advances are collateralized by the cash surrender value of the policies. The Company records as other assets its share of the cash surrender value of the policies. +(Continued) +F-9 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +Revenue Recognition +Oil and gas wells are drilled primarily on a contract basis. The Company follows the percentage-of-completion method of income recognition for drilling operations in progress. +Sales of natural gas are recognized when sold, oil revenues are recognized when produced into a stock tank. +Well operations income consists of operation charges for well upkeep, maintenance and operating lease income on tangible well equipment. +Income Taxes +Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. +Derivative Financial Instruments +All derivatives are recognized on the consolidated balance sheet at their fair value. On the date the derivative contract is entered into, the Company designates the derivative as either a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability ("Cash flow" hedge), or a non-hedging derivative. The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk-management objective and strategy for undertaking various hedge transactions. This process includes linking all derivatives that are designated as cash-flow hedges to specific firm commitments or forecasted transactions. The Company also formally assesses, both at the hedge's inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. When it is determined that a derivative is not highly effective as a hedge or that it has ceased to be a highly effective hedge, the Company discontinues hedge accounting prospectively. No hedging activities were discontinued during 2001. +Changes in fair value of a derivative that is highly effective and that is designated and qualifies as a cash-flow hedge are recorded in other comprehensive income, until earnings are affected by the variability in cash flows of the designated hedged item. Changes in the fair value of non-hedging derivatives are reported in current-period earnings. The Company discontinues hedge accounting prospectively when it is determined that the derivative is no longer effective in offsetting changes in the cash flows of the hedged item, the derivative expires or is sold, terminated, or exercised. Additionally, if the derivative is dedesignated as a hedging instrument, because it is unlikely that a forecasted transaction will occur, a hedged firm commitment no longer meets the definition of a firm commitment, or management determines that designation of the derivative as a hedging instrument is no longer appropriate, hedge accounting will discontinue. +For the years ended December 31, 2000 and 1999, prior to adoption of Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Certain Hedging Activities" and SFAS No. 138, "Accounting for Certain Hedging Activities", gains and losses related to qualifying hedges of firm commitments or anticipated transactions through the use of natural gas futures and option contracts were deferred and recognized in income or as adjustments of carrying amounts when the underlying hedged transaction occurred. In order for futures contracts to qualify as a hedge, there must be sufficient correlation to the underlying hedged transaction. The change in the fair value of derivative instruments which do not qualify for hedging were recognized into income in 2000 and 1999, respectively. +(Continued) +F-10 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +During 2000, the Company entered into an interest rate swap agreement which expires October 11, 2004 to reduce its exposure to market risks from changing interest rates. The interest rate differential to be paid or received was accrued and recognized as interest expense in the period incurred. +Stock Compensation +The Company has adopted SFAS No. 123, "Accounting for Stock-Based Compensation," which permits entities to recognize as expense over the vesting period the fair value of all stock-based awards on the date of grant. Alternatively, SFAS 123 allows entities to continue to measure compensation cost for stock-based awards using the intrinsic value based method of accounting prescribed by APB Opinion No. 25, "Accounting for Stock Issued to Employees," and to provide pro forma net income and pro forma earnings per share disclosures as if the fair value based method defined in SFAS 123 had been applied. The Company has elected to continue to apply the provisions of APB 25 and provide the pro forma disclosure provisions of SFAS 123. See note 5 to the financial statements. +Use of Estimates +Management of the Company has made a number of estimates and assumptions relating to the reporting of assets and liabilities and revenues and expenses and the disclosure of contingent assets and liabilities to prepare these financial statements in conformity with generally accepted accounting principles. Actual results could differ from those estimates. Estimates which are particularly significant to the consolidated financial statements include estimates of oil and gas reserves and future cash flows from oil and gas properties. +Reclassifications +Certain items and amounts reported in the 1999 consolidated financial statements have been reclassified to conform to the current year's reporting format. +Fair Value of Financial Instruments +The carrying values and fair values of the Company's receivables, payables and debt obligations are estimated to be substantially the same as of December 31, 2001, 2000 and 1999. +New Accounting Standards +Statement of Financial Accounting Standards No. 141, "Business Combinations" ("SFAS No. 141") and Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets" ("SFAS No. 142") were issued in July 2001. SFAS No. 141 requires that all business combinations entered into subsequent to June 30, 2001 be accounted for under the purchase method of accounting and establishes specific criteria for the recognition of intangible assets separately from goodwill. SFAS No. 142 requires that goodwill and intangible assets with indefinite useful lives no longer be amortized, but instead tested for impairment at least annually in accordance with the provisions of SFAS 142. SFAS 142 also requires that intangible assets with definite useful lives be amortized over their respective estimated useful lives to their estimated residual value, and subsequently reviewed for impairment. The Company does not believe that the adoption of these statements will have a material effect on its financial position, results of operations, or cash flows. +F-11 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +In June 2001, the FASB issued SFAS 143, Accounting for Asset Retirement Obligations (SFAS No. 143). SFAS No. 143 requires the Company to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development and/or normal use of the assets. The Company also records a corresponding asset which is depreciated over the life of the asset. Subsequent to the initial measurement of the asset retirement obligation, the obligation will be adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. The Company is required to adopt SFAS No. 143 on January 1, 2003. At this time, the Company cannot reasonably estimate the effect of the adoption of this Statement on either its financial position, results of operations, or cash flows. +In August, 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (SFAS No. 144). SFAS No. 144 addresses financial accounting and reporting for the impairment or disposal of long-lived assets. This Statement requires that long-lived assets be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future net cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset. SFAS No. 144 requires companies to separately report discontinued operations and extends that reporting to a component of an entity that either has been disposed of (by sale, abandonment, or in a distribution to owners) or is classified as held for sale. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell. The Company is required to adopt SFAS No. 144 on January 1, 2002. The Company does not believe that the adoption of this statement will have a material effect on its financial position, results of operations or cash flows. +(2) Notes and Accounts Receivable +Included in other assets are noncurrent accounts receivable as of December 31, 2001 and 2000, in the amounts of $173,600 and $245,300 net of the allowance for doubtful accounts of $174,600 and $183,000, respectively. +The allowance for doubtful current accounts receivable as of December 31, 2001 and 2000 was $349,900 and $341,500, respectively. +(3) Long-Term Debt +On August 29, 2000 the Company executed an Amendment to its Credit Agreement with Bank One. The amendment provides and the Company has activated a $40 million borrowing base, subject to adequate oil and gas reserves. The Company is required to pay a commitment fee of 1/4 percent on the unused portion of the activated credit facility. Interest accrues at prime, with LIBOR (London Interbank Market Rate) alternatives available at the discretion of the Company. No principal payments are required until the credit agreement expires on December 31, 2004. +As of December 31, 2001 and 2000 the outstanding balance was $28,000,000 and $17,350,000, respectively. Any amounts outstanding under the credit agreement are secured by substantially all properties of the Company. The credit agreement requires, among other things, the existence of satisfactory levels of natural gas reserves, maintenance of certain working capital and tangible net worth ratios along with a restriction on the payment of dividends. As of December 31, 2001 and 2000 the Company was in compliance with all financial covenants in the credit agreement. +At December 31, 2001, $10,000,000 of the outstanding balance was subject to an interest rate swap at a rate of 8.39% and $18,000,000 was subject to a prime rate of 4.75%. +F-12 +(Continued) +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +(4) Income Taxes +The Company's provision for income taxes consisted of the following: +2001 +2000 +1999 +Current: +Federal +$1,639,300 +1,182,000 +1,434,300 +State +473,300 +572,400 +733,000 +Total current income taxes +2,112,600 +1,754,400 +2,167,300 +Deferred: +Federal +3,898,600 +1,415,600 +(65,300) +State +103,800 +422,700 +174,200 +Total deferred income taxes +4,002,400 +1,838,300 +108,900 +Total taxes +$6,115,000 +3,592,700 +2,276,200 +======== +======== +======= +Income tax expense differed from the amounts computed by applying the U.S. federal income tax rate of 34 percent to pretax income as a result of the following: +2001 +2000 +1999 +Amount +Amount +Amount +Computed "expected" tax +$7,168,200 +4,853,100 +3,434,200 +State income tax +380,900 +656,800 +598,800 +Percentage depletion +(935,000) +(758,300) +(612,000) +Nonconventional source fuel credit +(1,184,700) +(1,067,500) +(846,800) +Adjustments to valuation allowance +- +- +(375,000) +Effect of state rate change +556,500 +- +- +Other +129,100 +(91,400 ) +77,000 +$6,115,000 +3,592,700 +2,276,200 +======== +======== +======= +The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2001 and 2000 are presented below: +2001 +2000 +Deferred tax assets: +Allowance for doubtful accounts +$ 199,300 +209,800 +Drilling notes +88,100 +101,900 +Alternative minimum tax credit carryforwards (Section 29) +1,715,800 +2,132,300 +Future abandonment +409,300 +347,200 +Deferred compensation +2,100,500 +1,729,200 +Other +48,900 +49,400 +Total gross deferred tax assets +4,561,900 +4,569,800 +Less valuation allowance +- +- +Deferred tax assets +4,561,900 +4,569,800 +Less current deferred tax assets (included in prepaid expenses) +(1,133,400 ) +(853,300 ) +Net non-current deferred tax assets +3,428,500 +3,716,500 +Deferred tax liabilities: +Properties and equipment, principally due to differences in +depreciation and amortization +(13,419,800 ) +(9,425,300 ) +Total gross deferred tax liabilities +(13,419,800 ) +(9,425,300 ) +Net deferred tax liability +(9,991,300) +(5,708,800) +======== +======== +Deferred income tax assets related to AOCI +280,500 +- +Net deferred tax liability after AOCI +$(9,710,800) +(5,708,800) +======== +======== +(Continued) +F-13 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +The valuation allowance for the deferred tax assets as of January 1, 2001 and 2000 was $0. The net changes in the total valuation allowance was a decrease of $375,000 for the year ended December 31, 1999. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. +At December 31, 2001, the Company has alternative minimum tax credit carryforwards (Section 29) of approximately $1,715,800 which are available to reduce future federal regular income taxes over an indefinite period. +Accumulated other comprehensive loss is net of tax of $280,500, $0 and $0 as of December 31, 2001, 2000 and 1999, respectively. The income tax benefit from the exercise of stock options recorded in additional paid-in capital was $0, $199,900 and $141,700 in 2001, 2000 and 1999, respectively. +(5) Common Stock +Options +Options amounting to 185,000, 180,000 and 145,000 shares were granted during 2001, 2000 and 1999, respectively, to certain employees and directors under the Company's Stock Option Plans. These options were granted with an exercise price equal to market value as of the date of grant and vest over a six month period. The outstanding options expire from 2005 to 2011. +The estimated fair value of the options granted during 2001, 2000 and 1999 was $3.70, $2.48 and $2.44 per option, respectively. The fair value was estimated using the Black-Scholes option pricing model with the following assumptions for the 2001, 2000 and 1999 grant, respectively: risk-free interest rate of 5.88%, 6.13% and 5.1%, expected dividend yield of 0%, expected volatility of 50.23%, 57.31% and 61.3% and expected life of 7 years. +Number +of Shares +Average +Exercise +Price +Range of +Exercise +Prices +Outstanding December 31, 1998 +1,568,317 +$2.39 +.94 - 6.13 +=== +========= +Granted +145,000 +$3.75 +3.75 - 3.75 +=== +========= +Exercised +(324,333 ) +$0.94 +.94 - .94 +=== +========= +Outstanding December 31, 1999 +1,388,984 +$2.87 +.94 - 6.13 +=== +========= +Granted +180,000 +$3.875 +3.875 - 3.875 +=== +========= +Exercised +(511,584) +$1.01 +.94 - 1.625 +=== +========= +Expired +(12,400 ) +$3.31 +1.50 - 3.75 +=== +========= +Outstanding December 31, 2000 +1,045,000 +$3.95 +1.125 - 6.125 +Granted +185,000 +$6.25 +6.25 - 6.25 +=== +========= +Outstanding December 31, 2001 +1,230,000 +$4.29 +1.125 - 6.25 +======== +=== +========= +As of December 31, 2001, there were 210,000 options outstanding and exercisable at the $1.125 exercise price which have a weighted average remaining contractual life of 3.9 years. Also as of December 31, 2001 there were 1,020,000 options outstanding and exercisable at a $3.75 to $6.25 exercise price range having a weighted average remaining contractual life of 6.9 years and weighted average exercise price of $4.95. +(Continued) +F-14 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +The Company accounts for its stock-based compensation plans under APB 25. For stock options granted, the option price was not less than the market value of shares on the grant date, therefore, no compensation cost has been recognized. Had compensation cost been determined under the provisions of SFAS 123, the Company's net income and earnings per share would have been the following on a pro forma basis: +2001 +2000 +As Reported +Pro Forma +As Reported +Pro Forma +Net income +$14,967,800 +$14,481,700 +$10,681,000 +$10,346,700 +========= +======== +======== +======== +Basic earnings per share +$ .92 +$ .89 +$ .66 +$ .64 +==== +=== +=== +=== +Diluted earnings per share +$ .90 +$ .87 +$ .65 +$ .63 +==== +=== +=== +=== +Stock Redemption Agreement +The Company has stock redemption agreements with three officers of the Company. The agreements require the Company to maintain life insurance on each executive in the amount of $1,000,000. The agreements provide that the Company shall utilize the proceeds from such insurance to purchase from such executives' estates or heirs, at their option, shares of the Company's stock. The purchase price for the outstanding common stock is to be based upon the average closing asked price for the Company's stock as quoted by NASDAQ during a specified period. The Company is not required to purchase any shares in excess of the amount provided for by such insurance. +(6) Employee Benefit Plans +The Company made 401-K Plan contributions of $260,800, $252,600 and $217,400 for 2001, 2000 and 1999, respectively. +The Company has a profit sharing plan (the Plan) covering full-time employees. The Company contributed $200,000, $1,000 and $47,000, to the plan in cash during 2001, 2000 and 1999, respectively. +During 2001, 2000 and 1999 the Company expensed and established a liability for $90,000 each year under a deferred compensation arrangement with the executive officers of the Company. +At December 31, 2001 and 2000, the Company has recorded as other assets $402,100 and $360,000, respectively as its share of the cash surrender value of the life insurance pledged as collateral for the payment of premiums on split-dollar life insurance policies owned by certain executive officers. +(7) Earnings Per Share +Basic earnings per share is based on the weighted average number of common shares outstanding of 16,244,931 for 2001, 16,157,532 for 2000, and 15,734,063 for 1999. +Diluted earnings per share is based on the weighted average number of common and common equivalent shares outstanding of 16,639,634 for 2001, 16,437,488 for 2000 and 16,286,852 for 1999. Stock options are considered to be common stock equivalents and to the extent appropriate, have been added to the weighted average common shares outstanding. +(8) Transactions with Affiliates +As part of its duties as well operator, the Company received $71,802,700 in 2001, $44,899,200 in 2000 and $24,002,500 in 1999 representing proceeds from the sale of oil and gas and made distributions to investor groups according to their working interests in the related oil and gas properties. Funds held for future distribution on the consolidated balance sheet includes amounts owed to affiliated partnerships as of December 31, 2001 and 2000. +(Continued) +F-15 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +The Company provided oil and gas well drilling services to affiliated partnerships. Substantially all of the Company's oil and gas well drilling operations was for such partnerships. The Company also provided related services of operation of wells, reimbursement of syndication costs, management fees, tax return preparation and other services relating to the operation of the partnerships. The Company received $16,072,500 in 2001, $15,713,300 in 2000 and $10,322,500 in 1999 for those services. Amounts due from the partnerships as of December 31, 2001 and 2000 were $1,246,200 and $957,700, and are included in notes and accounts receivable. +During 2001, 2000 and 1999, the Company paid $30,100, $40,400 and $31,600, respectively to the Corporate Secretary's law firm for various legal services. +(9) Commitments and Contingencies +The nature of the independent oil and gas industry involves a dependence on outside investor drilling capital and involves a concentration of gas sales to a few customers. The Company sells natural gas to various public utilities and industrial customers. One customer, Cinnabar Energy Services, accounted for 13.1% and 11.3% of total revenues in 2001 and 2000, respectively. No customer accounted for more than 10.0% of total revenues in 1999. +The Company would be exposed to natural gas price fluctuations on underlying purchase and sale contracts should the counterparties to the Company's hedging instruments or the counterparties to the Company's gas marketing contracts not perform. Such nonperformance is not anticipated. There were no counterparty default losses in 2001, 2000 or 1999. +Substantially all of the Company's drilling programs contain a repurchase provision where Investors may tender their partnership units for repurchase at any time beginning with the third anniversary of the first cash distribution. The provision provides that the Company is obligated to purchase an aggregate of 10% of the initial subscriptions per calendar year (at a minimum price of four times the most recent 12 months' cash distributions), only if such units are tendered, subject to the Company's financial ability to do so. The maximum annual 10% repurchase obligation, if tendered by the investors, is currently approximately $2,085,600. The Company has adequate capital to meet this obligation. +The Company is not party to any legal action that would materially affect the Company's results of operations or financial condition. +Lease Obligations +The Company has entered into certain operating leases on behalf of itself and its Partnerships principally for the leasing of natural gas compressors on its Michigan operating facilities. The future minimum lease payments under these non-cancellable operating leases as of December 31, 2001 are as follows: +Year +Lease Amount +2002 +$1,346,600 +2003 +1,061,500 +2004 +397,800 +2005 +120,400 +2006 +50,200 +$2,976,500 +======= +The Company's share of this lease expense for operating leases for the years ended December 31, 2001, 2000 and 1999 was $693,000, $629,800 and $457,400, respectively. +(Continued) +F-16 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +(11) Supplemental Disclosure of Cash Flows +The Company paid $1,173,100, $875,800 and $124,200 for interest in 2001, 2000 and 1999, respectively. The Company paid income taxes in 2001, 2000 and 1999 in the amounts of $2,830,000, $2,256,800 and $1,327,800, respectively. +The Company exchanged common stock in the amount of $550,000 and cash in the amount of $5,100,000 for the purchase of oil and gas properties in Colorado during 2000. +(12) Acquisitions and Divestitures +On January 29, 1999, the Company offered to purchase from Investors their units of investment in the Company's Drilling Programs formed prior to 1996. The Company purchased approximately $1.8 million of producing oil and gas properties in conjunction with this offer, which expired on March 31, 1999. The Company utilized capital received from its Public Stock Offering to fund this purchase. +On December 15, 1999, the Company purchased all of the working interest in 53 producing wells in the D-J Basin of Colorado. At the date of acquisition, the Company estimates that the purchase includes proved developed reserves of approximately 3.6 Bcf of natural gas and 370,000 barrels of oil or approximately 5.8 Bcf equivalent (Bcfe), along with 3.0 Bcfe of proved undeveloped reserves. Also included in the acquistion was 16.5 net development drilling locations. The total acquisition cost for the wells and locations was $5.2 million. The company utiltized part of its existing line of credit to fund the transaction. The effective date of the transaction was December 1, 1999. +On June 6, 2000, the Company purchased all of the working interest in 168 producing wells in Colorado for $5,650,000. The transaction was effective April 1, 2000. At the date of acquisition, the wells had net remaining reserves of 560,000 barrels of oil and 4.9 billion cubic feet of natural gas. The Company utilized its bank credit agreement to finance this purchase. +On December 31, 2000, the Company sold its Ohio gas gathering and sales systems. The result was a net gain of $109,600. +(13) Derivative Financial Instruments +The Company utilizes commodity based derivative instruments as hedges to manage a portion of its exposure to price volatility stemming from its integrated natural gas production and marketing activities. These instruments consist of natural gas futures and option contracts traded on the New York Mercantile Exchange. The futures and option contracts hedge committed and anticipated natural gas purchases and sales, generally forecasted to occur within a 12 month period. The Company does not hold or issue derivatives for trading or speculative purposes. In addition, interest rate swap agreements are used to reduce the potential impact of increases in interest rates on variable rate long-term debt. +Statement of Accounting Standards No. 133 and No. 138, Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133/138), was issued by the Financial Accounting Standards Board. SFAS No. 133/138 standardized the accounting for derivative instruments, including certain derivative instruments embedded in other contracts. The Company adopted the provisions of the SFAS 133/138 effective January 1, 2001. The natural gas futures and options and the interest rate swap are derivatives pursuant to SFAS 133/138. The Company's derivatives are treated as hedges of committed and/or anticipated transactions and have a total estimated fair value of $(457,400) (net of tax) on December 31, 2001. On adoption of this Statement on January 1, 2001, the Company recorded a net transition adjustment of ($12,079,100) (net of related income tax benefit of $8,052,700) which was recorded in accumulated other comprehensive income (AOCI). During the year ended December 31, 2001, the Company reclassified $4,971,200 (net of taxes of $3,046,900) from AOCI into cost of gas marketing activities. +F-17 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +Natural gas futures and option contracts for the sale of natural gas are as follows: +December 31, 2001 +Amount(dt) +Fair Value +Fair Value +net of tax +Futures contracts +Marketing activities +1,680,000 +$479,300 +$297,200 +Production activities +- +- +- +1,680,000 +$ 479,300 +$ 297,200 +======= +===== +====== +Option contracts +Marketing activities +20,000 +$9,000 +$ 5,600 +Production activities +- +- +- +20,000 +$9,000 +$ 5,600 +======= +===== +====== +December 31, 2000 +Futures contracts +Marketing activities +4,220,000 +$(11,526,500) +$ (6,915,900) +Production activities +2,010,000 +(7,813,900 ) +(4,688,300 ) +6,230,000 +$(19,340,400) +$(11,604,200) +======= +===== +====== +Option contracts +Marketing activities +- +- +- +Production activities +2,276,400 +$ (757,600 ) +$ (454,600 ) +2,276,400 +$(757,600) +$(454,600) +======= +===== +====== +The Company is required to maintain margin deposits with brokers for outstanding futures contracts. As of December 31, 2001 and 2000, cash in the amount of $283,300 and $2,938,300 was on deposit. +Interest rate swap agreements are used to reduce the potential impact of increases in interest rates on variable rate long-term debt. At December 31, 2001 and 2000, the Company was a party to an interest rate swap agreement expiring on October 11, 2004. The agreement entitles the Company, on a quarterly basis, to a fixed-rate interest payment of 6.89% plus its current LIBOR rate margin (+1.50% At December 31, 2001) on a $10,000,000 notional amount related to its outstanding line of credit. +The fair value of the interest rate swap agreement was $(1,226,200), $(760,200) net of tax at December 31, 2001 and $(33,800), $(20,300) net of tax at December 31, 2000. Current market pricing models were used to estimate fair value. +By using derivative financial instruments to hedge exposures to changes in interest rates and commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates repayment risk. The Company minimizes the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties. +F-18 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +(14) Costs Incurred in Oil and Gas Property Acquisition, Exploration and +Development Activities +Costs incurred by the Company in oil and gas property acquisition, exploration and development are presented below: +Years Ended December 31, +2001 +2000 +1999 +Property acquisition cost: +Proved undeveloped properties +$ 3,670,500 +3,397,500 +2,532,200 +Producing properties +75,700 +8,361,400 +6,997,500 +Development costs +35,411,900 +15,556,200 +17,168,000 +$39,158,100 +27,315,100 +26,697,700 +======== +======== +======== +The proved reserves attributable to the development costs in the above table were 7,496,900 Mcf and 263,400 bbls for 2001, 1,388,200 Mcf and 83,900 bbls for 2000, and 6,885,000 Mcf for 1999 (amounts unaudited). Of the above development costs incurred for the years ended December 31, 2001, 2000 and 1999 the amounts of $7,026,900, $2,379,300 and $2,977,500, respectively were incurred to develop proved undeveloped properties from the prior year end. +Property acquisition costs include costs incurred to purchase, lease or otherwise acquire a property. Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells and to provide facilities to extract, treat, gather and store oil and gas. +(15) Oil and Gas Capitalized Costs +Aggregate capitalized costs for the Company related to oil and gas exploration and production activities with applicable accumulated depreciation, depletion and amortization are presented below: +December 31, +2001 +2000 +Proved properties: +Tangible well equipment +$100,805,800 +82,304,400 +Intangible drilling costs +61,930,200 +44,944,000 +Undeveloped properties +4,508,600 +4,023,500 +167,244,600 +131,271,900 +Less accumulated depreciation, +depletion and amortization +39,503,200 +29,739,500 +$127,741,400 +101,532,400 +========= +========= +(Continued) +F-19 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +(16) Results of Operations for Oil and Gas Producing Activities +The results of operations for oil and gas producing activities (excluding marketing) are presented below: +Years Ended December 31, +2001 +2000 +1999 +Revenue: +Oil and gas sales +$25,887,900 +19,017,300 +8,628,400 +Expenses: +Production costs +6,012,400 +4,201,400 +2,422,000 +Depreciation, depletion and amortization +9,665,300 +6,031,200 +3,220,900 +15,677,700 +10,232,600 +5,642,900 +Results of operations for oil and gas producing activities before provision for income taxes +10,210,200 +8,874,700 +2,985,500 +Provision for income taxes +2,834,900 +2,713,900 +469,400 +Results of operations for oil and gas +producing activities (excluding corporate +overhead and interest costs) +$ 7,375,300 +6,070,800 +2,516,100 +======== +======= +======= +Production costs include those costs incurred to operate and maintain productive wells and related equipment, including such costs as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance and other production taxes. In addition, production costs include administrative expenses and depreciation applicable to support equipment associated with these activities. +Depreciation, depletion and amortization expense includes those costs associated with capitalized acquisition, exploration and development costs, but does not include the depreciation applicable to support equipment. +The provision for income taxes is computed at the statutory federal income tax rate and is reduced to the extent of permanent differences, such as investment tax and non-conventional source fuel tax credits and statutory depletion allowed for income tax purposes. +(17) Net Proved Oil and Gas Reserves (Unaudited) +The proved reserves of oil and gas of the Company have been estimated by an independent petroleum engineer, Wright & Company, Inc. at December 31, 2001, 2000 and 1999. These reserves have been prepared in compliance with the Securities and Exchange Commission rules based on year end prices. An analysis of the change in estimated quantities of oil and gas reserves, all of which are located within the United States, is shown below: +(Continued) +F-20 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +Oil (BBLS) +2001 +2000 +1999 +Proved developed and +Undeveloped reserves: +Beginning of year +2,166,000 +1,154,000 +29,000 +Revisions of previous estimates +(176,000 ) +10,000 +67,000 +Beginning of year as revised +1,990,000 +1,164,000 +96,000 +New discoveries and extensions +Michigan basin +- +265,000 +- +Rocky Mountain region +715,000 +535,000 +404,000 +Dispositions to partnerships +(384,000) +(262,000) +- +Acquisitions +Rocky Mountain region +- +573,000 +652,000 +Appalachian basin +- +- +10,000 +Production +(195,000 ) +(109,000 ) +(8,000 ) +End of year +2,126,000 +2,166,000 +1,154,000 +========= +========= +========= +Proved developed reserves: +Beginning of year +1,527,000 +798,000 +29,000 +======== +======== +========= +End of year +1,801,000 +1,527,000 +798,000 +======== +======== +========= +Gas (MCF) +2001 +2000 +1999 +Proved developed and undeveloped reserves: +Beginning of year +118,640,000 +101,245,000 +80,819,000 +Revisions of previous estimates +(8,694,000 ) +(3,859,000 ) +(4,475,000 ) +Beginning of year as revised +109,946,000 +97,386,000 +76,344,000 +New discoveries and extensions +Michigan basin +- +14,191,000 +4,559,000 +Rocky Mountain region +23,896,000 +14,603 +14,044 +Other +- +266,000 +6,178,000 +Dispositions to partnerships +(9,263,000) +(8,498,000) +(8,774,000) +Acquisitions +Rocky Mountain region +2,000 +5,761,000 +5,546,000 +Appalachian basin +112,000 +668,000 +6,799,000 +Production +( 6,085,000 ) +(5,737,000 ) +(3,451,000 ) +End of year +118,608,000 +118,640,000 +101,245,000 +========= +========== +========== +Proved developed reserves: +Beginning of year +92,131,000 +82,628,000 +64,562,000 +========= +========== +========== +End of year +88,477,000 +92,131,000 +82,628,000 +========= +========== +========== +(18) Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves (Unaudited) +Summarized in the following table is information for the Company with respect to the standardized measure of discounted future net cash flows relating to proved oil and gas reserves. Future cash inflows are computed by applying year-end prices, adjusted for hedging contracts, of oil and gas relating to the Company's proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the statutory rate in effect at the end of each year to the future pretax net cash flows, less the tax basis of the properties and gives effect to permanent differences, tax credits and allowances related to the properties. +F-21 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +Years Ended December 31, +2001 +2000 +1999 +Future estimated cash flows +$317,515,000 +520,010,000 +307,816,000 +Future estimated production costs +(98,538,000) +(144,505,000) +(104,233,000) +Future estimated development costs +(45,323,000) +(50,278,000) +(25,324,000) +Future estimated income tax expense +(50,360,000 ) +(80,982,000 ) +(39,930,000 ) +Future net cash flows +123,294,000 +244,245,000 +138,329,000 +10% annual discount for estimated +timing of cash flows +( 76,855,000 ) +(139,606,000 ) +(79,875,000 ) +Standardized measure of discounted future +estimated net cash flows +$46,439,000 +104,639,000 +58,454,000 +========= +========== +========= +The following table summarizes the principal sources of change in the standardized measure of discounted future estimated net cash flows: +Years Ended December 31, +2001 +2000 +1999 +Sales of oil and gas production, net of +production costs +$(19,876,000) +(14,816,000) +(6,206,000) +Net changes in prices and production costs +(140,487,000) +67,460,000 +15,897,000 +Extensions, discoveries and improved recovery, +less related cost +25,942,000 +73,636,000 +39,653,000 +Dispositions to partnerships +(28,935,000) +(16,850,000) +(6,152,000) +Acquisitions +189,000 +27,907,000 +31,915,000 +Development costs incurred during the period +35,412,000 +15,556,000 +17,168,000 +Revisions of previous quantity estimates +(23,818,000) +(5,925,000) +(4,944,000) +Changes in estimated income taxes +30,622,000 +(41,052,000) +(19,608,000) +Accretion of discount +62,751,000 +(59,731,000 ) +(39,463,000 ) +$ (58,200,000) +46,185,000 +28,260,000 +========== +======== +========= +It is necessary to emphasize that the data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein. +F-22 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +(19) Business Segments (Thousands) +PDC's operating activities can be divided into three major segments: drilling and development, natural gas sales, and well operations. The Company drills natural gas wells for Company-sponsored drilling partnerships and retains an interest in each well. The Company also engages in oil and gas sales to commercial and industrial end-users. The Company charges Company-sponsored partnerships and other third parties competitive industry rates for well operations and gas gathering. Segment information for the years ended December 31, 2001, 2000 and 1999 is as follows: +2001 +2000 +1999 +REVENUES +Drilling and Development +$76,291 +43,195 +42,116 +Natural Gas Sales +92,095 +90,420 +46,988 +Well Operations +5,604 +5,061 +5,314 +Unallocated amounts (1) +3,133 +2,540 +2,392 +Total +$177,123 +141,216 +96,810 +====== +====== +====== +(1) Includes interest on investments and partnership management fees in 2001, 2000 and 1999 and gain on sale +of assets in 2000 and 1999 which are not allocated in assessing segment performance. +2001 +2000 +1999 +SEGMENT INCOME BEFORE INCOME TAXES +Drilling and Development +$10,291 +7,950 +6,608 +Natural Gas Sales +10,570 +7,364 +2,967 +Well Operations +2,415 +1,385 +1,219 +Unallocated amounts (2) +General and Administrative expenses +(4,146) +(3,617) +(2,801) +Interest expense +(993) +(1,186) +(182) +Other (1) +2,946 +2,378 +2,289 +Total +$ 21,083 +14,274 +10,100 +======= +======= +====== +(2) Items which are not allocated in assessing segment performance. +2001 +2000 +1999 +SEGMENT ASSETS +Drilling and Development +$ 36,202 +31,592 +23,957 +Natural Gas Sales +142,865 +139,116 +93,073 +Well Operations +11,975 +8,490 +7,977 +Unallocated amounts +Cash +422 +1,567 +1,967 +Other +8,388 +6,920 +5,110 +Total +$199,852 +187,685 +132,084 +===== +===== +===== +2001 +2000 +1999 +EXPENDITURES FOR SEGMENT +LONG-LIVED ASSETS +Drilling and Development +$ 5,963 +3,217 +1,710 +Natural Gas Sales +35,488 +23,958 +24,613 +Well Operations +839 +650 +1,328 +Unallocated amounts +371 +107 +107 +Total +$ 42,661 +27,932 +27,758 +======= +======= +======= +F-23 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +(20) Quarterly Financial Data (Unaudited ) +Summarized quarterly financial data for the years ended December 31, 2001 and 2000, are as follows: +2001 +Quarter +Year +First +Second +Third +Fourth +Revenues +$59,541,400 +$47,129,000 +$33,336,600 +$37,116,100 +$177,123,100 +Cost of operations +50,330,400 +40,465,600 +27,546,300 +32,558,900 +150,901,200 +Gross profit +9,211,000 +6,663,400 +5,790,300 +4,557,200 +26,221,900 +General and administrative +expenses +961,400 +998,400 +1,143,200 +1,042,700 +4,145,700 +Interest expense +213,900 +213,700 +249,400 +316,400 +993,400 +1,175,300 +1,212,100 +1,392,600 +1,359,100 +5,139,100 +Income before +income taxes +8,035,700 +5,451,300 +4,397,700 +3,198,100 +21,082,800 +Income taxes +2,410,700 +1,635,400 +1,220,200 +848,700 +6,115,000 +Net income +$5,625,000 +$ 3,815,900 +$ 3,177,500 +$ 2,349,400 +$14,967,800 +======= +======== +======== +======== +======== +Basic earnings per share +$ .35 +$ .23 +$ .20 +$ .14 +$ .92 +=== +=== +=== +=== +=== +Diluted earnings per share +$ .34 +$ .23 +$ .19 +$ .14 +$ .90 +=== +=== +=== +=== +=== +2000 +Quarter +Year +First +Second +Third +Fourth +Revenues +$34,504,400 +$29,063,200 +$32,818,600 +$44,830,300 +$141,216,500 +Cost of operations +29,600,900 +25,225,800 +28,646,900 +38,666,300 +122,139,900 +Gross profit +4,903,500 +3,837,400 +4,171,700 +6,164,000 +19,076,600 +General and administrative +expenses +679,200 +1,032,300 +1,038,300 +867,100 +3,616,900 +Interest expense +14,600 +275,400 +437,500 +458,500 +1,186,000 +693,800 +1,307,700 +1,475,800 +1,325,600 +4,802,900 +Income before income taxes +4,209,700 +2,529,700 +2,695,900 +4,838,400 +14,273,700 +Income taxes +968,300 +581,900 +555,000 +1,487,500 +3,592,700 +Net income +$3,241,400 +$ 1,947,800 +$ 2,140,900 +$ 3,350,900 +$10,681,000 +======= +======== +======== +======== +======== +Basic earnings per share +$ .20 +$ .12 +$ .13 +$ .21 +$ .66 +=== +=== +=== +=== +=== +Diluted earnings per share +$ .20 +$ .12 +$ .13 +$ .20 +$ .65 +=== +=== +=== +=== +=== +Cost of operations include cost of oil and gas well drilling operations, oil and gas purchases and production costs and depreciation, depletion and amortization. +F-24 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS +AND RESERVES +Years Ended December 31, 2001, 2000 and 1999 +Column A +Column B +Column C +Column D +Column E +Additions, +Balance at +Charged to +Balance +Beginning +Costs and +at End +Description +of Period +Expenses +Deductions +of Period +Allowance for doubtful accounts deducted +from accounts and notes receivable in the +balance sheet +2001 +$524,500 +$ - +$ - +$524,500 +====== +====== +====== +====== +2000 +$438,400 +$573,000 +$486,900 +$524,500 +====== +====== +====== +====== +1999 +$274,600 +$272,500 +$108,700 +$438,400 +====== +====== +====== +====== +F-25 \ No newline at end of file diff --git a/raw/filings/0000077877/2001/0000077877-02-000003/filing_metadata.csv b/raw/filings/0000077877/2001/0000077877-02-000003/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..02bcad66166125d6c4dc67e085cfe86550cfe11b --- /dev/null +++ b/raw/filings/0000077877/2001/0000077877-02-000003/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 +0000077877,PDCE,"PDC ENERGY, INC.",10-K,2002-03-15,2001-12-31,2002-03-15T05:00:00.000Z,0000077877-02-000003,pdc200110k1.htm,PDC 2001 10K HTML,784116,0,0,https://www.sec.gov/Archives/edgar/data/77877/000007787702000003/pdc200110k1.htm,https://www.sec.gov/Archives/edgar/data/77877/000007787702000003/,2001,2001,1 diff --git a/raw/filings/0000077877/2001/0000077877-02-000003/item1.txt b/raw/filings/0000077877/2001/0000077877-02-000003/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..23a10a9b9e82c06739b0f722494ac14982593521 --- /dev/null +++ b/raw/filings/0000077877/2001/0000077877-02-000003/item1.txt @@ -0,0 +1,97 @@ +Item 1. Business +The Company is an independent energy company engaged primarily in the development, production and marketing of natural gas and oil. The Company has grown primarily through drilling and development activities, the acquisition of natural gas and oil producing wells and the expansion of its natural gas marketing activities. As of December 31, 2001, the Company operates approximately 2,150 wells located in the Appalachian basin, Michigan, and the Rocky Mountain Region, with gross proved reserves of 328 billion cubic feet equivalent of natural gas ("Bcfe", based on one barrel of oil equals 6 thousand cubic feet equivalent of natural gas ("Mcfe")) of which the Company's share is 131 Bcfe. The wells operated by the Company currently produce an aggregate of approximately 50,000 thousand cubic feet equivalent of gas per day, of which the Company's share is approximately 21,400 Mcfe. +The Company's operations are divided into three regions, the Appalachian Basin, Michigan Basin, and the Rocky Mountain Region. The Company has conducted operations in Appalachian Basin since its inception in 1969, in Michigan Basin since 1997, and the Rocky Mountain Region since 1999. During 2001 approximately 31% of production was generated by Appalachian Basin wells, 34% by Michigan Basin wells and 35% by Rocky Mountain wells. As of the end of 2001, the Company's total proved reserves were located as follows: Appalachian Basin 32%, Michigan Basin 21% and Rocky Mountain Region 47%. The majority of the Company's undeveloped reserves are in the Rocky Mountain Region and the planned drilling for 2002 will be focused in that area. +In all three regions the Company has historically targeted shallow, developmental natural gas reserves for development. In some areas of the Rocky Mountain Region, Michigan and the Appalachian Basin the wells also produce oil in conjunction with natural gas. +The Company owns Riley Natural Gas (RNG), a natural gas marketing company, which aggregates and resells natural gas developed by the Company and other producers. This allows the Company to diversify its operations beyond natural gas drilling and production. RNG has established relationships with many of the natural gas producers in the Appalachian Basin and has significant expertise in the natural gas end-user market. In addition, RNG has extensive experience in the use of hedging strategies, which the Company utilizes to reduce the financial impact on the Company of changes in the price of natural gas. +Since 1984, the Company has sponsored limited partnerships formed to engage in drilling operations. The Company typically retains a 20% ownership interest in these drilling limited partnerships. In 2001, the Company raised $57.1 million through four public drilling partnerships, making it the sponsor of the largest public oil and gas partnership program in the United States in that year. The drilling programs have provided the Company with access to the capital resources necessary to expand its drilling opportunities and to maintain the infrastructure necessary to support such activities. +Industry Overview +Natural gas is the second largest energy source in the United States, after liquid petroleum. The 21.5 Tcf of natural gas consumed in 2001 represented approximately 23% of the total energy used in the United States. Natural gas is consumed in the United States as follows: 42% by industrial end-users as feedstock for products such as plastic and fertilizer or as the energy source for producing products such as glass; 22% and 15% by residential and commercial end-users, respectively, for uses including heating, cooling and cooking; 14% by utilities for the generation of electricity; and the remainder for transportation purposes. (Source U.S. Energy Information Administration) +-2- +The Company believes that the market for natural gas will grow in the future. The demand for natural gas has increased due to four main factors: +- Efficiency. Relative to other energy sources, natural gas losses during transportation from source to destination are slight, averaging only about 9% of the natural gas energy. +- Environmentally favorable. Natural gas is the cleanest and most environmentally safe of the fossil fuels. +- Safety. The delivery of natural gas is among the safest means of distributing energy to customers, as the natural gas transmission system is fixed and is located underground. +- Price. The deregulation of the natural gas industry and a favorable regulatory environment have resulted in end-users' ability to purchase natural gas on a competitive basis from a greater variety of sources. +The Company believes that the foregoing factors, together with the increased availability of natural gas as a form of energy for residential, commercial and industrial uses, should increase the demand for natural gas as well as create new markets for natural gas. +As local supplies of natural gas are inadequate to meet demand, the West Coast and the Northeast import natural gas from producing areas via interstate natural gas pipelines. The cost of transporting natural gas from the major producing areas to markets creates a price advantage for production located closer to the consuming regions. The natural gas industry in the Appalachian Basin and Michigan benefit from proximity to the northeastern United States. +In the early 1980's, natural gas companies began exploiting the northern portion of Michigan's lower peninsula, when certain favorable tax credits for natural gas development were enacted. The result of such development was new advances in drilling technology, which made natural gas drilling in this area profitable even after the expiration of these tax credits. In Michigan's lower peninsula, there is an abundance of shallow Antrim gas shale, which can provide significant reserves per well drilled. Additionally, this area is close to certain end-user markets, which has provided favorable premiums. +During 1998 the Company began to establish a lease position in the Rocky Mountain producing region. The region is believed to hold substantial undeveloped natural gas resources. Recent additions to pipeline capacity in the region have made the area more attractive for development. Gas from the region will generally sell for less than gas in the Appalachian and Michigan Basins, but costs of development are expected to be less. The Company currently has over 200 development locations in Wattenberg field, and 58,000 acres available for development in the Piceance Basin. +Business Strategy +The Company's objective is to expand its natural gas reserves, production and revenues through a strategy that includes the following key elements: +-3- +Expand drilling operations. For its size, the Company has had one of the most active drilling programs in the country. The Company drilled 141 wells in 2001, compared to 97 wells in 2000. The Company believes that it will be able to drill a substantial number of new wells on its current undeveloped leased properties. As of December 31, 2001, the Company had development rights to 4,200 undeveloped acres in the Michigan Basin, 5,400 undeveloped acres in the Appalachian Basin and 125,600 undeveloped acres in the Rocky Mountain Region. As drilling activity increases, the Company benefits as its fixed costs may be spread over a larger number of wells. +Acquire producing properties. The Company's acquisition efforts are focused on properties that fit well within existing operations or that help to build critical mass in areas where the Company is establishing new operations. Acquisitions will likely offer economies in management and administration, and therefore the Company believes that it will be able to acquire more producing wells without incurring substantial increases in its administrative costs. +Pursue geographic expansion. The Company has proven its ability to drill and operate in geographically diverse domestic areas. Since 1996, the Company expanded its operations from the Appalachian Basin, first to Michigan, and more recently to the Rocky Mountains. Currently, the Company's production is divided almost equally among the three areas. The Company plans to conduct the majority of its drilling activities in the Rocky Mountain region during 2002, but will continue to seek additional opportunities for expansion to areas where the Company's experience and expertise can be applied successfully. +Reduce risks inherent in natural gas development and marketing. An integral part of the Company's strategy has been and will continue to be to concentrate on shallow development, (rather than exploratory) drilling, and geographical diversification to reduce risk levels associated with natural gas and oil production. Development drilling is less risky than exploratory drilling and is likely to generate cash returns more quickly. The focus on shallow wells builds on the Company's knowledge and experience, and also provides greater investment diversification than an equal investment in a smaller number of deeper and/or more expensive wells. Geographical diversification can help to offset possible weakness in the natural gas market or disappointing drilling results in one area. The Company believes that successful natural gas marketing is essential to profitable operations in a deregulated gas market. To further this goal, the Company has the expertise of RNG, an experienced natural gas marketer. The Company intends to continue to expand its marketing capabilities to keep pace with the changing natural gas industry. +Exploration and Development Activities +The Company's development activities focus on the identification and drilling of new productive wells and the acquisition of existing producing wells from other producers. +Prospect Generation +The Company's staff of professional geologists is responsible for identifying areas with potential for economic production of natural gas and oil. These geologists have decades of cumulative experience drilling natural gas and oil wells. They utilize results from logs and other tools to evaluate existing wells and to predict the location of attractive new gas reserves. To further this process, the Company has collected and continues to collect logs, core data, production information and other raw data available from state and private agencies, other companies and individuals actively drilling in the regions being evaluated. From this information the geologists develop models of the subsurface structures and stratigraphy that are used to predict areas with above-average prospects for economic development. +-4- +On the basis of these models, the geologists instruct the Company's land department to obtain available natural gas leaseholds in these prospective areas. These leases are then obtained, if possible, by the Company's land department or contract landmen under the direction of the Company's land manager. In most cases, the Company pays a lease bonus and annual rental payments, converting, upon initiation of production, to a royalty on gross production revenue in return for obtaining the leases. In addition overriding royalty payments may be made to third parties in conjunction with the acquisition of drilling rights initially leased by others. As of December 31, 2001, the Company had a total leasehold inventory of approximately 246,080 acres. See--"Properties--Natural Gas Leases." +Drilling Activities +When prospects have been identified and leased, the Company develops these properties by drilling wells. In 2001, the Company drilled a total of 141 wells, with six dry holes. Typically, the Company will act as driller-operator for these prospects, entering into contracts with partnerships, including Company-sponsored partnerships, and other entities that are interested in exploration or development of the prospects. The Company generally retains an interest in each well it drills. See "Financing of Drilling Activities." +Much of the work associated with drilling, completing and connecting wells, including drilling, fracturing, logging and pipeline construction, is performed by subcontractors specializing in those operations, as is common in the industry. A large part of the material and services used by the Company in the development process is acquired through competitive bidding by approved vendors. The Company also directly negotiates rates and costs for services and supplies when conditions indicate that such an approach is warranted. As the prices paid to the Company by its investor partners for the Company's services are frequently fixed before the wells are drilled or are determined solely on the well depth, the Company is subject to the risk that prices of goods or services used in the development process could increase, rendering its contracts with its investor partners less profitable or unprofitable. In addition, problems encountered in the process can substantially increase development costs, sometimes without recourse for the Company to recover its costs from its partners. To minimize these risks, the Company seeks to lock in its development costs in advance of drilling and, when possible, at the time of negotiation and execution of its investor partnership agreements. +Acquisitions of Producing Properties +In addition to drilling new wells, the Company continues to pursue opportunities to purchase existing wells from other producers and greater ownership interests in the wells it operates. Generally, outside interests purchased include a majority interest in the wells and well operations. +During 1999, the Company purchased a 100% working interest in 53 producing wells in the D-J Basin of Colorado which added 3.6 Bcf of natural gas and 370,000 barrels of oil to the Company's reserves. During 2000, the Company purchased 100% of the working interest in 168 producing wells in the DJ Basin of Colorado which added 4.9 Bcf of natural gas and 560,000 barrels of oil to the Company's reserves. Certain well interests in its Company sponsored partnerships were also purchased in 1999, 2000 and 2001. +-5- +Production +The following table shows the Company's net production in Bbls of crude oil and in Mcf of natural gas and the costs and weighted average selling prices thereof, for the last five years. +Year Ended December 31, +2001 +2000 +1999 +1998 +1997 +Production(1): +Oil(MBbls) +195 +109 +8 +8 +9 +Natural Gas (MMcf) +6,085 +5,737 +3,451 +2,453 +1,810 +Equivalent MMcfs(2) +7,255 +6,391 +3,499 +2,501 +1,864 +Average sales price: +Oil (per Bbl) +$22.53 +$29.99 +$18.75 +$10.61 +$16.10 +Natural gas (per Mcf)(3) +$3.53 +$2.74 +$2.46 +$2.46 +$2.88 +Average production cost (lifting cost) +per equivalent Mcf(4) +$0.83 +$0.66 +$0.69 +$0.61 +$0.65 +---------- +(1) Production as shown in the table is net to the Company and is determined by multiplying the gross production volume of properties in which the Company has an interest by the percentage of the leasehold or other property interest owned by the Company. +(2) A ratio of energy content of natural gas and oil (six Mcf of natural gas equals one barrel of oil) was used to obtain a conversion factor to convert oil production into equivalent Mcfs of natural gas. +(3) The Company utilizes commodity-based derivative instruments as hedges to manage a portion of its exposure to price volatility of its natural gas sales. The effect of hedges on the average sales price of natural gas for the years ended December 31, 2001, 2000, 1999 and 1998 was $(0.56), $(0.91), $(0.01) and $0.14, respectively. +(4) Production costs represent oil and gas operating expenses as reflected in the financial statements of the Company. +Well Operations +The Company currently operates approximately 1,523 wells in the Appalachian Basin, 219 wells in the Michigan Basin and 400 wells in the Rocky Mountain Region. The Company's ownership interest in these wells ranges from 0% to 100%, and, on average, the Company has an approximate 51% ownership interest in the wells it operates. Currently these wells produce an aggregate of about 50,000 Mcfe of natural gas per day, including the Company's share of 21,400 Mcfe per day. +The Company is paid a monthly operating charge for each well it operates for outside owners. The rate is competitive with rates charged by other operators in the area. The charge covers monthly operating and accounting costs, insurance and other recurring costs. The Company may also receive additional compensation for special non-recurring activities, such as reworks and recompletions. +Transportation +Natural gas wells are connected by pipelines to natural gas markets. Over the years, the Company has developed extensive gathering systems in some of its areas of operations. The Company also continues to construct new trunklines as necessary to provide for the marketing of natural gas being developed from new areas and to enhance or maintain its existing systems. +The Company is paid a transportation fee for natural gas that is moved by other producers through these pipeline systems. In many cases the Company has been able to receive higher natural gas prices as a result of its ability to move natural gas to more attractive markets through this pipeline system, to the benefit of both the Company and its investor partners. +-6- \ No newline at end of file diff --git a/raw/filings/0000077877/2001/0000077877-02-000003/item13.txt b/raw/filings/0000077877/2001/0000077877-02-000003/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..f17c031312401b7732ca9bea578ba0b22922501f --- /dev/null +++ b/raw/filings/0000077877/2001/0000077877-02-000003/item13.txt @@ -0,0 +1,2 @@ +Item 13. Certain Relationships and Related Transactions +The response to this item is set forth herein in Note 8 in the Notes to Consolidated Financial Statements. \ No newline at end of file diff --git a/raw/filings/0000077877/2001/0000077877-02-000003/item9a.txt b/raw/filings/0000077877/2001/0000077877-02-000003/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2001/0000077877-02-000003/rp_note.txt b/raw/filings/0000077877/2001/0000077877-02-000003/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2001/0000077877-02-000003/rpt_disclosure.txt b/raw/filings/0000077877/2001/0000077877-02-000003/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2002/0000077877-03-000003/filing.txt b/raw/filings/0000077877/2002/0000077877-03-000003/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..1c08b5f0445c1202f0a0a7ef7f99e3801e48bb3c --- /dev/null +++ b/raw/filings/0000077877/2002/0000077877-03-000003/filing.txt @@ -0,0 +1,2815 @@ +10-K +1 +pdc10k2002.htm +PDC 2002 FORM 10-K +CONFORMED COPY +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +[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 +Commission File Number 0-7246 +[] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transaction period from to +PETROLEUM DEVELOPMENT CORPORATION +(Exact name of registrant as specified in its charter) +Nevada +95-2636730 +(State or other jurisdiction of +(I.R.S. Employer +incorporation or organization) +Identification No.) +103 East Main Street, Bridgeport, West Virginia 26330 +(Address of principal executive offices) (zip code) +Registrant's telephone number, including area code (304) 842-3597 +SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: NONE +SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: +Petroleum Development Corporation Common Stock, $.01 par value +(Title of class) +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 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 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 definition in Rule 12b-2 of the Exchange Act). Yes X No +As of March 5, 2003, 15,734,767 shares of the Registrant's Common Stock were issued and outstanding, and the aggregate market value of such shares held by non-affiliates of the Registrant on such date was $67,881,269 (based on the last traded price of $5.80). +DOCUMENTS INCORPORATED BY REFERENCE +Document +Form 10-K Part III +Proxy +Items 10, 11, 12, and 13 +(except as presented herein) +PART I +Item 1. Business +The Company is an independent energy company engaged primarily in the development, production and marketing of natural gas and oil. The Company has grown primarily through drilling and development activities, the acquisition of natural gas and oil producing wells and the expansion of its natural gas marketing activities. As of December 31, 2002, the Company operates approximately 2,200 wells located in the Appalachian basin, Michigan, and the Rocky Mountain Region, with gross proved reserves of 364 billion cubic feet equivalent of natural gas ("Bcfe", based on one barrel of oil equals 6 thousand cubic feet equivalent of natural gas ("Mcfe")) of which the Company's share is 141 Bcfe. The wells operated by the Company currently produce an aggregate of approximately 55,000 thousand cubic feet equivalent of gas per day, of which the Company's share is approximately 21,500 Mcfe. +The Company's operations are divided into three regions, the Appalachian Basin, Michigan Basin, and the Rocky Mountain Region. The Company has conducted operations in Appalachian Basin since its inception in 1969, in Michigan Basin since 1997, and the Rocky Mountain Region since 1999. During 2002 approximately 27% of production was generated by Appalachian Basin wells, 28% by Michigan Basin wells and 45% by Rocky Mountain wells. As of the end of 2002, the Company's total proved reserves were located as follows: Appalachian Basin 32%, Michigan Basin 20% and Rocky Mountain Region 48%. The majority of the Company's undeveloped reserves are in the Rocky Mountain Region and the planned drilling for 2003 will be focused in that area. +In all three regions the Company has historically targeted shallow, developmental natural gas reserves for development. In some areas of the Rocky Mountain Region, Michigan and the Appalachian Basin the wells also produce oil in conjunction with natural gas. +The Company owns Riley Natural Gas (RNG), a natural gas marketing company, which aggregates and resells natural gas developed by the Company and other producers. This allows the Company to diversify its operations beyond natural gas drilling and production. RNG has established relationships with many of the natural gas producers in the Appalachian Basin and has significant expertise in the natural gas end-user market. In addition, RNG has extensive experience in the use of hedging strategies, which the Company utilizes to manage the financial impact on the Company of changes in the price of natural gas. +Since 1984, the Company has sponsored limited partnerships formed to engage in drilling operations. The Company typically purchases a 20% ownership interest in these drilling limited partnerships. In 2002, the Company, through four public drilling partnerships, raised $56.9 million making it the sponsor of the largest public oil and gas partnership program in the United States as it has been for the last several years. The drilling programs have provided the Company with access to the capital resources necessary to expand its drilling opportunities and to maintain the infrastructure necessary to support such activities. +Available Information +The Company's Internet address is www.petd.com. Electronic copies of the Company's annual report on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, and amendments to those reports are available free of charge by visiting the "Investor Relations - Edgar Link" section of www.petd.com. These reports are posted as soon as reasonably practicable after they are electronically filed with the Securities and Exchange Commission. +Industry Overview +Natural gas is the second largest energy source in the United States, after liquid petroleum. The 21.5 Tcf of natural gas consumed in 2002 represented approximately 23% of the total energy used in the United States. Natural gas is consumed in the United States as follows: 37% by industrial end-users as feedstock for products such as plastic and fertilizer or as the energy source for producing products such as glass; 23% and 15% by residential and commercial end-users, respectively, for uses including heating, cooling and cooking; and 25% by utilities for the generation of electricity. (Source U.S. Energy Information Administration) +-2- +The Company believes that the market for natural gas will grow in the future. The demand for natural gas has increased due to four main factors: +Efficiency. Relative to other energy sources, natural gas losses during transportation from source to destination are slight, averaging only about 9% of the natural gas energy. +Environmentally favorable. Natural gas is the cleanest and most environmentally safe of the fossil fuels. +Safety. The delivery of natural gas is among the safest means of distributing energy to customers, as the natural gas transmission system is fixed and is located underground. +Price. The deregulation of the natural gas industry and a favorable regulatory environment have resulted in end-users' ability to purchase natural gas on a competitive basis from a greater variety of sources. +The Company believes that the foregoing factors, together with the increased availability of natural gas as a form of energy for residential, commercial and industrial uses, should increase the demand for natural gas as well as create new markets for natural gas. +As local supplies of natural gas are inadequate to meet demand in certain sections of the country, the West Coast and the Northeast import natural gas from producing areas via interstate natural gas pipelines. The cost of transporting natural gas from the major producing areas to markets creates a price advantage for production located closer to the consuming regions. The natural gas industry in the Appalachian Basin and Michigan benefit from proximity to the northeastern United States. In contrast, much of the production in the Rocky Mountains is transported significant distances to end use markets. +In the early 1980's, natural gas companies began exploiting the northern portion of Michigan's lower peninsula, when certain favorable tax credits for natural gas development were enacted. The result of such development was new advances in drilling technology, which made natural gas drilling in this area profitable even after the expiration of these tax credits. In Michigan's lower peninsula, there is an abundance of shallow Antrim gas shale, which can provide significant reserves per well drilled. Additionally, this area is close to certain end-user markets, which has provided favorable premiums in gas sales prices. +During 1998 the Company began to establish a lease position in the Rocky Mountain producing region. The region is believed to hold substantial undeveloped natural gas resources. Recent and planned additions to pipeline capacity in the region have made the area more attractive for development. Gas from the region will generally sell for less than gas in the Appalachian and Michigan Basins, but costs of development are expected to be less. The Company currently has over 150 development locations in the Wattenberg field in the DJ Basin, and 63,000 acres available for development in the Piceance Basin, both basins are located in Colorado. +Business Strategy +The Company's objective is to expand its natural gas reserves, production and revenues through a strategy that includes the following key elements: +-3- +Expand drilling operations. For its size, the Company has had one of the most active drilling programs in the country. The Company drilled 70 wells in 2002, compared to 141 wells in 2001. The Company believes that it will be able to drill a substantial number of new wells on its current undeveloped leased properties. As of December 31, 2002, the Company had leases or other development rights to 3,500 undeveloped acres in the Michigan Basin, 950 undeveloped acres in the Appalachian Basin and 69,300 undeveloped acres in the Rocky Mountain Region. As drilling activity increases, the Company benefits as its fixed costs may be spread over a larger number of wells. +Acquire producing properties. The Company's acquisition efforts are focused on properties that fit well within existing operations or that help to build critical mass in areas where the Company is establishing new operations. Acquisitions will likely offer economies in management and administration, and therefore the Company believes that it will be able to acquire more producing wells without incurring substantial increases in its administrative costs. +Pursue geographic expansion. The Company has proven its ability to drill and operate in geographically diverse domestic areas. Since 1996, the Company expanded its operations from the Appalachian Basin, first to Michigan, and more recently to the Rocky Mountains. In 2002 over two-thirds of the Company's production was generated in the two newer regions. The Company plans to conduct the majority of its drilling activities in the Rocky Mountain region during 2003, but will continue to seek additional opportunities for expansion to areas where the Company's experience and expertise can be applied successfully. +Reduce risks inherent in natural gas development and marketing. An integral part of the Company's strategy has been and will continue to be to concentrate on shallow development, (rather than exploratory) drilling, and geographical diversification to reduce risk levels associated with natural gas and oil production. Development drilling is less risky than exploratory drilling and is likely to generate cash returns more quickly. The focus on shallow wells builds on the Company's knowledge and experience, and also provides greater investment diversification than an equal investment in a smaller number of deeper and/or more expensive wells. Geographical diversification can help to offset possible weakness in the natural gas market or disappointing drilling results in one area. The Company believes that successful natural gas marketing is essential to profitable operations in a deregulated gas market. To further this goal, the Company has the expertise of RNG, an experienced natural gas marketer. The Company also uses natural gas and oil hedges to reduce the effects of volatility of energy prices. The Company intends to continue to expand its marketing capabilities to keep pace with the changing natural gas industry. +Exploration and Development Activities +The Company's development activities focus on the identification and drilling of new productive wells and the acquisition of existing producing wells from other producers. +Prospect Generation +The Company's staff of professional geologists is responsible for identifying areas with potential for economic production of natural gas and oil. These geologists have decades of cumulative experience drilling natural gas and oil wells. They utilize results from logs and other tools to evaluate existing wells and to predict the location of attractive new gas reserves. To further this process, the Company has collected and continues to collect logs, core data, production information and other raw data available from state and private agencies, other companies and individuals actively drilling in the regions being evaluated. From this information the geologists develop models of the subsurface structures and formations that are used to predict areas with above-average prospects for economic development. +-4- +On the basis of these models, the geologists instruct the Company's land department to obtain available natural gas leaseholds, farmouts and other development rights in these prospective areas. These rights are then obtained, if possible, by the Company's land department or contract landmen under the direction of the Company's land manager. In most cases, the Company pays a lease bonus and annual rental payments, converting, upon initiation of production, to a royalty on gross production revenue in return for obtaining the leases. In addition overriding royalty payments may be made to third parties in conjunction with the acquisition of drilling rights initially leased by others. As of December 31, 2002, the Company had a total leasehold inventory of approximately 183,950 acres. See--"Properties--Oil and Natural Gas Leases." +Drilling Activities +When prospects have been identified and leased, the Company develops these properties by drilling wells. In 2002, the Company drilled a total of 70 wells all of which were successfully completed as producing wells. Typically, the Company will act as driller-operator for these prospects, entering into contracts with partnerships, primarily Company-sponsored partnerships, and other entities that are interested in exploration or development of the prospects. The Company generally retains an interest in each well it drills. See "Financing of Drilling Activities." +Much of the work associated with drilling, completing and connecting wells, including drilling, fracturing, logging and pipeline construction, is performed by subcontractors specializing in those operations, as is common in the industry. A large part of the material and services used by the Company in the development process is acquired through competitive bidding by approved vendors. The Company also directly negotiates rates and costs for services and supplies when conditions indicate that such an approach is warranted. As the prices paid to the Company by its investor partners for the Company's services are frequently fixed before the wells are drilled or are determined solely on the well depth, the Company is subject to the risk that prices of goods or services used in the development process could increase, rendering its contracts with its investor partners less profitable or unprofitable. In addition, problems encountered in the process can substantially increase development costs, sometimes without recourse for the Company to recover its costs from its partners. To minimize these risks, the Company seeks to lock in its development costs in advance of drilling and, when possible, at the time of negotiation and execution of its investor partnership agreements. +Acquisitions of Producing Properties +In addition to drilling new wells, the Company continues to pursue opportunities to purchase existing wells from other producers and greater ownership interests in the wells it operates. Generally, outside interests purchased include a majority interest in the wells and well operations. +During 1999, the Company purchased a 100% working interest in 53 producing wells in the D-J Basin of Colorado which added 3.6 Bcf of natural gas and 370,000 barrels of oil to the Company's reserves. During 2000, the Company purchased 100% of the working interest in 168 producing wells in the DJ Basin of Colorado which added 4.9 Bcf of natural gas and 560,000 barrels of oil to the Company's reserves. Certain well interests in its Company sponsored partnerships were also purchased in 2002, 2001 and 2000. +-5- +Production +The following table shows the Company's net production in Bbls of crude oil and in Mcf of natural gas and the costs and weighted average selling prices thereof, for the last five years. +Year Ended December 31, +2002 +2001 +2000 +1999 +1998 +Production(1): +Oil(MBbls) +227 +195 +109 +8 +8 +Natural Gas (MMcf) +6,462 +6,085 +5,737 +3,451 +2,453 +Equivalent MMcfs(2) +7,824 +7,255 +6,391 +3,499 +2,501 +Average sales price: +Oil (per Bbl) +$24.41 +$22.53 +$29.99 +$18.75 +$10.61 +Natural gas (per Mcf)(3) +$2.68 +$3.53 +$2.74 +$2.46 +$2.46 +Average production cost (lifting cost) Per equivalent Mcf(4) +$0.82 +$0.83 +$0.66 +$0.69 +$0.61 +---------- +(1) Production as shown in the table is net to the Company and is determined by multiplying the gross production volume of properties in which the Company has an interest by the percentage of the leasehold or other property interest owned by the Company. +(2) A ratio of energy content of natural gas and oil (six Mcf of natural gas equals one barrel of oil) was used to obtain a conversion factor to convert oil production into equivalent Mcfs of natural gas. +(3) The Company utilizes commodity-based derivative instruments as hedges to manage a portion of its exposure to price volatility of its natural gas sales. The effect of hedges on the average sales price of natural gas for the years ended December 31, 2002, 2001, 2000, 1999 and 1998 was $0.02, $(0.56), $(0.91), $(0.01) and $0.14, respectively. +(4) Production costs represent oil and gas operating expenses as reflected in the financial statements of the Company. +Well Operations +The Company currently operates approximately 1,502 wells in the Appalachian Basin, 204 wells in the Michigan Basin and 463 wells in the Rocky Mountain Region. The Company's ownership interest in these wells ranges from 0% to 100%, and, on average, the Company has an approximate 50% ownership interest in the wells it operates. Currently these wells produce an aggregate of about 55,000 Mcfe of natural gas per day, including the Company's share of 21,500 Mcfe per day. +The Company is paid a monthly operating charge for each well it operates for outside owners. The rate is competitive with rates charged by other operators in the area. The charge covers monthly operating and accounting costs, insurance and other recurring costs. The Company may also receive additional compensation for special non-recurring activities, such as reworks and recompletions. +Transportation +Natural gas wells are connected by pipelines to natural gas markets. Over the years, the Company has developed extensive gathering systems in some of its areas of operations. The Company also continues to construct new trunklines as necessary to provide for the marketing of natural gas being developed from new areas and to enhance or maintain its existing systems. +The Company is paid a transportation fee for natural gas that is moved by other shippers through these pipeline systems. In many cases the Company has been able to receive higher natural gas prices as a result of its ability to move natural gas to more attractive markets through this pipeline system, to the benefit of both the Company and its investor partners. +-6- +Item 2. Properties +Drilling Activity +The following table summarizes the Company's development drilling activity for the years ended December 31, 1998, 1999, 2000, 2001 and 2002. There is no correlation between the number of productive wells completed during any period and the aggregate reserves attributable to those wells. The Company's exploratory wells drilled in the past five years consist of one dry hole (0.19 net) drilled in 1998 and five dry holes (2.44 net) drilled in 1999. +Development Wells Drilled +Total +Productive +Dry +Drilled +Net +Drilled +Net +Drilled +Net +1998 +212 +56.99 +201 +54.22 +11 +2.77 +1999 +173 +54.64 +165 +53.10 +8 +1.54 +2000 +97 +27.39 +97 +27.39 +- +- +2001 +141 +40.00 +135 +37.94 +6 +2.06 +2002 +70 +13.71 +70 +13.71 +- +- +Total +693 +192.73 +668 +186.36 +25 +6.37 +==== +====== +==== +====== +=== +====== +Summary of Productive Wells +The table below shows the number of the Company's productive gross and net wells at December 31, 2002. +Productive Wells +Gas +Oil +Location +Gross +Net +Gross +Net +Colorado +458 +265.70 +- +- +Michigan +197 +109.23 +7 +2.66 +North Dakota +- +- +5 +1.83 +Ohio +11 +3.42 +- +- +Pennsylvania +531 +165.76 +- +- +Tennessee +1 +0.71 +36 +13.62 +West Virginia +919 +518.27 +4 +1.72 +Total +2,117 +1,063.09 +52 +19.83 +====== +======= +==== +====== +Reserves +All of the Company's oil and natural gas reserves are located in the United States. The Company's approximate net proved reserves were estimated by Wright & Company, Inc. independent petroleum engineers ("Wright & Company"), to be 128,851,000 Mcf of natural gas and 2,073,000 Bbls of oil at December 31, 2002, 118,608,000 Mcf of natural gas and 2,126,000 Bbls of oil at December 31, 2001 and 118,640,000 Mcf of natural gas and 2,166,000 Bbls of oil at December 31, 2000. +The Company's approximate net proved developed reserves were estimated, by Wright & Company to be 94,847,000 Mcf of natural gas and 1,849,000 Bbls of oil at December 31, 2002, 88,477,000 Mcf of natural gas and 1,801,000 Bbls of oil at December 31, 2001 and 92,131,000 Mcf of natural gas and 1,527,000 Bbls of oil at December 31, 2000. +-7- +The Company's reserves by region are as follows as of December 31, 2002: +Oil +Mbbl) +Gas +(Mmcf) +Natural Gas +Equivalent +(Mmcfe) +% +Proved Developed Reserves +Appalachian Basin +46 +45,216 +45,492 +42.94% +Michigan Basin +48 +26,671 +26,959 +25.45% +Rocky Mountain Region +1,755 +22,960 +33,490 +31.61 % +Total Proved Developed Reserves +1,849 +94,847 +105,941 +100.00% +Proved Undeveloped Reserves +Appalachian Basin +0 +0 +0 +0.00% +Michigan Basin +0 +1,488 +1,488 +4.21% +Rocky Mountain Region +224 +32,516 +33,860 +95.79 % +Total Proved Undeveloped +224 +34,004 +35,348 +100.00% +Total Proved Reserves +Appalachian Basin +46 +45,216 +45,492 +32.20% +Michigan Basin +48 +28,159 +28,447 +20.13% +Rocky Mountain Region +1,979 +55,476 +67,350 +47.67 % +Total Proved Reserves +2,073 +128,851 +141,289 +100.00% +No major discovery or other favorable or adverse event that would cause a significant change in estimated reserves is believed by the Company to have occurred since December 31, 2002. Reserves cannot be measured exactly, as reserve estimates involve subjective judgment. The estimates must be reviewed periodically and adjusted to reflect additional information gained from reservoir performance, new geological and geophysical data and economic changes. +The standardized measure of discounted future estimated net cash flows attributable to the Company's proved oil and gas reserves, giving effect to future estimated income tax expenses, was estimated by Wright & Company to be $98.5 million as of December 31, 2002, $46.4 million as of December 31, 2001 and $104.6 million as of December 31, 2000. These amounts are based on year-end prices, adjusted for hedging contracts at the respective dates. The values expressed are estimates only, and may not reflect realizable values or fair market values of the natural gas and oil ultimately extracted and recovered. The standardized measure of discounted future net cash flows may not accurately reflect proceeds of production to be received in the future from the sale of natural gas and oil currently owned and does not necessarily reflect the actual costs that would be incurred to acquire equivalent natural gas and oil reserves. +-8- +Net Proved Natural Gas and Oil Reserves +The proved reserves of natural gas and oil of the Company as estimated by Wright & Company at December 31, 2002 are set forth below. These reserves have been prepared in compliance with the rules of the Securities and Exchange Commission (the "SEC") based on year-end prices. An analysis of the change in estimated quantities of natural gas and oil reserves from January 1, 2002 to December 31, 2002, all of which are located within the United States, is shown below: +Natural Gas (Mcf) +Oil (Bbls) +Proved developed and undeveloped reserves: +Beginning of year +118,608,000 +2,126,000 +Revisions of previous estimates +1,469,000 +124,000 +Beginning of year as revised +120,077,000 +2,250,000 +New discoveries and extensions +Rocky Mountain region +19,607,000 +130,000 +Dispositions to partnerships +(4,792,000) +(80,000) +Acquisitions +Michigan +4,000 +- +Rocky Mountain region +75,000 +- +Appalachian basin +342,000 +- +Production +(6,462,000 ) +(227,000 ) +End of year +128,851,000 +2,073,000 +========== +========== +Proved developed reserves: +Beginning of year +88,477,000 +1,801,000 +========== +========== +End of year +94,847,000 +1,849,000 +========== +========== +Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Natural Gas and Oil Reserves +Summarized in the following table is information for the Company with respect to the standardized measure of discounted future net cash flows relating to proved natural gas and oil reserves. Future cash inflows are computed by applying year-end prices, adjusted for any hedging contracts, of natural gas and oil relating to the Company's proved reserves to year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs, assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the statutory rate in effect at December 31, 2002 to the future pretax net cash flows, less the tax basis of the properties, and gives effect to permanent differences, tax credits and allowances related to the properties. +As of +December 31, 2002 +Future estimated revenues +$ 548,949,000 +Future estimated production costs +(143,878,000) +Future estimated development costs +(50,971,000) +Future estimated income tax expense +(105,876,000 ) +Future net cash flows +248,224,000 +10% annual discount for estimated timing of cash flows +(149,755,000 ) +Standardized measure of discounted +future estimated net cash flows +$ 98,469,000 +========= +-9- +The following table summarizes the principal sources of change in the standardized measure of discounted future estimated net cash flows from January 1, 2002 through December 31, 2002: +Sales of oil and natural gas production, net of production costs +$(16,449,000) +Net changes in prices and production costs +143,574,000 +Extensions, discoveries and improved recovery, less related costs +39,347,000 +Dispositions to partnerships +(6,940,000) +Acquisitions +1,167,000 +Development costs incurred during the period +16,429,000 +Revisions of previous quantity estimates +3,318,000 +Changes in estimated income taxes +(55,516,000) +Accretion in discount +(72,900,000 ) +$52,030,000 +========= +It is necessary to emphasize that the data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves, as the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision, and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods and the limitations inherent therein. +Substantially all of the Company's natural gas and oil reserves have been mortgaged or pledged as security for the Company's credit agreement. See Note 3 of Notes to Consolidated Financial Statements. +Oil and Natural Gas Leases +The following table sets forth, as of December 31, 2002, the acres of developed and undeveloped oil and natural gas acreage leased and available to the Company, listed alphabetically by state. +Developed +Acreage +Undeveloped +Acreage +Colorado +21,200 +62,700 +Michigan +23,900 +3,500 +North Dakota +1,700 +6,600 +Ohio +400 +- +Pennsylvania +9,000 +350 +Tennessee +5,400 +- +West Virginia +48,600 +600 +Total +110,200 +73,750 +======== +======== +Title to Properties +The Company believes that it holds good and indefeasible title to its properties, in accordance with standards generally accepted in the natural gas industry, subject to such exceptions stated in the opinion of counsel employed in the various areas in which the Company conducts its exploration activities, which exceptions, in the Company's judgment, do not detract substantially from the use of such property. As is customary in the natural gas industry, only a perfunctory title examination is conducted at the time the properties believed to be suitable for drilling operations are acquired by the Company. Prior to the commencement of drilling operations, an extensive title examination is conducted and curative work is performed with respect to defects which the Company deems to be significant. A title examination has been performed with respect to substantially all of the Company's producing properties. No single property owned by the Company represents a material portion of the Company's holdings. +-10- +The properties owned by the Company are subject to royalty, overriding royalty and other outstanding interests customary in the industry. The properties are also subject to burdens such as liens incident to operating agreements, current taxes, development obligations under natural gas and oil leases, farm-out arrangements and other encumbrances, easements and restrictions. The Company does not believe that any of these burdens will materially interfere with the use of the properties. +Natural Gas Sales +Natural gas is sold by the Company under contracts with terms ranging from one month to three years. Virtually all of the Company's contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. As a result, the Company's revenues from the sale of natural gas will suffer if market prices decline and benefit if they increase. The Company believes that the pricing provisions of its natural gas contracts are customary in the industry. +The Company sells its natural gas to industrial end-users and utilities. Two customers, Cinnabar Energy Services and Duke Energy accounted for 21.1% and 11.0%, respectively of the Company's revenues from oil and gas sales (10.8% and 5.6% of total revenues) in 2002. One customer, Cinnabar Energy Services, accounted for 25.2% and 17.7% of the Company's revenues from oil and gas sales (13.1% and 11.3% of total revenues) in 2001 and 2000, respectively. No other single purchaser of the Company's natural gas accounted for 10% or more of the Company's total revenues during 2002, 2001 or 2000. +At December 31, 2002, natural gas produced by the Company sold at prices per Mcf ranging from $0.90 to $5.93, depending upon well location, the date of the sales contract and other factors. The weighted net average price of natural gas sold by the Company during 2002 was $2.68 per Mcf. +In general, the Company, together with its marketing subsidiary, RNG, has been and expects to continue to be able to produce and sell natural gas from its wells without significant curtailment by providing natural gas to purchasers at competitive prices. Open access transportation on the country's interstate pipeline system has greatly increased the range of potential markets. Whenever feasible the Company allows for multiple market possibilities from each of its gathering systems, while seeking the best available market for its natural gas at any point in time. +Oil Sales +The Company's acquisition in December 1999 of 53 wells and in April 2000 of 108 wells in the Wattenberg field in Colorado and ongoing development activities in the Rocky Mountains added to oil production and reserves. At the end of 2002 oil was about 9% of the Company's total equivalent reserves. +The Company is currently able to sell all the oil that it can produce under existing sales contracts with petroleum refiners and marketers. The Company does not refine any of its oil production. The Company's crude oil production is sold to purchasers at or near the Company's wells under short-term purchase contracts at prices and in accordance with arrangements that are customary in the oil industry. One purchaser, Teppco Crude Oil, L.P. accounted for 11.9% of the Company's revenues from oil and gas sales (5.6% of total revenues) in 2002. No customer accounted for more than 10% of the Company's revenues from oil and gas sales in 2001 or 2000. At December 31, 2002, oil produced by the Company sold at prices ranging from $23.93 to $28.64 per barrel, depending upon the location and quality of oil. In 2002, the weighted net average price per barrel of oil sold by the Company was $24.41. +-11- +Oil production is subject to many of the same operating hazards and environmental concerns as natural gas production, but is also subject to the risk of oil spills. Federal regulations require certain owners or operators of facilities that store or otherwise handle oil, such as the Company, to procure and implement spill prevention, control, counter-measures and response plans relating to the possible discharge of oil into surface waters. The Oil Pollution Act of 1990 ("OPA") subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from oil spills. Noncompliance with OPA may result in varying civil and criminal penalties and liabilities. Operations of the Company are also subject to the Federal Clean Water Act and analogous state laws relating to the control of water pollution, which laws provide varying civil and criminal penalties and liabilities for release of petroleum or its derivatives into surface waters or into the ground. +Natural Gas Marketing +The Company's natural gas marketing activities involve the aggregation and reselling of natural gas produced by the Company and others. The Company believes that in a deregulated market, successful natural gas marketing is essential to profitable operations. A variety of factors affect the market for natural gas, including the availability of other domestic production, natural gas imports, the availability and price of alternative fuels, the proximity and capacity of natural gas pipelines, general fluctuations in the supply and demand for natural gas and the effects of state and federal regulations on natural gas production and sales. The natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual customers. +RNG, a wholly owned subsidiary, is a natural gas marketing company that specializes in the acquisition, aggregation and marketing of natural gas production in the Company's operating areas. RNG markets natural gas produced by the Company and also purchases natural gas from other producers and resells to utilities, end users or other marketers. The employees of RNG have extensive knowledge of natural gas markets in the Company's areas of operations. Such knowledge assists the Company in maximizing its prices as it markets natural gas from Company-operated wells. The gas is marketed to natural gas utilities, pipelines and industrial and commercial customers, either directly through the Company's gathering system, or utilizing transportation services provided by regulated interstate pipeline companies. +Hedging Activities +The Company utilizes commodity-based derivative instruments as hedges to manage a portion of its exposure to price volatility stemming from its natural gas sales and marketing activities. These instruments consist of NYMEX-traded natural gas futures and option contracts for Appalachian and Michigan production, and CIG (Colorado Interstate Gas Index)-based contracts for Colorado production. The contracts hedge committed and anticipated natural gas purchases and sales, generally forecasted to occur within the next twelve-month period. Company policy prohibits the use of natural gas futures or options for speculative purposes and permits utilization of hedges only if there is an underlying physical position. +The Company has extensive experience with the use of financial hedges to reduce the risk and impact of natural gas price changes. These hedges are used by RNG to coordinate fixed and variable priced purchases and sales, and by the Company to "lock in" fixed prices from time to time for the Company's share of production, and to establish "floors" and "ceilings" or "collars" on the possible range of the price realized for the sale of natural gas and oil. In order for future contracts to serve as effective hedges, there must be sufficient correlation to the underlying hedged transaction. While hedging can help provide price protection if spot prices drop, hedges can also limit upside potential. +For unhedged natural gas sales not subject to fixed price contracts, the Company is subject to price fluctuations for natural gas sold in the spot market. The Company continues to evaluate the potential for reducing these risks by entering into hedge transactions. In addition, the Company may also close out any portion of hedges that may exist from time to time which may result in a gain or loss on that hedge transaction. There are no hedge contracts outstanding as of December 31, 2002 related to oil production. +-12- +Financing of Drilling Activities +The Company conducts development drilling activities for its own account and for other investors. In 1984, the Company began sponsoring private drilling limited partnerships, and, in 1989, the Company began to register the partnership interests offered under public drilling programs with the SEC. The Company's public partnerships had $56.9 million in subscriptions in 2002, $57.1 million in subscriptions in 2001 and $55.6 million in 2000. The Company generally invests, as its equity contribution to each drilling partnership, an additional sum approximating 20% of the aggregate subscriptions received for that particular drilling partnership. As a result, the Company is subject to substantial cash commitments at the closing of each drilling partnership. The funds received from these programs are restricted to use in future drilling operations. While funds were received by the Company pursuant to drilling contracts in the years indicated, the Company recognizes revenues from drilling operations on the percentage of completion method as the wells are drilled, rather than when funds are received. Most of the Company's drilling and development funds now are received from partnerships in which the Company serves as managing general partner. However, because wells produce for a number of years, the Company continues to serve as operator for a number of unaffiliated parties. In addition to the partnership structure, the Company also utilizes joint venture arrangements for financing drilling activities. +The financing process begins when the Company enters into a development agreement with an investor partner, pursuant to which the Company agrees to assign its rights in the property to be drilled to the partnership or other entity. The partnership or other entity thereby becomes owner of a working interest in the property. +The Company's development contracts with its investor partners have historically taken many different forms. Generally the agreements can be classified as on a "footage-based" rate, whereby the Company receives drilling and completion payments based on the depth of the well; "cost-plus," in which the Company is reimbursed for its actual cost of drilling plus some additional amount for overhead and profit; or "turnkey," in which a specified amount is paid for drilling and another amount for completion. As part of the compensation for its services, the Company also has received some interest in the production from the well in the form of an overriding royalty interest, working interest or other proportionate share of revenue or profits. The Company's development contracts may provide for a combination of several of the foregoing payment options. Basic drilling and completion operations are performed on a footage-based rate, with leases and gathering pipelines being contributed at Company cost. The Company may also purchase a working interest in the subject properties. +The level of the Company's drilling and development activity is dependent upon the amount of subscriptions in its public drilling partnerships and investments from other partnerships or other joint venture partners. The use of partnerships and similar financing structures enables the Company to diversify its holdings, thereby reducing the risks of its development investments. Additionally, the Company benefits through such arrangements by its receipt of fees for its management services and/or through an increased share in the revenues produced by the developed properties. The Company believes that investments in drilling activities, whether through Company-sponsored partnerships or other sources, are influenced in part by the favorable treatment that such investments enjoy under the federal income tax laws. No assurance can be given that the Company will continue to have access to funds generated through these financing vehicles. +Governmental Regulation +The Company's business and the natural gas industry in general are heavily regulated. The availability of a ready market for natural gas production depends on several factors beyond the Company's control. These factors include regulation of natural gas production, federal and state regulations governing environmental quality and pollution control, the amount of natural gas available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. State and federal regulations generally are intended to prevent waste of natural gas, protect rights to produce natural gas between owners in a common reservoir and control contamination of the environment. Pipelines are subject to the jurisdiction of various federal, state and local agencies. The Company takes the steps necessary to comply with applicable regulations both on its own behalf and as part of the services it provides to its investor partnerships. The Company believes that it is in substantial compliance with such statutes, rules, regulations and governmental orders, although there can be no assurance that this is or will remain the case. The following discussion of the regulation of the United States natural gas industry is not intended to constitute a complete discussion of the various statutes, rules, regulations and environmental orders to which the Company's operations may be subject. +-13- +Regulation of Oil and Natural Gas Exploration and Production +The Company's oil and natural gas operations are subject to various types of regulation at the federal, state and local levels. Prior to commencing drilling activities for a well, the Company must procure permits and/or approvals for the various stages of the drilling process from the applicable state and local agencies in the state in which the area to be drilled is located. Such permits and approvals include those for the drilling of wells, and such regulation includes maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties on which wells are drilled, the plugging and abandoning of wells and the disposal of fluids used in connection with operations. The Company's operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units and the density of wells which may be drilled and the unitization or pooling of natural gas properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely primarily or exclusively on voluntary pooling of lands and leases. In areas where pooling is voluntary, it may be more difficult to form units, and therefore, more difficult to develop a project if the operator owns less than 100% of the leasehold. In addition, state conservation laws may establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations may limit the amount of oil and natural gas the Company can produce from its wells and may limit the number of wells or the locations at which the Company can drill. The regulatory burden on the oil and natural gas industry increases the Company's costs of doing business and, consequently, affects its profitability. In as much as such laws and regulations are frequently expanded, amended and reinterpreted, the Company is unable to predict the future cost or impact of complying with such regulations. +Regulation of Sales and Transportation of Natural Gas +Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 (the "NGPA") and the regulations promulgated thereunder by the Federal Energy Regulatory Commission(FERC). Maximum selling prices of certain categories of natural gas sold in "first sales," whether sold in interstate or intrastate commerce, were regulated pursuant to the NGPA. The Natural Gas Wellhead Decontrol Act (the "Decontrol Act") removed, as of January 1, 1993, all remaining federal price controls from natural gas sold in "first sales" on or after that date. FERC's jurisdiction over natural gas transportation was unaffected by the Decontrol Act. While sales by producers of natural gas and all sales of crude oil, condensate and natural gas liquids can currently be made at market prices, Congress could reenact price controls in the future. +The Company's sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive regulation. In recent years, FERC has undertaken various initiatives to increase competition within the natural gas industry. As a result of initiatives like FERC Order No.636, issued in April 1992, the interstate natural gas transportation and marketing system has been substantially restructured to remove various barriers and practices that historically limited non-pipeline natural gas sellers, including producers, from effectively competing with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. The most significant provisions of Order No.636 require that interstate pipelines provide transportation separate or "unbundled" from their sales service, and require that pipelines provide firm and interruptible transportation service on an open access basis that is equal for all natural gas suppliers. In many instances, the result of Order No.636 and related initiatives have been to substantially reduce or eliminate the interstate pipelines' traditional role as wholesalers of natural gas in favor of providing only storage and transportation services. Another effect of regulatory restructuring is the greater transportation access available on interstate pipelines. In some cases, producers and marketers have benefited from this availability. However, competition among suppliers has greatly increased and traditional long-term producer-pipeline contracts are rare. Furthermore, gathering facilities of interstate pipelines are no longer regulated by FERC, thus allowing gatherers to charge higher gathering rates. +Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC, state commissions 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 FERC and Congress will continue. The Company cannot determine to what extent future operations and earnings of the Company will be affected by new legislation, new regulations, or changes in existing regulation, at federal, state or local levels. +-14- +Environmental Regulations +The Company's operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stricter environmental legislation and regulations could continue. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the natural gas industry in general, the business and prospects of the Company could be adversely affected. +The Company generates wastes that may be subject to the Federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes. The U.S. Environmental Protection Agency ("EPA") and various state agencies have limited the approved methods of disposal for certain hazardous and nonhazardous wastes. Furthermore, certain wastes generated by the Company's operations that are currently exempt from treatment as "hazardous wastes" may in the future be designated as "hazardous wastes," and therefore be subject to more rigorous and costly operating and disposal requirements. +The Company currently owns or leases numerous properties that for many years have been used for the exploration and production of oil and natural gas. Although the Company believes that it has utilized good operating and waste disposal practices, prior owners and operators of these properties may not have utilized similar practices, and hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by the Company or on or under locations where such wastes have been taken for disposal. These properties and the wastes disposed thereon may be subject to the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), RCRA and analogous state laws as well as state laws governing the management of oil and natural gas wastes. Under such laws, the Company 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) or to perform remedial plugging operations to prevent future contamination. +CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed of or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for release of 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, and 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. +The Company's operations may be subject to the Clean Air Act ("CAA") and comparable state and local requirements. Amendments to the CAA were adopted in 1990 and contain provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from the operations of the Company. The EPA and states have been developing regulations to implement these requirements. The Company may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues. +The Company's expenses relating to preserving the environment during 2002 were not significant in relation to operating costs and the Company expects no material change in 2003. Environmental regulations have had no materially adverse effect on the Company's operations to date, but no assurance can be given that environmental regulations will not, in the future, result in a curtailment of production or otherwise have a materially adverse effect on the Company's business, financial condition or results of operations. +As a matter of corporate policy and commitment, the Company attempts to minimize the adverse environmental impact of all its operations. During the 1990's, the Company was a nine-time recipient of the West Virginia Department of Environmental Protection's top award in recognition of the quality of the Company's environmental and reclamation work in its drilling activities. +-15- +Operating Hazards and Insurance +The Company's exploration and production operations include a variety of operating risks, including the risk of fire, explosions, blowouts, craterings, pipe failure, casing collapse, abnormally pressured formations, and environmental hazards such as gas leaks, ruptures and discharges of toxic gas, the occurrence of any of which could result in substantial losses to the Company due to injury and loss of life, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. The Company's pipeline, gathering and distribution operations are subject to the many hazards inherent in the natural gas industry. These hazards include damage to wells, pipelines and other related equipment, and surrounding properties caused by hurricanes, floods, fires and other acts of God, inadvertent damage from construction equipment, leakage of natural gas and other hydrocarbons, fires and explosions and other hazards that could also result in personal injury and loss of life, pollution and suspension of operations. +Any significant problems related to its facilities could adversely affect the Company's ability to conduct its operations. In accordance with customary industry practice, the Company maintains insurance against some, but not all, potential risks; however, there can be no assurance that such insurance will be adequate to cover any losses or exposure for liability. The occurrence of a significant event not fully insured against could materially adversely affect the Company's operations and financial condition. The Company cannot predict whether insurance will continue to be available at premium levels that justify its purchase or whether insurance will be available at all. +Competition +The Company believes that its exploration, drilling and production capabilities and the experience of its management and professional staff generally enable it to compete effectively. The Company encounters competition from numerous other oil and natural gas companies, drilling and income programs and partnerships in all areas of its operations, including drilling and marketing natural gas and obtaining desirable natural gas leases. Many of these competitors possess larger staffs and greater financial resources than the Company, which may enable them to identify and acquire desirable producing properties and drilling prospects more economically. The Company's ability to explore for oil and natural gas prospects and to acquire additional properties in the future depends upon its ability to conduct its operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. The Company competes with a number of other companies, which offer interests in drilling partnerships with a wide range of investment objectives and program structures. Competition for investment capital for both public and private drilling programs is intense. The Company also faces intense competition in the marketing of natural gas from competitors including other producers as well as marketing companies. Also, international developments and the possible improved economics of domestic natural gas exploration may influence other companies to increase their domestic oil and natural gas exploration. Furthermore, competition among companies for favorable prospects can be expected to continue, and it is anticipated that the cost of acquiring properties may increase in the future. Factors affecting competition in the natural gas industry include price, location, availability, quality and volume of natural gas. The Company believes that it can compete effectively in the oil and natural gas industry on each of the foregoing factors. Nevertheless, the Company's business, financial condition or results of operations could be materially adversely affected by competition. +Employees +As of December 31, 2002, the Company had 94 employees, including 16 in finance and data processing, 6 in administration, 15 in exploration and development, 52 in production and 5 in natural gas marketing. The Company's engineers, supervisors and well tenders are generally responsible for the day-to-day operation of wells and pipeline systems. In addition, the Company retains subcontractors to perform drilling, fracturing, logging, and pipeline construction functions at drilling sites. The Company's employees act as supervisors of the subcontractors. +The Company's employees are not covered by a collective bargaining agreement. The Company considers relations with its employees to be excellent. +-16- +Facilities +The Company owns and occupies three buildings in Bridgeport, West Virginia, two of which serve as the Company's headquarters and one which serves as a field operating site. The Company also owns a field operating building in Gilmer County, West Virginia. The Company leases field operating offices in Colorado, Michigan and Pennsylvania under operating leases. The Company believes that its current facilities are sufficient for its current and anticipated operations. +Item 3. Legal Proceedings +From time to time the Company is a party to various legal proceedings in the ordinary course of business. The Company is not currently a party to any litigation that it believes would materially affect the Company's business, financial condition or results of operations. +Item 4. Submission of Matters to a Vote of Security Holders +No matters were submitted to a vote of security holders during the fourth quarter of the fiscal year covered by this report. +PART II +Item 5. Market for the Company's Common Stock and Related Stockholders Matters +The common stock of the Company is traded in the Nasdaq National Market under the symbol PETD. The following table sets forth, for the periods indicated, the high and low bid quotations per share of the Company's common stock in the over-the-counter market, as reported by Nasdaq. These quotations represent inter-dealer prices without retail markups, markdowns, commissions or other adjustments and may not represent actual transactions. +High +Low +2002 +First Quarter +6.65 +5.70 +Second Quarter +6.66 +5.86 +Third Quarter +5.95 +4.60 +Fourth Quarter +5.70 +4.75 +2001 +First Quarter +7.94 +5.72 +Second Quarter +8.84 +5.94 +Third Quarter +6.47 +4.38 +Fourth Quarter +6.30 +4.72 +As of December 31, 2002, there were approximately 1,170 record holders of the Company's common stock. +The Company has not paid any dividends on its common stock and currently intends to retain earnings for use in its business. Therefore, it does not expect to declare cash dividends in the foreseeable future. Further, the Company's Credit Agreement restricts the payment of dividends. +-17- +Item 6. Selected Financial Data (1) +Year Ended December 31, +2002 +2001 +2000 +1999 +1998 +Revenues +Oil and gas well +drilling operations +$57,149,100 +$76,291,200 +$43,194,700 +$42,115,600 +$40,447,100 +Oil and gas sales +69,223,000 +92,095,300 +90,419,700 +46,988,100 +35,560,300 +Well operations income +6,116,200 +5,604,200 +5,061,600 +5,314,500 +4,581,000 +Other income +2,853,600 +3,132,400 +2,540,500 +2,392,400 +2,385,200 +Total +$135,341,900 +$177,123,100 +$141,216,500 +$96,810,600 +$82,973,600 +========== +========== +========== +========== +========== +Costs and Expenses (excluding interest and depreciation, deple-tion and amortization) +$108,816,600 +$144,468,600 +$118,813,300 +$82,496,500 +$71,094,900 +========== +========== +========== +========== +========== +Interest Expense +$ 1,339,800 +$ 993,400 +$1,186,000 +$ 182,400 +$ - +========== +========== +========== +========== +========== +Depreciation, depletion and +Amortization +$12,103,300 +$10,578,300 +$6,943,500 +$ 4,031,200 +$ 3,253,600 +========== +========== +========== +========== +========== +Net Income +$ 9,284,800 +$14,967,800 +$10,681,000 +$ 7,824,300 +$ 6,658,000 +========== +========== +========== +========== +========== +Basic earnings per common share +$.59 +$.92 +$.66 +$.50 +$.43 +==== +==== +==== +==== +==== +Diluted earnings per share +$.58 +$.90 +$.65 +$.48 +$.41 +==== +==== +==== +==== +==== +Average Common and Common Equivalent Shares Outstanding +During the Year +16,143,414 +16,639,634 +16,437,488 +16,286,852 +16,338,298 +========== +========== +========== +========== +========== +December 31, +2002 +2001 +2000 +1999 +1998 +Total Assets +$212,251,600 +$199,852,100 +$187,684,500 +$132,083,600 +$111,409,000 +========== +========== +========== +========== +========== +Working Capital +$ 1,770,500 +$ 3,419,600 +$ 780,700 +$ (2,503,900) +$ 1,633,400 +========== +========== +========== +========== +========== +Long-Term Debt, excluding current maturities +$ 25,000,000 +$ 28,000,000 +$ 17,350,000 +$ 9,300,000 +$ - +========== +========== +========== +========== +========== +Stockholders' Equity +$101,122,200 +$ 96,772,800 +$ 82,256,900 +$70,724,900 +$ 62,746,700 +========== +========== +========== +========== +========== +See Consolidated Financial Statements elsewhere herein. +-18- +Item 7. Management's Discussion and Analysis of Financial Condition and +Results of Operations +Safe Harbor Statement Under the Private Securities +Litigation Reform Act of 1995 +Statements, other than historical facts, contained in this Annual Report on Form 10-K, including statements of estimated oil and gas production and reserves, drilling plans, future cash flows, anticipated capital expenditures and Management's strategies, plans and objectives, are "forward looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Although the Company believes that its forward looking statements are based on reasonable assumptions, it cautions that such statements are subject to a wide range of risks and uncertainties incidental to the exploration for, acquisition, development and marketing of oil and gas, and it can give no assurance that its estimates and expectations will be realized. Important factors that could cause actual results to differ materially from the forward looking statements include, but are not limited to, changes in production volumes, worldwide demand, and commodity prices for petroleum natural resources; the timing and extent of the Company's success in discovering, acquiring, developing and producing oil and gas reserves; risks incident to the drilling and operation of oil and gas wells; future production and development costs; the effect of existing and future laws, governmental regulations and the political and economic climate of the United States; the effect of hedging activities; and conditions in the capital markets. Other risk factors are discussed elsewhere in this Form 10-K. +Results of Operations +Year Ended December 31, 2002 Compared with December 31, 2001 +Revenues. Total revenues for the year ended December 31, 2002 were $135.3 million compared to $177.1 million for the year ended December 31, 2001, a decrease of approximately $41.8 million or 23.6%. Such decrease was primarily a result of reduced drilling revenues, gas marketing activities and oil and gas sales. Drilling revenues for the year ended December 31, 2002 were $57.1 million compared to $76.3 million for the year ended December 31, 2001, a decrease of approximately $19.2 million or 25.2%. The decrease was a result of higher drilling activity carried over from the Company's public drilling programs at the end of 2000. The wells were drilled and completed during the first three quarters of 2001. The carryover resulted from a shortage of drilling rigs and field services during the second half of 2000 which delayed the drilling and completion of the wells which normally would have been drilled during the second half of 2000. Natural gas sales from the marketing activities of Riley Natural Gas (RNG), the Company's natural gas marketing subsidiary for the year ended December 31, 2002 was $46.4 million compared to $66.2 million for the year ended December 31, 2001, a decrease of approximately $19.8 million or 29.9%. Such decrease was due to natural gas sold at significantly lower average sales prices along with slightly lower volumes sold. Oil and gas sales from the Company's producing properties for the year ended December 31, 2002 were $22.9 million compared to $25.9 million for the year ended December 31, 2001, a decrease of approximately $3.0 million or 11.6%. Such decrease was due to lower average sales prices of natural gas offset in part by an increase in volumes produced and sold of natural gas and oil from the Company's producing properties. Financial results depend upon many factors, particularly the price of natural gas and our ability to market our production on economically attractive terms. Price volatility in the natural gas market has remained prevalent in the last few years. Natural gas prices declined dramatically at the end of the fourth quarter of 2001 and during the entire first quarter of 2002. However, in the second quarter of 2002, the Company saw a significant strengthening of natural gas prices in its Appalachian and Michigan producing areas. Natural gas prices in Colorado remained low for most of 2002. In the fourth quarter, Colorado prices began to increase, although they continue to trail prices in other areas by a greater than normal margin. The Company believes the low prices in the Rocky Mountain Region, including Colorado, result from increasing local supplies that exceed the local demand and pipeline capacity available to move gas from the region. In May of 2003, the Kern River Pipeline is scheduled to complete a capacity addition that will add about 900 million cubic feet of capacity for deliveries to Utah and southern California. This represents almost 30% of the current pipeline capacity from the region to the West Coast and other markets outside the region. The Company believes that the completion and start-up of the pipeline will eliminate or reduce the local supply surplus, leading to improved prices in the region compared to other producing areas. +-19- +If the pipeline is not completed on schedule, the price of natural gas in the Rocky Mountains is likely to continue to be discounted compared to other areas. If this occurs, the Company's oil and gas sales in 2003 will be lower than they might otherwise be, and the sales of the Company's drilling programs, which focus on Colorado development, could be adversely impacted. Beginning in the second quarter and continuing later in the year, the Company entered into some commodity price hedging contracts for production from May 2002 through October 2003 to protect ourselves against possible short-term price weaknesses. Well operations and pipeline income for the year ended December 31, 2002 was $6.1 million compared to $5.6 million for the year ended December 31, 2001, an increase of approximately $500,000 or 8.9%. Such increase was due to an increase in the number of wells and pipelines operated by the Company. Other income for the year ended December 31, 2002 was $2.9 million compared to $3.1 million for the year ended December 31, 2001, a decrease of approximately $200,000 or 6.5%. +Costs and expenses. Costs and expenses for the year ended December 31, 2002 were $122.3 million compared to $156.0 million for the year ended December 31, 2001, a decrease of approximately $33.7 million, or 21.6%. Oil and gas well drilling operations costs for the year ended December 31, 2002 were $49.2 million compared to $66.0 million for the year ended December 31, 2001, a decrease of approximately $16.8 million or 25.5%. Such decrease was due to the reduced drilling activity referred to above. The costs of gas marketing activities of RNG for the year ended December 31, 2002 were $46.2 million compared to $65.7 million for the year ended December 31, 2001, a decrease of $19.5 million or 29.7%. Such decrease was due to lower average prices of natural gas purchased for resale and slightly lower volumes purchased. Based on the nature of RNG's gas marketing activities, hedging did not have a significant impact on RNG's net margins from marketing activities during either period. Oil and gas production costs from the Company's producing properties for the year ended December 31, 2002 were $9.1 million compared to $8.6 million for the year ended December 31, 2001 an increase of approximately $500,000 or 5.8%. Such increase was due to the increased sales volumes from the Company's oil and gas producing properties and increased number of wells operated by the Company. General and administrative expenses for the year ended December 31, 2002 were $4.4 million compared to $4.1 million for the year ended December 31, 2001, an increase of approximately $300,000. Depreciation, depletion and amortization costs for the year ended December 31, 2002 were $12.1 million compared to $10.6 million for the year ended December 31, 2001, an increase of approximately $1.5 million or 14.2%. Such increase was due to the increased amount of production and investment in oil and gas properties owned by the Company. Interest costs for the year ended December 31, 2002 were $1.3 million compared to $1.0 million for the year ended December 31, 2001 an increase of approximately $300,000. Such increase was due to higher average debt balances offset in part by lower average interest rates. +Net income. Net income for the year ended December 31, 2002 was $9.3 million compared to $15.0 million for the year ended December 31, 2001, a decrease of approximately $5.7 million or 38.0%. +Year Ended December 31, 2001 Compared with December 31, 2000 +Revenues. Total revenues for the year ended December 31, 2001 were $177.1 million compared to $141.2 million for the year ended December 31, 2000, an increase of approximately $35.9 million, or 25.4%. Drilling revenues for the year ended December 31, 2001 were $76.3 million compared to $43.2 for the year ended December 31, 2000, an increase of approximately $33.1 million, or 76.6%. Such increase was due to an increase in drilling and completion activities, which was a direct result of an increase in the availability of drilling rigs which allowed us to reduce the drilling backlog from $43.8 million as of December 31, 2000 to $31.6 million as of December 31, 2001. Natural gas sales from the marketing activities of RNG for the year ended December 31, 2001 were $66.2 million compared to $71.4 million for the year ended December 31, 2000, a decrease of approximately $5.2 million or 7.3%. Such decrease was due to decreased volumes of natural gas sold. Oil and gas sales from the Company's producing properties for the year ended December 31, 2001 were $25.9 million compared to $19.0 million for the year ended December 31, 2000, an increase of approximately $6.9 million or 36.3%. Such increase was due to increased production of producing properties along with new wells drilled and higher average sales prices of natural gas offset in part by lower average oil sales prices from the Company's producing properties. Financial results depend upon many factors, particularly the price of natural gas and our ability to market our production on economically attractive terms. Price volatility in the natural gas market has remained prevalent in the last few years. From late 1998 through the first quarter of 1999, we experienced a decline in energy commodity prices. However, in the summer of 2000 and continuing into 2001, prices improved. For the months of April, 2000 through October, 2001, we had certain natural gas hedges in place that prevented us from realizing the full impact of this price environment. Despite this limitation, our realized natural gas sales price for the year ended December 31, 2001 was $3.53 per Mcf compared to $2.74 for the year ended December +-20- +31, 2000. In the final months of 2000 and the first quarter of 2001, the NYMEX futures market reported unprecedented natural gas contract prices. During the year ended December 31, 2001, the hedging activities resulted in oil and gas sales being $3.4 million lower than if the Company had not hedged. As of December 31, 2001, the Company had no hedges or option contracts in place for its oil and gas production. RNG in its normal course of business had natural gas hedges and option contracts as of December 31, 2001. However, based on its gas marketing activities, hedging and option contracts did not have a significant impact on RNG's net margins from gas marketing activities in 2001. Well operations and pipeline income for the year ended December 31, 2001 was $5.6 million compared to $5.1 million for the year ended December 31, 2000, an increase of approximately $500,000 or 9.8%. Such increase resulted from an increase in the number of wells operated by the Company. Other income for the year ended December 31, 2001 was $3.1 million compared to $2.5 million for the year ended December 31, 2000, an increase of approximately $600,000 or 24.0%. Such increase resulted from interest earned on higher average cash balances. +Costs and expenses. Costs and expenses for the year ended December 31, 2001 were $156.0 million compared to $126.9 million for the year ended December 31, 2000, an increase of approximately $29.1 million, or 22.9%. Oil and gas well drilling operations costs for the year ended December 31, 2001 were $66.0 million compared to $35.2 million for the year ended December 31, 2000, an increase of approximately $30.8 million or 87.5%. Such increase was due to the increased drilling activity referred to above. The costs of gas marketing activities of RNG for the year ended December 31, 2001 were $65.7 million compared to $71.6 million for the year ended December 31, 2000, a decrease of $4.9 million or 6.8%. Such decrease was due to lower volumes of natural gas purchased for resale. Based on the nature of RNG's gas marketing activities, hedging and option contracts did not have a significant impact on RNG's net margins from marketing activities during 2001. Oil and gas production costs from the Company's producing properties for the year ended December 31, 2001 were $8.6 million compared to $8.3 million for the year ended December 31, 2000 an increase of approximately $300,000 or 3.6%. General and administrative expenses for the year ended December 31, 2001 were $4.1 million compared to $3.6 million for the year ended December 31, 2000, an increase of approximately $500,000. Depreciation, depletion and amortization costs for the year ended December 31, 2001 were $10.6 million compared to $6.9 million for the year ended December 31, 2000, an increase of approximately $3.7 million or 53.6%. Such increase was due to the increased amount of production and investment in oil and gas properties owned by the Company. Interest costs for the year ended December 31, 2001 were $1.0 million compared to $1.2 million for the year ended December 31, 2000 a decrease of approximately $200,000. Such decrease was due to lower average debt balances along with lower average interest rates. +Net income. Net income for the year ended December 31, 2001 was $15.0 million compared to $10.7 million for the year ended December 31, 2000, an increase of approximately $4.3 million or 40.2%. +Liquidity and Capital Resources +The Company funds its operations through a combination of cash flow from operations, capital raised through drilling partnerships, and use of the Company's credit facility. Operational cash flow is generated by sales of natural gas from the Company's well interests, well drilling and operating activities for the Company's investor partners, natural gas gathering and transportation, and natural gas marketing. Cash payments from Company-sponsored partnerships are used to drill and complete wells for the partnerships, with operating cash flow accruing to the Company to the extent payments exceed drilling costs. The Company utilizes its revolving credit arrangement to meet the cash flow requirements of its operating and investment activities. +Natural gas and oil prices have been unusually volatile for the past 24 months, and the Company anticipates continued volatility in the future. Currently, the NYMEX futures reflect a market expectation of gas prices at Henry Hub close to or above record prices per million Btu's (mmbtu). These prices look strong for the remainder of the year with natural gas storage levels at five-year low levels. The Company believes this situation creates the possibility of both periods of low prices and continued high prices. +-21- +Earlier this year, our Colorado gas prices had been adversely effected by an increase in the negative "basis" between NYMEX and Colorado prices. Pipeline capacity from the area to major markets in California and the Midwest is not adequate to move the new supplies developed over the past several years by oil and gas companies when local demand is at low summer levels. The result has been lower prices and some limited curtailment of production during the summer months. This situation has corrected itself some this winter. Several major pipeline projects are underway and in planning stages that will improve capacity over the next several years. There remains a possibility of greater seasonal volatility in Colorado than some other producing areas, but we expect the situation to improve over the coming year. +Because of the uncertainty surrounding gas prices we used hedging instruments to manage some of the impact of fluctuations in prices. Through October of 2003 we have in place a series of asymmetric costless collars. Under the collar arrangements, if the applicable index rises above the ceiling price, we pay the counterparty, however if the index drops below the floor the counterparty pays us. These floor and ceiling prices were set at levels which allowed us to set floors on two units of production for each unit of production with a ceiling. The positions in effect as of December 31, 2002 on the Company's share of production are shown in the following table: +Floors +Ceilings +Monthly +Quantity +MMBtu +Contract +Price +Monthly +Quantity +MMBtu +Contract +Price +Month +NYMEX Based Hedges +Jan 2003 +114,000 +$3.70 +57,000 +$4.10 +Jan 2003 +114,000 +$3.80 +57,000 +$4.40 +Feb 2003 +114,000 +$3.50 +57,000 +$4.20 +Feb 2003 +114,000 +$3.60 +57,000 +$4.30 +Mar 2003 +114,000 +$3.50 +57,000 +$3.75 +Mar 2003 +114,000 +$3.45 +57,000 +$4.20 +Apr 2003 +114,000 +$3.50 +57,000 +$3.80 +May 2003 - Oct 2003 +114,000 +$3.40 +57,000 +$3.80 +Colorado Interstate Gas (CIG) Based Hedges +Jan 2003-Mar 2003 +20,000 +$2.75 +10,000 +$4.45 +Jan 2003-Mar 2003 +29,000 +$2.75 +6,500 +$3.28 +Apr 2003-Oct 2003 +32,000 +$2.50 +8,000 +$3.13 +The Company hedges prices for its partners' share of production as well as its own production. Actual wellhead prices will vary based on local contract conditions, gathering and other costs and factors. +Oil prices have strengthened from earlier in the year. While oil prices are influenced by supply and demand, global geopolitics may be the single most important determinant. Since the percentage of company production reflected by oil sales has increased to almost 18% for 2002, variations in oil prices will have a greater impact on the Company than in the past. +The Company plans to conduct most, if not all, of its 2003 drilling operations in Colorado. If the planned pipeline capacity increases do not occur, it could reduce the Company's results from its producing activities. It could also make the company's drilling programs less attractive to potential investors. However, the Rocky Mountain region is the only onshore area of the U.S. with increasing production. The Company believes the necessary pipelines will be constructed, so increasing Rocky Mountain gas can move to the markets where it will be needed. +-22- +The Company closed four public drilling partnerships during 2002. The total amount received during 2002 was $56.9 million compared to $57.1 million for 2001. The Company closed its fourth program of 2002 on December 31, 2002 in the amount of $29.1 million and will drill the wells during the first quarter 2003. The Company invests, as its equity contribution to each drilling partnership, an additional sum approximating 20% of the aggregate subscriptions received for that particular drilling partnership. As a result, the Company is subject to substantial cash commitments at the closing of each drilling partnership. The funds received from these programs are restricted to use in future drilling operations. No assurance can be made that the Company will continue to receive this level of funding from these or future programs. +Substantially all of the Company's drilling programs contain a repurchase provision where Investors may tender their partnership units for repurchase at any time beginning with the third anniversary of the first cash distribution. The provision provides that the Company is obligated to purchase an aggregate of 10% of the initial subscriptions per calendar year (at a minimum price of four times the most recent 12 months' cash distributions), only if such units are tendered, subject to the Company's financial ability to do so. The maximum annual 10% repurchase obligation, if tendered by the investors, is currently approximately $1,878,200. The Company has adequate liquidity to meet this obligation. +The Company has a credit facility with Bank One, NA and BNP Paribas of $100 million subject to adequate oil and natural gas reserves. The current borrowing base is $58.0 million, of which the Company has activated $40.0 million of the facility. As of December 31, 2002, the outstanding balance on the line of credit was $25.0 million of which $10 million was subject to an interest rate swap at a rate of 8.39%, $6.0 million subject to a 90-day LIBOR (London Interbank Market Rate) of 3.27% and the remaining $9.0 million was subject to prime rate of 4.25%. The line of credit is at prime, with LIBOR alternatives available at the discretion of the Company. No principal payments are required until the credit agreement expires on July 3, 2005. +The Company continues to pursue capital investment opportunities in producing natural gas properties as well as its plan to participate in its sponsored natural gas drilling partnerships, while pursuing opportunities for operating improvements and costs efficiencies. Management believes that the Company has adequate capital to meet its operating requirements. +A summary of Company's contractual obligations and due dates are as follows: +Payments due by period +Contractual Obligations +Total +Less than +1 year +1-3 +years +3-5 +years +More than +5 years +Long-Term Debt +$25,000,000 +- +$25,000,000 +- +- +Operating Leases +$1,547,600 +$979,300 +$518,100 +$50,200 +- +Other Liabilities +$4,137,200 +- +917,700 +120,000 +$3,099,500 +Total +$30,684,800 +$979,300 +$26,435,800 +$170,200 +$3,099,500 +========= +========= +========= +======= +======== +Critical Accounting Policies +Certain accounting policies are very important to the portrayal of Company's financial condition and results of operations and require management's most subjective or complex judgments. The policies are as follows: +Revenue Recognition +Oil and gas wells are drilled primarily on a contract basis. The Company follows the percentage-of-completion method of income recognition for drilling operations in progress. +Sales of natural gas are recognized when sold, oil revenues are recognized when produced into a stock tank. +Well operations income consists of operation charges for well upkeep, maintenance and operating lease income on tangible well equipment. +-23- +Valuation of Accounts Receivable +Management reviews accounts receivable to determine which are doubtful of collection. In making the determination of the appropriate allowance for doubtful accounts, management considers Company's history of write-offs, relationships and overall credit worthiness of its customers, and well production data for receivables related to well operations. +Impairment of Long-Lived Assets +Exploration and development costs are accounted for by the successful efforts method. +The Company assesses impairment of capitalized costs of proved oil and gas properties by comparing net capitalized costs to undiscounted future net cash flows on a field-by-field basis using expected prices. Prices utilized in each year's calculation for measurement purposes and expected costs are held constant throughout the estimated life of the properties. If net capitalized costs exceed undiscounted future net cash flow, the measurement of impairment is based on estimated fair value which would consider future discounted cash flows. +Unproved properties are assessed on a property-by-property basis and properties considered to be impaired are charged to expense when such impairment is deemed to have occurred. +Deferred Tax Asset Valuation Allowance +Deferred tax assets are recognized for deductible temporary differences, net operating loss carryforwards, and credit carryforwards if it is more likely than not that the tax benefits will be realized. To the extent a deferred tax asset cannot be recognized under the preceding criteria, a valuation allowance has been established. +The judgments used in applying the above policies are based on management's evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results may differ from those estimates. See additional discussions in this Management's Discussion and Analysis. +New Accounting Standards +In June 2001, the FASB issued SFAS 143, Accounting for Asset Retirement Obligations (SFAS No. 143). SFAS No. 143 requires the Company to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development and/or normal use of the assets. The Company also records a corresponding asset which is depreciated over the life of the asset. Subsequent to the initial measurement of the asset retirement obligation, the obligation will be adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. The Company is required to adopt SFAS No. 143 on January 1, 2003. At this time the Company does not believe that the adoption of this statement will have a material effect on its financial position, results or operation, cash flows or disclosures. +In December 2002, the FASB issued SFAS 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 123 to require prominent disclosures in both annual and interim financial statements. Certain of the disclosure modifications are required for fiscal years ending December 31, 2002 and are included in the notes to these financial statements. +-24- +Item 7A. Quantitative and Qualitative Disclosure About Market Risk . +Market-Sensitive Instruments and Risk Management +The Company's primary market risk exposures are interest rate risk and commodity price risk. These exposures are discussed in detail below: +Interest Rate Risk +The Company's exposure to market risk for changes in interest rates relates primarily to the Company's interest-bearing cash and cash equivalents and long-term debt. Interest-bearing cash and cash equivalents includes money market funds, certificates of deposit and checking and savings accounts with various banks. The amount of interest-bearing cash and cash equivalents as of December 31, 2002 is $59,241,500 with an average interest rate of 0.78%. As of December 31, 2002, the Company has long-term debt of $25,000,000 of which $10,000,000 is subject to an interest rate swap at a rate of 8.39%, $6,000,000 subject to a 90-day LIBOR rate of 3.27% and $9,000,000 was subject to a prime rate of 4.25%. +Commodity Price Risk +The Company utilizes commodity-based derivative instruments as hedges to manage a portion of its exposure to price risk from its natural gas sales and marketing activities. These instruments consist of NYMEX-traded natural gas futures contracts and option contracts for Appalachian and Michigan production and CIG-based contracts traded by Bank One for Colorado production. These hedging arrangements have the effect of locking in for specified periods (at predetermined prices or ranges of prices) the prices the Company will receive for the volume to which the hedge relates and, in the case of RNG, the cost of gas supplies purchased for marketing activities. As a result, while these hedging arrangements are structured to reduce the Company's exposure to changes in price associated with the hedged commodity, they also limit the benefit the Company might otherwise have received from price changes associated with the hedged commodity. The Company's policy prohibits the use of natural gas future and option contracts for speculative purposes. +As of December 31, 2002 RNG had entered into a series of natural gas future contracts stemming from its marketing activities. Open future contracts maturing in 2003 are for the sale of 3,210,000 mmbtu of natural gas with a weighted average price of $3.97 mmbtu resulting in a total contract amount of $12,728,100 and a fair market value of $(1,912,200) and for the purchase of 740,000 mmbtu of natural gas with a weighted average price of $4.15 mmbtu resulting in a total contract amount of $3,073,200 and a fair market value of $480,800. There were no open option contracts stemming from RNG's marketing activities as of December 31, 2002. As of December 31, 2001, RNG had entered into a series of natural gas future contracts and option contracts stemming from its marketing activities. Open future contracts matured in 2002 were for the sale of 1,680,000 mmbtu of natural gas with a weighted average price of $3.18 mmbtu resulting in a total contract amount of $5,343,500 and a fair market value of $479,300. Open option contracts matured in 2002 were for the sale of 20,000 mmbtu with a weighted average floor price of $2.85 mmbtu and a fair value of $9,000. +As of December 31, 2002, PDC had entered into a series of natural gas future contracts and option contracts stemming from its natural gas production. Open future contracts maturing in 2003 are for the sale of 280,000 mmbtu of natural gas with a weighted average price of $4.25 mmbtu resulting in a total contract amount of $1,190,000 and a fair market value of $(209,700). Open option contracts maturing in 2003 are for the sale of 2,155,600 mmbtu with a weighted average floor price of $3.15 mmbtu and a fair value of $105,600 and 794,800 mmbtu with a weighted average ceiling price of $3.80 mmbtu and a fair value of $(442,800). As of December 31, 2001, PDC had no natural gas future contracts or option contracts stemming from its natural gas production. +The average NYMEX closing price for natural gas for the years 2002, 2001 and 2000 was $3.22 mmbtu, $4.27 mmbtu, and $3.88 mmbtu. The average NYMEX closing price for oil for the years 2002, 2001 and 2000 was $26.98 bbl, $26.60 bbl and $30.95 bbl. Future near-term gas prices will be affected by various supply and demand factors such as weather, government and environmental regulation and new drilling activities within the industry. +-25- +Disclosure of Limitations +As the information above incorporates only those exposures that exist at December 31, 2002, it does not consider those exposures or positions which could arise after that date. As a result, the Company's ultimate realized gain or loss with respect to interest rate and commodity price fluctuations will depend on the exposures that arise during the period, the Company's hedging strategies at the time, and interest rates and commodity prices at the time. +PART III +Item 8. Financial Statements and Supplementary Data: +The response to this Item is set forth herein in a separate section of this Report, beginning on Page F-1. +Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. +None. +Item 10. Directors and Executive Officers of the Company +Directors and Executive Officers of the Company +The executive officers and directors of the Company, their principal occupations for the past five years and additional information are set forth below: +Name +Age +Positions and Offices Held +Held Current +Position Since +James N. Ryan +71 +Chairman, Chief Executive Officer +and Director +November 1983 +Steven R. Williams +51 +President and Director +March 1983 +Dale G. Rettinger +58 +Chief Financial Officer, Executive +Vice President, Treasurer and +Director +July 1980 +Roger J. Morgan +75 +Secretary +November 1969 +Vincent F. D'Annunzio +50 +Director +February 1989 +Jeffrey C. Swoveland +47 +Director +March 1991 +Donald B. Nestor +54 +Director +March 2000 +Kimberly Luff Wakim +44 +Director +January 2003 +James N. Ryan has served as President and Director of PDC from 1969 to 1983 and was elected Chairman and Chief Executive Officer in March 1983. +Steven R. Williams has served as President and Director of PDC since March 1983. Prior to joining PDC, Mr. Williams was employed by Exxon until 1979 and attended Stanford Graduate School of Business, graduating in 1981. He then worked with Texas Oil and Gas until July 1982, when he joined Exco Enterprises, an oil and gas investment company as manager of operations. +Dale G. Rettinger has served as Vice President and Treasurer of PDC since July 1980, and was appointed Chief Financial Officer in September 1997. Mr. Rettinger was elected Director in 1985. Previously Mr. Rettinger was a partner with Main Hurdman, Certified Public Accountants, having served in that capacity since 1976. +Roger J. Morgan has been a member of the law firm of Young, Morgan & Cann, Clarksburg, West Virginia since 1955. Mr. Morgan is not active in the day-to-day business of PDC, but his law firm provides legal services to PDC. +Vincent F. D'Annunzio has served as president of Beverage Distributors, Inc. located in Clarksburg, West Virginia since 1985. +-26- +Jeffrey C. Swoveland has served as Chief Financial Officer of Body Media since September, 2000. Prior thereto, Mr. Swoveland was Vice President-Finance and Treasurer of Equitable Resources Inc since 1994. +Donald B. Nestor, elected as a director in March, 2000, is a Certified Public Accountant and a Partner in the CPA firm of Toothman Rice, P.L.L.C. and is in charge of the firm's Buckhannon, West Virginia office. Mr. Nestor has served in that capacity since 1975. +Kimberly Luff Wakim, elected director in January 2003, an Attorney and Certified Public Accountant, is a Partner with the law firm Thorp, Reed & Armstrong LLP. Ms. Wakim joined Thorp Reed & Armstrong LLP in 1990. +The Company's By-Laws provide that the directors of the Company shall be divided into three classes and that, at each annual meeting of stockholders of the Company, successors to the class of directors whose term expires at the annual meeting will be elected for a three-year term. The classes are staggered so that the term of one class expires each year. Mr. Williams, Mr. Nestor and Ms. Wakim are members of the class whose term expires in 2003; Mr. Ryan and Mr. D'Annunzio are members of the class whose term expires in 2004; and Mr. Rettinger and Mr. Swoveland are members of the class whose term expires in 2005. There is no family relationship between any director or executive officer and any other director or executive officer of the Company. There are no arrangements or understandings between any director or officer and any other person pursuant to which such person was selected as an officer. +On January 24, 2003, the Company adopted a Code of Business Conduct and Ethics Policy meeting the specified standards applicable to the Chief Executive Officer and Chief Financial Officer. The policy also covers all the corporate officers. +The Audit Committee of the Board of Directors is comprised entirely of independent outside directors. Donald B. Nestor, CPA, a partner in the certified public accounting firm of Toothman Rice PLLC, chairs the committee. Mr. Nestor and the other audit committee members, qualify as audit committee financial experts and are independent of management. +Item 11. Executive Compensation +There is incorporated by reference herein in response to this Item the material under the heading "Election of Directors - Remuneration of Directors and Officers", "Election of Directors - Stock Options" and "Election of Directors - Interest of Management in Certain Transactions" in the Company's definitive proxy statement for its 2003 annual meeting of stockholders filed or to be filed with the Commission on or before April 30, 2003. +Item 12. Security Ownership of Certain Beneficial Owners, Management and Related Stockholder Matters +There is incorporated by reference herein in response to this Item, the material under the heading "Election of Directors", in the Company's definitive proxy statement for its 2003 annual meeting of stockholders filed or to be filed with the Commission on or before April 30, 2003. +-27- +The Company has the following common stock options outstanding under the stock option plans approved by the stockholders: +Equity Compensation Plan Information +December 31, 2002 +Plan Category +Number of securities to +be issued upon exercise +of outstanding options, +warrants and rights +(a) +Weighted-average +exercise price of +outstanding options, +warrants and rights +(b) +Number of securities +remaining available for +future issuance under +equity compensation +plans (excluding +securities reflected +in column (a)) +(c) +Equity compensation plans +approved by security holders +1,160,000 shares +$4.48 +- +Equity compensation plans not +approved by security holders +- +- +- +Total +1,160,000 shares +$4.48 +- +Item 13. Certain Relationships and Related Transactions +The response to this item is set forth herein in Note 8 in the Notes to Consolidated Financial Statements and under "Election of Directors - Interest of Management in Certain Transactions," in the Company's definitive proxy statement for its 2003 annual meeting of stockholders filed or to be filed with the Commission on or before April 30, 2003. +Item 14. Controls and Procedures +Under the supervision and with the participation of the Company's management, including the Company's Chief Executive Officer and Chief Financial Officer, the Company has evaluated the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Exchange Act Rule 13a-14(c)) within 90 days of the filing date of this annual report, and, based on their evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these disclosure controls and procedures are effective in all material respects, including those to ensure that information required to be disclosed in reports filed or submitted under the Securities Exchange Act is recorded, processed, summarized, and reported, within the time periods specified in the Commission's rules and forms, and is accumulated and communicated to management, including the Company's Chief Executive Officer and Chief Financial Officer, as appropriate to allow for timely disclosure. 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 their evaluation. +Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K +(a) (1) Financial Statements: +See Index to Financial Statements and Schedules on page F-1. +(2) Financial Statement Schedules: +See Index to Financial Statements and Schedules on page F-1. +Schedules and Financial Statements Omitted +All other financial statement schedules are omitted because they are not required, inapplicable, or the information is included in the Financial Statements or Notes thereto. +(3) Exhibits: +See Exhibits Index on page E-1. +-28- +CONFORMED COPY +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. +PETROLEUM DEVELOPMENT CORPORATION +By /s/ James N. Ryan +James N. Ryan, Chairman +March 7, 2003 +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/James N. Ryan +James N. Ryan +Chairman, Chief Executive +Officer and Director +March 7, 2003 +/s/ Steven R. Williams +Steven R. Williams +President and Director +March 7, 2003 +/s/ Dale G. Rettinger +Dale G. Rettinger +Chief Financial Officer +Executive Vice +President, Treasurer and +Director (principal financial +and accounting officer +March 7, 2003 +/s/ Vincent F. D'Annunzio +Vincent F. D'Annunzio +Director +March 7, 2003 +-29- +FORM 10-K CERTIFICATION +I, James N. Ryan, certify that: +1 I have reviewed this annual report on Form 10-K of Petroleum Development Corporation; +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 officer 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 we 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 function): +(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 officer and I have indicated in this annual report whether or not 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 7, 2003 +/s/ James N. Ryan +James N. Ryan +Chief Executive Officer +of Petroleum Development Corporation +FORM 10-K CERTIFICATION +I, Dale G. Rettinger, certify that: +1. I have reviewed this annual report on Form 10-K of Petroleum Development Corporation; +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 officer 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 we 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 function): +(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 officer and I have indicated in this annual report whether or not 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 7, 2003 +/s/ Dale G. Rettinger +Dale G. Rettinger +Chief Financial Officer +of Petroleum Development Corporation +Exhibits Index +Exhibit Name +Exhibit +Number +Articles of Incorporation +3.1 +Incorporated by reference to +Form S-2 filed September 25, 1997 +By Laws +3.2 +Incorporated by reference to +Form 8-K filed on January 24, 2003 +Credit Agreement +10.1 +Employment Agreement -Steven R. Williams +10.2 +Employment Agreement - Dale G. Rettinger +10.3 +Code of Business Conduct and Ethics +14 +Certification by Chief Executive Officer +99.1 +Certification by Chief Financial Officer +99.2 +E-1 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Index to Financial Statements and Financial Statement Schedules +1. +Financial Statements: +Independent Auditors' Report +F-2 +Consolidated Balance Sheets - December 31, 2002 and 2001 +F-3 & 4 +Consolidated Statements of Income - +Years Ended December 31, 2002, 2001 and 2000 +F-5 +Consolidated Statements of Stockholders' Equity - +Years Ended December 31, 2002, 2001 and 2000 +F-6 +Consolidated Statements of Cash Flows - +Years Ended December 31, 2002, 2001 and 2000 +F-7 +Notes to Consolidated Financial Statements +F-8 -24 +2. +Financial Statement Schedule: +Schedule II - Valuation and Qualifying Accounts and Reserves +F-25 +F-1 +Independent Auditors' Report +The Stockholders and Board of Directors +Petroleum Development Corporation: +We have audited the consolidated financial statements of Petroleum Development Corporation and subsidiaries as listed in the accompanying index. In connection with our audits of the consolidated financial statements, we also have audited the financial statement schedule as listed in the accompanying index. These consolidated financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits. +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, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Petroleum Development Corporation and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. +As discussed in note 13 to the consolidated financial statements, the Company changed its method of accounting for derivative instruments and hedging activities in 2001. +KPMG LLP +Pittsburgh, Pennsylvania +February 25, 2003 +F-2 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Consolidated Balance Sheets +December 31, 2002 and 2001 +2002 +2001 +Assets +Current assets: +Cash and cash equivalents +$ 48,263,000 +47,892,300 +Restricted cash +2,760,500 +283,300 +Notes and accounts receivable +15,336,500 +10,752,600 +Inventories +1,174,100 +1,117,900 +Prepaid expenses +4,125,300 +4,659,300 +Total current assets +71,659,400 +64,705,400 +Properties and equipment: +Oil and gas properties (successful +efforts accounting method) +183,614,200 +167,244,600 +Pipelines +7,015,000 +6,501,500 +Transportation and other equipment +3,174,200 +3,201,500 +Land and buildings +1,455,400 +1,402,400 +195,258,800 +178,350,000 +Less accumulated depreciation, depletion and amortization +57,143,700 +45,809,500 +138,115,100 +132,540,500 +Other assets +2,477,100 +2,606,200 +$212,251,600 +199,852,100 +========== +========== +(Continued) +F-3 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Consolidated Balance Sheets +December 31, 2002 and 2001 +2002 +2001 +Liabilities and Stockholders' Equity +Current liabilities: +Accounts payable +$ 17,425,500 +17,118,600 +Other accrued expenses +11,261,700 +7,924,200 +Advances for future drilling contracts +37,283,800 +31,592,200 +Funds held for future distribution +3,917,900 +4,650,800 +Total current liabilities +69,888,900 +61,285,800 +Long-term debt +25,000,000 +28,000,000 +Other liabilities +4,137,200 +4,082,700 +Deferred income taxes +12,103,300 +9,710,800 +Commitments and contingencies +Stockholders' equity: +Common stock, par value $.01 per share; authorized 50,000,000 shares; issued and outstanding 15,734,767 and 16,245,752 shares +157,300 +162,400 +Additional paid-in capital +29,316,800 +32,922,500 +Retained earnings +73,430,100 +64,145,300 +Accumulated other comprehensive loss, net of tax +(1,782,000 ) +(457,400 ) +Total stockholders' equity +101,122,200 +96,772,800 +$212,251,600 +199,852,100 +=========== +========== +See accompanying notes to consolidated financial statements. +F-4 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Consolidated Statements of Income +Years Ended December 31, 2002, 2001 and 2000 +2002 +2001 +2000 +Revenues: +Oil and gas well drilling operations +$57,149,100 +76,291,200 +43,194,700 +Gas sales from marketing activities +46,365,900 +66,207,400 +71,402,400 +Oil and gas sales +22,857,100 +25,887,900 +19,017,300 +Well operations and pipeline income +6,116,200 +5,604,200 +5,061,600 +Other income +2,853,600 +3,132,400 +2,540,500 +135,341,900 +177,123,100 +141,216,500 +Costs and expenses: +Cost of oil and gas well drilling operations +49,166,200 +65,999,900 +35,244,300 +Cost of gas marketing activities +46,184,300 +65,740,300 +71,648,500 +Oil and gas production costs +9,074,200 +8,582,700 +8,303,600 +General and administrative expenses +4,391,900 +4,145,700 +3,616,900 +Depreciation, depletion and amortization +12,103,300 +10,578,300 +6,943,500 +Interest +1,339,800 +993,400 +1,186,000 +122,259,700 +156,040,300 +126,942,800 +Income before income taxes +13,082,200 +21,082,800 +14,273,700 +Income taxes +3,797,400 +6,115,000 +3,592,700 +Net income +$ 9,284,800 +14,967,800 +10,681,000 +========= +========= +========= +Basic earnings per common share +$.59 +.92 +.66 +==== +==== +=== +Diluted earnings per commonand common equivalent share +$.58 +.90 +.65 +==== +==== +==== +See accompanying notes to consolidated financial statements. +F-5 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Consolidated Statements of Stockholders' Equity +Years Ended December 31, 2002, 2001 and 2000 +Common stock issued +Number +Of +Shares +Amount +Additional +Paid-in- +capital +Retained +E arnings +Accumulated +Other +Compre- +hensive +Income +Total +Balance, December 31, 1999 +15,737,795 +$157,400 +32,071,000 +38,496,500 +- +70,724,900 +Issuance of common stock: +Exercise of employee stock options +511,584 +5,100 +511,700 +- +- +516,800 +Purchase of properties +100,000 +1,000 +549,000 +- +- +550,000 +Amortization of stock award +- +- +5,500 +- +- +5,500 +Repurchase and cancellation of treasury stock +(105,335) +(1,100) +(420,100) +- +- +(421,200) +Income tax benefit from the exercise of stock options +- +- +199,900 +- +- +199,900 +Net income +- +- +- +10,681,000 +- +10,681,000 +Balance, December 31, 2000 +16,244,044 +$ 162,400 +32,917,000 +49,177,500 +- +82,256,900 +Issuance of common stock +1,708 +- +- +- +- +- +Amortization of stock award +- +- +5,500 +- +- +5,500 +Net income +14,967,800 +14,967,800 +Comprehensive income: +Cumulative effect of change in accounting principle - +January 1, 2001 (net of tax of $8,052,700) +- +- +- +- +(12,079,100) +- +Reclassification adjustment for settlement of contracts +Included in net income (net of tax of $3,046,900) +- +- +- +- +4,971,200 +- +Changes in fair value of outstanding hedging positions +(net of tax of $4,076,100) +- +- +- +- +6,650,500 +- +Other comprehensive loss +(457,400) +(457,400 ) +Comprehensive income +_________ +___________ +_________ +___________ +________ +14,510,400 +Balance, December 31, 2001 +16,245,752 +$ 162,400 +32,922,500 +64,145,300 +(457,400) +96,772,800 +Issuance of common stock: +Exercise of employee stock options +70,000 +700 +78,100 +- +- +78,800 +Amortization of stock award +- +5,500 +- +- +5,500 +Repurchase and cancellation of treasury stock +(580,985) +(5,800) +(3,689,300) +(3,695,100) +Net income +- +- +- +9,284,800 +- +9,284,800 +Comprehensive income: +Reclassification adjustment for settlement of contracts +Included in net income (net of tax of $9,100) +- +- +- +- +14,800 +- +Changes in fair value of outstanding hedging positions and interest rate swap (net of tax of +$820,900) +- +- +- +- +(1,339,400 ) +- +Other comprehensive loss +(1,324,600) +(1,324,600 ) +Comprehensive income +_________ +___________ +_________ +__________ +________ +7,960,200 +Balance, December 31, 2002 +15,734,767 +$ 157,300 +29,316,800 +73,430,100 +(1,782,000) +101,122,200 +======== +========= +======== +======== +======== +========= +See accompanying notes to consolidated financial statements. +F-6 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Consolidated Statements of Cash Flows +Years Ended December 31, 2002, 2001 and 2000 +2002 +2001 +2000 +Cash flows from operating activities: +Net income +$9,284,800 +14,967,800 +10,681,000 +Adjustment to net income to reconcile +to cash provided by operating activities: +Deferred income taxes +2,986,400 +4,002,300 +1,838,300 +Depreciation, depletion and amortization +12,103,300 +10,578,300 +6,943,500 +Gain from sale of assets +(25,800) +(132,400) +(199,200) +Expired and abandoned leases +1,129,400 +919,200 +672,700 +Amortization of stock award +5,500 +5,500 +5,500 +(Increase) decrease in notes and accounts receivable +(4,583,900) +12,895,400 +(13,384,800) +Increase in inventories +(56,200) +(20,000) +(520,300) +Decrease (increase) in prepaid expenses +369,200 +3,243,900 +(4,774,700) +Decrease (increase) in other assets +56,300 +336,700 +(375,700) +Increase (decrease) in accounts payable and accrued expenses +1,945,200 +(8,219,900) +15,359,700 +Increase (decrease) in advances for future drilling contracts +5,691,600 +(12,217,200) +18,672,000 +(Decrease) increase funds held for future distribution +(732,900 ) +2,210,700 +412,500 +Total adjustments +18,888,100 +13,602,500 +24,649,500 +Net cash provided by operating activities +28,172,900 +28,570,300 +35,330,500 +Cash flows from investing activities: +Capital expenditures +(19,777,000) +(42,661,100) +(27,932,100) +Proceeds from sale of leases +1,042,500 +4,732,200 +1,588,700 +Proceeds from sale of fixed assets +25,800 +12,200 +680,100 +(Increase) decrease in restricted cash +(2,477,200 ) +2,655,000 +(2,324,000 ) +Net cash used in investing activities +(21,185,900 ) +(35,261,700 ) +(27,987,300 ) +Cash flows from financing activities: +Proceeds from/(retirement of) debt, net +(3,000,000) +10,650,000 +8,050,000 +Proceeds from issuance of stock +78,800 +- +95,600 +Repurchase and cancellation of treasury stock +(3,695,100 ) +- +- +Net cash (used in) provided by financing activities +(6,616,300 ) +10,650,000 +8,145,600 +Net increase in cash and cash equivalents +370,700 +3,958,600 +15,488,800 +Cash and cash equivalents, beginning of year +47,892,300 +43,933,700 +28,444,900 +Cash and cash equivalents, end of year +$48,263,000 +47,892,300 +43,933,700 +========== +========= +=========== +See accompanying notes to consolidated financial statements. +F-7 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +Years Ended December 31, 2002, 2001 and 2000 +(1) Summary of Significant Accounting Policies +Principles of Consolidation +The accompanying consolidated financial statements include the accounts of Petroleum Development Corporation and its wholly owned subsidiaries. All material intercompany accounts and transactions have been eliminated in consolidation. The Company accounts for its investment in limited partnerships under the proportionate consolidation method. Under this method, the Company's financial statements include its prorata share of assets and liabilities and revenues and expenses, respectively, of the limited partnerships in which it participates. +The Company is involved in three business segments. The segments are drilling and development, natural gas sales and well operations. (See Note 19) +The Company grants credit to purchasers of oil and gas and the owners of managed properties, substantially all of whom are located in West Virginia, Tennessee, Pennsylvania, Ohio, Michigan, North Dakota and Colorado. +Cash Equivalents +For purposes of the statement of cash flows, the Company considers all highly liquid debt instruments with original maturities of three months or less to be cash equivalents. +Inventories +Inventories of well equipment, parts and supplies are valued at the lower of average cost or market. An inventory of natural gas is recorded when gas is purchased in excess of deliveries to customers and is recorded at the lower of cost or market. An inventory of oil located in stock tanks on well locations, is carried at market at the end of each period. +Oil and Gas Properties +Exploration and development costs are accounted for by the successful efforts method. +The Company assesses impairment of capitalized costs of proved oil and gas properties by comparing net capitalized costs to undiscounted future net cash flows on a field-by-field basis using expected prices. Prices utilized in each year's calculation for measurement purposes and expected costs are held constant throughout the estimated life of the properties. If net capitalized costs exceed undiscounted future net cash flow, the measurement of impairment is based on estimated fair value which would consider future discounted cash flows. +Property acquisition costs are capitalized when incurred. Geological and geophysical costs and delay rentals are expensed as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether the wells have discovered economically producible reserves. If reserves are not discovered, such costs are expensed as dry holes. Development costs, including equipment and intangible drilling costs related to both producing wells and developmental dry holes, are capitalized. +(Continued) +F-8 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +Unproved properties are assessed on a property-by-property basis and properties considered to be impaired are charged to expense when such impairment is deemed to have occurred. +Costs of proved properties, including leasehold acquisition, exploration and development costs and equipment, are depreciated or depleted by the unit-of-production method based on estimated proved developed oil and gas reserves. +Upon sale or retirement of complete units of depreciable or depletable property, the net cost thereof, less proceeds or salvage value, is credited or charged to income. Upon retirement of a partial unit of property, the cost thereof is charged to accumulated depreciation and depletion. +Based on the Company's experience, management believes site restoration, dismantlement and abandonment costs net of salvage to be immaterial in relation to operating costs. These costs are being expensed when incurred. +Transportation Equipment, Pipelines and Other Equipment +Transportation equipment, pipelines and other equipment are carried at cost. Depreciation is provided principally on the straight-line method over useful lives of 3 to 17 years. SFAS No. 144 provides a single accounting model for long-lived assets to be disposed of. The Company adopted SFAS No. 144 on January 1, 2002. The adoption of SFAS No. 144 did not affect the Company's financial statements. +In accordance with SFAS No. 144, long-lived assets, such as property, plant, and equipment, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset. +Prior to the adoption of SFAS No. 144, the Company accounted for long-lived assets in accordance with SFAS No. 121, Accounting for Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of. +Maintenance and repairs are charged to expense as incurred. Major renewals and betterments are capitalized. Upon the sale or other disposition of assets, the cost and related accumulated depreciation, depletion and amortization are removed from the accounts, the proceeds applied thereto and any resulting gain or loss is reflected in income. +Buildings +Buildings are carried at cost and depreciated on the straight-line method over estimated useful lives of 30 years. +Advances for Future Drilling Contracts +Represents funds received from Partnerships and other joint ventures for drilling activities which have not been completed and accordingly have not yet been recognized as income in accordance with the Company's income recognition policies. +Retirement Plans +The Company has a 401-K contributory retirement plan (401-K Plan) covering full-time employees. The Company provides a discretionary matching of employee contributions to the plan. +The Company also has a profit sharing plan covering full-time employees. The Company's contributions to this plan are discretionary. +(Continued) +F-9 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +The Company has a deferred compensation arrangement covering executive officers of the Company as a supplemental retirement benefit. +The Company has established split-dollar life insurance arrangements with certain executive officers. Under these arrangements, advances are made to these officers equal to the premiums due. The advances are collateralized by the cash surrender value of the policies. The Company records as other assets its share of the cash surrender value of the policies. +Revenue Recognition +Oil and gas wells are drilled primarily on a contract basis. The Company follows the percentage-of-completion method of income recognition for drilling operations in progress. +Sales of natural gas are recognized when sold, oil revenues are recognized when produced into a stock tank. +Well operations income consists of operation charges for well upkeep, maintenance and operating lease income on tangible well equipment. +Income Taxes +Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. +Derivative Financial Instruments +All derivatives are recognized on the consolidated balance sheet at their fair value. On the date the derivative contract is entered into, the Company designates the derivative as either a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability ("Cash flow" hedge), or a non-hedging derivative. The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk-management objective and strategy for undertaking various hedge transactions. This process includes linking all derivatives that are designated as cash-flow hedges to specific firm commitments or forecasted transactions. The Company also formally assesses, both at the hedge's inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. When it is determined that a derivative is not highly effective as a hedge or that it has ceased to be a highly effective hedge, the Company discontinues hedge accounting prospectively. No hedging activities were discontinued during 2002 or 2001. +Changes in fair value of a derivative that is highly effective and that is designated and qualifies as a cash-flow hedge are recorded in other comprehensive income, until earnings are affected by the variability in cash flows of the designated hedged item. Changes in the fair value of non-hedging derivatives are reported in current-period earnings. The Company discontinues hedge accounting prospectively when it is determined that the derivative is no longer effective in offsetting changes in the cash flows of the hedged item, the derivative expires or is sold, terminated, or exercised. Additionally, if the derivative is dedesignated as a hedging instrument, because it is unlikely that a forecasted transaction will occur, a hedged firm commitment no longer meets the definition of a firm commitment, or management determines that designation of the derivative as a hedging instrument is no longer appropriate, hedge accounting will discontinue. +(Continued) +F-10 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +For the year ended December 31, 2000, prior to adoption of Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Certain Hedging Activities" and SFAS No. 138, "Accounting for Certain Hedging Activities", gains and losses related to qualifying hedges of firm commitments or anticipated transactions through the use of natural gas futures and option contracts were deferred and recognized in income or as adjustments of carrying amounts when the underlying hedged transaction occurred. In order for futures contracts to qualify as a hedge, there must be sufficient correlation to the underlying hedged transaction. The change in the fair value of derivative instruments which do not qualify for hedging were recognized into income in 2000 +During 2000, the Company entered into an interest rate swap agreement which expires October 11, 2004 to reduce its exposure to market risks from changing interest rates. The interest rate differential to be paid or received was accrued and recognized as interest expense in the period incurred. +Stock Compensation +The Company has adopted SFAS No. 123, "Accounting for Stock-Based Compensation," which permits entities to recognize as expense over the vesting period the fair value of all stock-based awards on the date of grant. Alternatively, SFAS 123 allows entities to continue to measure compensation cost for stock-based awards using the intrinsic value based method of accounting prescribed by APB Opinion No. 25, "Accounting for Stock Issued to Employees," and to provide pro forma net income and pro forma earnings per share disclosures as if the fair value based method defined in SFAS 123 had been applied. The Company has elected to continue to apply the provisions of APB 25 and provide the pro forma disclosure provisions of SFAS 123. For stock options granted, the option price was not less than the market value of shares on the grant date, therefore, no compensation cost has been recognized. Had compensation cost been determined under the provisions of SFAS 123, the Company's net income and earnings per share would have been the following on a pro forma basis: +2002 +2001 +2000 +Net income, as reported +$9,284,800 +$14,967,800 +$10,681,000 +Deduct total stock-based employee compensation expense determined under fair-value-based method for all rewards, net of tax +- +(486,100 ) +(334,300 ) +Pro forma net income +$9,284,800 +$14,481,700 +$10,346,700 +======== +========== +========== +Pro forma basic earnings per share +$0.59 +$0.89 +$0.64 +==== +==== +==== +Pro forma diluted earnings per share +$0.58 +$0.87 +$0.63 +==== +==== +==== +Use of Estimates +Management of the Company has made a number of estimates and assumptions relating to the reporting of assets and liabilities and revenues and expenses and the disclosure of contingent assets and liabilities to prepare these financial statements in conformity with generally accepted accounting principles. Actual results could differ from those estimates. Estimates which are particularly significant to the consolidated financial statements include estimates of oil and gas reserves and future cash flows from oil and gas properties. +Fair Value of Financial Instruments +The carrying values of the Company's receivables, payables and debt obligations are estimated to be substantially the same as the fair values as of December 31, 2002, 2001 and 2000. +F-11 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +New Accounting Standards +In June 2001, the FASB issued SFAS 143, Accounting for Asset Retirement Obligations (SFAS No. 143). SFAS No. 143 requires the Company to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development and/or normal use of the assets. The Company also records a corresponding asset which is depreciated over the life of the asset. Subsequent to the initial measurement of the asset retirement obligation, the obligation will be adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. The Company is required to adopt SFAS No. 143 on January 1, 2003. At this time, the Company cannot reasonably estimate the effect of the adoption of this Statement on either its financial position, results of operations, or cash flows. +In December 2002, the FASB issued SFAS 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 123 to require prominent disclosures in both annual and interim financial statements. Certain of the disclosure modifications are required for fiscal years ending December 31, 2002 and are included in the notes to these financial statements. +(2) Notes and Accounts Receivable +Included in other assets are noncurrent accounts receivable as of December 31, 2002 and 2001, in the amounts of $445,600 and $173,600 net of an allowance for doubtful accounts of $445,600 and $174,600, respectively. +The allowance for doubtful current accounts receivable as of December 31, 2002 and 2001 was $49,400 and $349,900, respectively. +(3) Long-Term Debt +On July 3, 2002 the Company executed a $100 million credit facility with Bank One, NA and BNP Paribas. The agreement provides for borrowing up to $100 million subject to and secured by adequate levels of oil and gas reserves. The current total borrowing base is $58.0 million of which the Company has activated $40 million of the facility. The Company is required to pay a commitment fee of 1/4 percent on the unused portion of the activated credit facility. Interest accrues at prime, with LIBOR (London Interbank Market Rate) alternatives available at the discretion of the Company. No principal payments are required until the credit agreement expires on July 3, 2005. +As of December 31, 2002 and 2001 the outstanding balance was $25,000,000 and $28,000,000, respectively. Any amounts outstanding under the credit facility are secured by substantially all properties of the Company. The credit agreement requires, among other things, the existence of satisfactory levels of natural gas reserves, maintenance of certain working capital and tangible net worth ratios along with a restriction on the payment of dividends. As of December 31, 2002 and 2001 the Company was in compliance with all financial covenants in the credit agreement. +At December 31, 2002, $10,000,000 of the outstanding balance was subject to an interest rate swap at a rate of 8.39%, $6,000,000 was subject to a 90-day LIBOR rate of 3.27% and $9,000,000 was subject to a prime rate of 4.25%. +(Continued) +F-12 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +(4) Income Taxes +The Company's provision for income taxes consisted of the following: +2002 +2001 +2000 +Current: +Federal +$604,200 +1,639,300 +1,182,000 +State +206,800 +473,300 +572,400 +Total current income taxes +811,000 +2,112,600 +1,754,400 +Deferred: +Federal +2,461,200 +3,898,600 +1,415,600 +State +525,200 +103,800 +422,700 +Total deferred income taxes +2,986,400 +4,002,400 +1,838,300 +Total income taxes +$3,797,400 +6,115,000 +3,592,700 +======== +======== +======== +Income tax expense differed from the amounts computed by applying the U.S. federal income tax rate of 34 percent to pretax income as a result of the following: +2002 +2001 +2000 +Computed "expected" tax +$4,447,900 +7,168,200 +4,853,100 +State income tax +483,100 +380,900 +656,800 +Percentage depletion +(680,000) +(935,000) +(758,300) +Nonconventional source fuel credit +(491,500) +(1,184,700) +(1,067,500) +Effect of state rate change +- +556,500 +- +Other +37,900 +129,100 +(91,400 ) +$3,797,400 +6,115,000 +3,592,700 +======== +======== +======== +The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2002 and 2001 are presented below: +2002 +2001 +Deferred tax assets: +Allowance for doubtful accounts +$ 199,300 +199,300 +Drilling notes +84,500 +88,100 +Alternative minimum tax credit carryforwards (Section 29) +2,055,500 +1,715,800 +Future abandonment +505,900 +409,300 +Deferred compensation +2,000,400 +2,100,500 +Other +40,600 +48,900 +Total gross deferred tax assets +4,886,200 +4,561,900 +Less valuation allowance +- +- +Deferred tax assets +4,886,200 +4,561,900 +Less current deferred tax assets (included in prepaid expenses) +(1,351,200 ) +(1,133,400 ) +Net non-current deferred tax assets +3,535,000 +3,428,500 +Deferred tax liabilities: +Properties and equipment, principally due to differences in +Depreciation and amortization +(16,730,500 ) +(13,419,800 ) +Total gross deferred tax liabilities +(16,730,500 ) +(13,419,800 ) +Net deferred tax liability +(13,195,500) +(9,991,300) +========== +========= +Deferred income tax assets related to AOCI +1,092,200 +280,500 +Net deferred tax liability after AOCI +$(12,103,300) +(9,710,800) +========== +========= +(Continued) +F-13 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +At December 31, 2002, the Company has alternative minimum tax credit carryforwards (Section 29) of approximately $2,055,500 which are available to reduce future federal regular income taxes over an indefinite period. +Accumulated other comprehensive loss is net of tax of $1,092,200, $280,500 and $0 as of December 31, 2002, 2001 and 2000, respectively. The income tax benefit from the exercise of stock options recorded in additional paid-in capital was $0 in 2002 and 2001 and $199,900 in 2000. +(5) Common Stock +Options +Options amounting to 185,000 and 180,000 shares were granted during 2001 and 2000, respectively, to certain employees and directors under the Company's Stock Option Plans. These options were granted with an exercise price equal to market value as of the date of grant and vest over a six month period. The outstanding options expire from 2005 to 2011. +The estimated fair value of the options granted during 2001 and 2000 was $3.70 and $2.48 per option, respectively. The fair value was estimated using the Black-Scholes option pricing model with the following assumptions for the 2001 and 2000 grant, respectively: risk-free interest rate of 5.88% and 6.13%, expected dividend yield of 0%, expected volatility of 50.23% and 57.31% and expected life of 7 years. +Number +of Shares +Average +Exercise +Price +Range of +Exercise +Prices +Outstanding December 31, 1999 +1,388,984 +$2.87 +.94 - 6.13 +===== +========= +Granted +180,000 +$3.875 +3.875 - 3.875 +===== +========= +Exercised +(511,584) +$1.01 +.94 - 1.625 +===== +========= +Expired +(12,400 ) +$3.31 +1.50 - 3.75 +===== +========= +Outstanding December 31, 2000 +1,045,000 +$3.95 +1.125 - 6.125 +Granted +185,000 +$6.25 +6.25 - 6.25 +===== +========= +Outstanding December 31, 2001 +1,230,000 +$4.29 +1.125 - 6.25 +Exercised +(70,000 ) +$1.125 +1.125 - 1.125 +Outstanding December 31, 2002 +1,160,000 +$4.48 +1.125 - 6.25 +======= +===== +========= +As of December 31, 2002, there were 140,000 options outstanding and exercisable at the $1.125 exercise price which have a weighted average remaining contractual life of 2.9 years. Also as of December 31, 2002 there were 1,020,000 options outstanding and exercisable at a $3.75 to $6.25 exercise price range having a weighted average remaining contractual life of 5.9 years and weighted average exercise price of $4.95. +(Continued) +F-14 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +Stock Redemption Agreement +The Company has stock redemption agreements with three officers of the Company. The agreements require the Company to maintain life insurance on each executive in the amount of $1,000,000. The agreements provide that the Company shall utilize the proceeds from such insurance to purchase from such executives' estates or heirs, at their option, shares of the Company's stock. The purchase price for the outstanding common stock is to be based upon the average closing asked price for the Company's stock as quoted by NASDAQ during a specified period. The Company is not required to purchase any shares in excess of the amount provided for by such insurance. +(6) Employee Benefit Plans +The Company made 401-K Plan contributions of $288,000, $260,800 and $252,600 for 2002, 2001 and 2000, respectively. +The Company has a profit sharing plan (the Plan) covering full-time employees. The Company contributed $200,000, $200,000 and $1,000, to the plan in cash during 2002, 2001 and 2000, respectively. +During 2002, 2001 and 2000 the Company expensed and established a liability for $90,000 each year under a deferred compensation arrangement with the executive officers of the Company. +At December 31, 2002 and 2001, the Company has recorded as other assets $501,000 and $402,100, respectively related to the cash surrender value of the life insurance on certain executive officers. +(7) Earnings Per Share +Basic earnings per share is based on the weighted average number of common shares outstanding of 15,866,363 for 2002, 16,244,931 for 2001 and 16,157,532 for 2000. +Diluted earnings per share is based on the weighted average number of common and common equivalent shares outstanding of 16,143,414 for 2002, 16,639,634 for 2001 and 16,437,488 for 2000. Stock options are considered to be common stock equivalents and to the extent appropriate, have been added to the weighted average common shares outstanding. +(Continued) +F-15 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +(8) Transactions with Affiliates +As part of its duties as well operator, the Company received $60,620,222 in 2002, $71,802,700 in 2001 and $44,899,200 in 2000 representing proceeds from the sale of oil and gas and made distributions to investor groups according to their working interests in the related oil and gas properties. Funds held for future distribution on the consolidated balance sheet of $3,917,900 and $4,650,800 includes amounts owed to affiliated partnerships as of December 31, 2002 and 2001, respectively. +The Company provided oil and gas well drilling services to affiliated partnerships. Substantially all of the Company's oil and gas well drilling operations was for such partnerships. The Company also provided related services of operation of wells, reimbursement of syndication costs, management fees, tax return preparation and other services relating to the operation of the partnerships. The Company received $20,008,900 in 2002, $16,072,500 in 2001 and $15,713,300 in 2000 for those services. Amounts due from the partnerships as of December 31, 2002 and 2001 were $1,028,000 and $1,246,200, and are included in notes and accounts receivable. +During 2002, 2001 and 2000, the Company paid $51,800, $30,100 and $40,400, respectively to the Corporate Secretary's law firm for various legal services. +(9) Commitments and Contingencies +The nature of the independent oil and gas industry involves a dependence on outside investor drilling capital and involves a concentration of gas sales to a few customers. The Company sells natural gas to various public utilities and industrial customers. One customer, Cinnabar Energy Services, accounted for 10.8%, 13.1% and 11.3% of total revenues in 2002, 2001 and 2000, respectively. +The Company would be exposed to natural gas price fluctuations on underlying purchase and sale contracts should the counterparties to the Company's hedging instruments or the counterparties to the Company's gas marketing contracts not perform. Such nonperformance is not anticipated. There were no counterparty default losses in 2002, 2001 or 2000. +Substantially all of the Company's drilling programs contain a repurchase provision where Investors may tender their partnership units for repurchase at any time beginning with the third anniversary of the first cash distribution. The provision provides that the Company is obligated to purchase an aggregate of 10% of the initial subscriptions per calendar year (at a minimum price of four times the most recent 12 months' cash distributions), only if such units are tendered, subject to the Company's financial ability to do so. The maximum annual 10% repurchase obligation, if tendered by the investors, is currently approximately $1,878,200. The Company has adequate liquidity to meet this obligation. +The Company is not party to any legal action that would materially affect the Company's results of operations or financial condition. +(10) Lease Obligations +The Company has entered into certain operating leases on behalf of itself and its Partnerships principally for the leasing of natural gas compressors on its Michigan operating facilities. The future minimum lease payments under these non-cancellable operating leases as of December 31, 2002 are as follows: +Year +Lease Amount +2003 +$ 979,300 +2004 +397,800 +2005 +120,400 +2006 +50,200 +$1,547,700 +======== +(Continued) +F-16 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +The Company's share of this lease expense for operating leases for the years ended December 31, 2002, 2001 and 2000 was $660,700, $693,000 and $629,800, respectively. +(11) Supplemental Disclosure of Cash Flows +The Company paid $1,290,400, $1,173,100 and $875,800 for interest in 2002, 2001 and 2000, respectively. The Company paid income taxes in 2002, 2001 and 2000 in the amounts of $175,000, $2,830,000 and $2,256,800, respectively. +The Company exchanged common stock in the amount of $550,000 and paid cash in the amount of $5,100,000 for the purchase of oil and gas properties in Colorado during 2000. +(12) Acquisitions and Divestitures +On June 6, 2000, the Company purchased all of the working interest in 168 producing wells in Colorado for $5,650,000. The transaction was effective April 1, 2000. At the date of acquisition, the wells had net remaining reserves of 560,000 barrels of oil and 4.9 billion cubic feet of natural gas. The Company utilized its bank credit agreement to finance this purchase. +On December 31, 2000, the Company sold its Ohio gas gathering and sales systems. The result was a net gain of $109,600. +(13) Derivative Financial Instruments +The Company utilizes commodity based derivative instruments as hedges to manage a portion of its exposure to price volatility stemming from its integrated natural gas production and marketing activities. These instruments consist of natural gas futures and option contracts traded on the New York Mercantile Exchange for Appalachian and Michigan production and CIG (Colorado Interest Gas Index)-based hedges traded by Bank One for Colorado production. The futures and option contracts hedge committed and anticipated natural gas purchases and sales, generally forecasted to occur within a 12 month period. The Company does not hold or issue derivatives for trading or speculative purposes. In addition, interest rate swap agreements are used to reduce the potential impact of increases in interest rates on variable rate long-term debt. +Statement of Accounting Standards No. 133 and No. 138, Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133/138), was issued by the Financial Accounting Standards Board. SFAS No. 133/138 standardized the accounting for derivative instruments, including certain derivative instruments embedded in other contracts. The Company adopted the provisions of the SFAS 133/138 effective January 1, 2001. The natural gas futures and options and the interest rate swap are derivatives pursuant to SFAS 133/138. The Company's derivatives are treated as hedges of committed and/or anticipated transactions and had a total estimated fair value of $(1,782,000) (net of tax) on December 31, 2002 and a total estimated fair value of $(457,400) (net of tax) on December 31, 2001. +(Continued) +F-17 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +Natural gas futures and option contracts for the sale or purchase of natural gas are as follows: +December 31, 2002 +Amount +(mmbtu) +Fair Value +Fair Value +net of tax +Futures contracts +Marketing activities +3,950,000 +$(1,431,400) +$(887,400) +Production activities +280,000 +(209,700) +(130,000) +4,230,000 +$(1,641,100) +$(1,017,400) +========= +========= +========= +Option contracts +Marketing activities +- +- +- +Production activities +2,950,400 +$(337,200 ) +(209,100 ) +2,950,400 +$(337,200) +$(209,100) +========= +========= +========= +December 31, 2001 +Futures contracts +Marketing activities +1,680,000 +$479,300 +$297,200 +Production activities +- +- +- +1,680,000 +$479,300 +$297,200 +========= +========= +========= +Option contracts +Marketing activities +20,000 +$9,000 +$ 5,600 +Production activities +- +- +- +20,000 +$9,000 +$ 5,600 +========= +========= +========= +The Company is required to maintain margin deposits with brokers for outstanding futures contracts. As of December 31, 2002 and 2001, cash in the amount of $2,760,500 and $283,300 was on deposit. +Interest rate swap agreements are used to reduce the potential impact of increases in interest rates on variable rate long-term debt. At December 31, 2002 and 2001, the Company was a party to an interest rate swap agreement expiring on October 11, 2004. The agreement entitles the Company, on a quarterly basis, to a fixed-rate interest payment of 6.89% plus its current LIBOR rate margin (+1.50% At December 31, 2002) on a $10,000,000 notional amount related to its outstanding line of credit. +The fair value of the interest rate swap agreement was $(896,000), $(555,000) net of tax at December 31, 2002 and $(1,226,200), $(760,200) net of tax at December 31, 2001. Current market pricing models were used to estimate fair value. +By using derivative financial instruments to hedge exposures to changes in interest rates and commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates repayment risk. The Company minimizes the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties. +(Continued) +F-18 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +(14) Costs Incurred in Oil and Gas Property Acquisition, Exploration and +Development Activities +Costs incurred by the Company in oil and gas property acquisition, exploration and development are presented below: +Years Ended December 31, +2002 +2001 +2000 +Property acquisition cost: +Proved undeveloped properties +$ 1,892,700 +3,670,500 +3,397,500 +Producing properties +240,000 +75,700 +8,361,400 +Development costs +16,429,400 +35,411,900 +15,556,200 +$18,562,100 +39,158,100 +27,315,100 +========= +========= +========= +The proved reserves attributable to the development costs in the above table were 19,607,000 Mcf and 130,000 bbls for 2002, 23,896,000 Mcf and 715,000 bbls for 2001 and 29,060,000 Mcf and 800,000 bbls for 2000 (amounts unaudited). Of the above development costs incurred for the years ended December 31, 2002, 2001 and 2000 the amounts of $2,699,500, $7,026,900 and $2,379,300, respectively were incurred to develop proved undeveloped properties from the prior year end. +Property acquisition costs include costs incurred to purchase, lease or otherwise acquire a property. Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells and to provide facilities to extract, treat, gather and store oil and gas. +(15) Oil and Gas Capitalized Costs +Aggregate capitalized costs for the Company related to oil and gas exploration and production activities with applicable accumulated depreciation, depletion and amortization are presented below: +December 31, +2002 +2001 +Proved properties: +Tangible well equipment +$114,431,800 +100,805,800 +Intangible drilling costs +64,973,600 +61,930,200 +Undeveloped properties +4,208,800 +4,508,600 +183,614,200 +167,244,600 +Less accumulated depreciation, depletion and amortization +50,664,600 +39,503,200 +$132,949,600 +127,741,400 +========== +========= +(Continued) +F-19 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +(16) Results of Operations for Oil and Gas Producing Activities +The results of operations for oil and gas producing activities (excluding marketing) are presented below: +Years Ended December 31, +2002 +2001 +2000 +Revenue: +Oil and gas sales +$22,857,100 +25,887,900 +19,017,300 +Expenses: +Production costs +6,407,900 +6,012,400 +4,201,400 +Depreciation, depletion and amortization +11,149,000 +9,665,300 +6,031,200 +17,556,900 +15,677,700 +10,232,600 +Results of operations for oil and gas +Producing activities before provision +For income taxes +5,300,200 +10,210,200 +8,874,700 +Provision for income taxes +1,538,400 +2,834,900 +2,713,900 +Results of operations for oil and gas +producing activities (excluding corporate +overhead and interest costs) +$ 3,761,800 +7,375,300 +6,070,800 +========= +========= +========= +Production costs include those costs incurred to operate and maintain productive wells and related equipment, including such costs as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance and other production taxes. In addition, production costs include administrative expenses and depreciation applicable to support equipment associated with these activities. +Depreciation, depletion and amortization expense includes those costs associated with capitalized acquisition, exploration and development costs, but does not include the depreciation applicable to support equipment. +The provision for income taxes is computed at the statutory federal income tax rate and is reduced to the extent of permanent differences, such as investment tax and non-conventional source fuel tax credits and statutory depletion allowed for income tax purposes. +(17) Net Proved Oil and Gas Reserves (Unaudited) +The proved reserves of oil and gas of the Company have been estimated by an independent petroleum engineer, Wright & Company, Inc. at December 31, 2002, 2001 and 2000. These reserves have been prepared in compliance with the Securities and Exchange Commission rules based on year end prices. An analysis of the change in estimated quantities of oil and gas reserves, all of which are located within the United States, is shown below: +(Continued) +F-20 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +Oil (BBLS) +2002 +2001 +2000 +Proved developed and +Undeveloped reserves: +Beginning of year +2,126,000 +2,166,000 +1,154,000 +Revisions of previous estimates +124,000 +(176,000 ) +10,000 +Beginning of year as revised +2,250,000 +1,990,000 +1,164,000 +New discoveries and extensions +Michigan basin +- +- +265,000 +Rocky Mountain region +130,000 +715,000 +535,000 +Dispositions to partnerships +(80,000) +(384,000) +(262,000) +Acquisitions +Rocky Mountain region +- +- +573,000 +Production +(227,000 ) +(195,000 ) +(109,000 ) +End of year +2,073,000 +2,126,000 +2,166,000 +======== +======== +======== +Proved developed reserves: +Beginning of year +1,801,000 +1,527,000 +798,000 +======== +======== +======== +End of year +1,849,000 +1,801,000 +1,527,000 +======== +======== +======== +Gas (MCF) +2002 +2001 +2000 +Proved developed and undeveloped reserves: +Beginning of year +118,608,000 +118,640,000 +101,245,000 +Revisions of previous estimates +1,469,000 +(8,694,000 ) +(3,859,000 ) +Beginning of year as revised +120,077,000 +109,946,000 +97,386,000 +New discoveries and extensions +Michigan basin +- +- +14,191,000 +Rocky Mountain region +19,607,000 +23,896,000 +14,603,000 +Other +- +- +266,000 +Dispositions to partnerships +(4,792,000) +(9,263,000) +(8,498,000) +Acquisitions +Michigan Basin +4,000 +- +- +Rocky Mountain region +75,000 +2,000 +5,761,000 +Appalachian basin +342,000 +112,000 +668,000 +Production +(6,462,000 ) +( 6,085,000 ) +(5,737,000 ) +End of year +128,851,000 +118,608,000 +118,640,000 +========= +========= +========= +Proved developed reserves: +Beginning of year +88,477,000 +92,131,000 +82,628,000 +========= +========= +========= +End of year +94,847,000 +88,477,000 +92,131,000 +========= +========= +========= +(18) Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves (Unaudited) +Summarized in the following table is information for the Company with respect to the standardized measure of discounted future net cash flows relating to proved oil and gas reserves. Future cash inflows are computed by applying year-end prices, adjusted for hedging contracts, of oil and gas relating to the Company's proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the statutory rate in effect at the end of each year to the future pretax net cash flows, less the tax basis of the properties and gives effect to permanent differences, tax credits and allowances related to the properties. +(Continued) +F-21 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +As of December 31, +2002 +2001 +2000 +Future estimated revenues +$548,949,000 +317,515,000 +520,010,000 +Future estimated production costs +(143,878,000) +(98,538,000) +(144,505,000) +Future estimated development costs +(50,971,000) +(45,323,000) +(50,278,000) +Future estimated income tax expense +(105,876,000 ) +(50,360,000 ) +(80,982,000 ) +Future net cash flows +248,224,000 +123,294,000 +244,245,000 +10% annual discount for estimated timing of cash flows +( 149,755,000 ) +( 76,855,000 ) +(139,606,000 ) +Standardized measure of discounted future estimated net cash flows +$98,469,000 +46,439,000 +104,639,000 +========= +========= +========= +The following table summarizes the principal sources of change in the standardized measure of discounted future estimated net cash flows: +Years Ended December 31, +2002 +2001 +2000 +Sales of oil and gas production, net of production costs +$(16,449,000) +(19,876,000) +(14,816,000) +Net changes in prices and production costs +143,574,000 +(140,487,000) +67,460,000 +Extensions, discoveries and improved recovery, less related cost +39,347,000 +25,942,000 +73,636,000 +Dispositions to partnerships +(6,940,000) +(28,935,000) +(16,850,000) +Acquisitions +1,167,000 +189,000 +27,907,000 +Development costs incurred during the period +16,429,000 +35,412,000 +15,556,000 +Revisions of previous quantity estimates +3,318,000 +(23,818,000) +(5,925,000) +Changes in estimated income taxes +(55,516,000) +30,622,000 +(41,052,000) +Accretion of discount +(72,900,000 ) +62,751,000 +(59,731,000 ) +$ 52,030,000 +(58,200,000) +46,185,000 +========== +========= +======== +It is necessary to emphasize that the data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein. +(Continued) +F-22 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +(19) Business Segments (Thousands) +PDC's operating activities can be divided into three major segments: drilling and development, natural gas sales, and well operations. The Company drills natural gas wells for Company-sponsored drilling partnerships and retains an interest in each well. The Company also engages in oil and gas sales to commercial and industrial end-users. The Company charges Company-sponsored partnerships and other third parties competitive industry rates for well operations and gas gathering. Segment information for the years ended December 31, 2002, 2001 and 2000 is as follows: +2002 +2001 +2000 +REVENUES +Drilling and Development +$57,149 +76,291 +43,195 +Oil and Natural Gas Sales +69,223 +92,095 +90,420 +Well Operations +6,116 +5,604 +5,061 +Unallocated amounts (1) +2,854 +3,133 +2,540 +Total +$135,342 +177,123 +141,216 +======= +======= +======= +2002 +2001 +2000 +SEGMENT INCOME BEFORE INCOME TAXES +Drilling and Development +$7,983 +10,291 +7,950 +Oil and Natural Gas Sales +5,474 +10,570 +7,364 +Well Operations +2,788 +2,415 +1,385 +Unallocated amounts (2) +General and Administrative expenses +(4,392) +(4,146) +(3,617) +Interest expense +(1,340) +(993) +(1,186) +Other (1) +2,569 +2,946 +2,378 +Total +$ 13,082 +21,083 +14,274 +======= +======= +======= +2002 +2001 +2000 +SEGMENT ASSETS +Drilling and Development +$31,279 +36,202 +31,592 +Oil and Natural Gas Sales +162,232 +142,865 +139,116 +Well Operations +10,706 +11,975 +8,490 +Unallocated amounts +Cash +1,736 +422 +1,567 +Other +6,299 +8,388 +6,920 +Total +$212,252 +199,852 +187,685 +======= +======= +======= +2002 +2001 +2000 +EXPENDITURES FOR SEGMENT +LONG-LIVED ASSETS +Drilling and Development +$ 1,800 +5,963 +3,217 +Oil and Natural Gas Sales +16,674 +35,488 +23,958 +Well Operations +1,221 +839 +650 +Unallocated amounts +82 +371 +107 +Total +$ 19,777 +42,661 +27,932 +======= +======= +======= +(1) Includes interest on investments and partnership management fees in 2002, 2001 and 2000 and gain on sale +of assets in 2002, 2001 and 2000 which are not allocated in assessing segment performance. +(2) Items which are not allocated in assessing segment performance. +(Continued) +F-23 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +(20) Quarterly Financial Data (Unaudited ) +Summarized quarterly financial data for the years ended December 31, 2002 and 2001, are as follows: +2002 +Quarter +Year +First +Second +Third +Fourth +Revenues +$36,085,900 +$33,468,900 +$28,148,600 +$37,638,500 +$135,341,900 +Cost of operations +30,644,300 +28,590,800 +25,557,500 +31,735,400 +116,528,000 +Gross profit +5,441,600 +4,878,100 +2,591,100 +5,903,100 +18,813,900 +General and administrative expenses +975,700 +1,027,400 +1,069,900 +1,318,900 +4,391,900 +Interest expense +239,300 +355,900 +399,800 +344,800 +1,339,800 +1,215,000 +1,383,300 +1,469,700 +1,663,700 +5,731,700 +Income before income taxes +4,226,600 +3,494,800 +1,121,400 +4,239,400 +13,082,200 +Income taxes +1,297,600 +1,072,900 +232,400 +1,194,500 +3,797,400 +Net income +$2,929,000 +$ 2,421,900 +$ 889,000 +$ 3,044,900 +$ 9,284,800 +======== +========= +========= +========= +========= +Basic earnings per share +$ .18 +$ .15 +$ .06 +$ .20 +$ .59 +==== +==== +==== +==== +==== +Diluted earnings per share +$ .18 +$ .15 +$ .05 +$ .20 +$ .58 +==== +==== +===== +==== +==== +2001 +Quarter +Year +First +Second +Third +Fourth +Revenues +$59,541,400 +$47,129,000 +$33,336,600 +$37,116,100 +$177,123,100 +Cost of operations +50,330,400 +40,465,600 +27,546,300 +32,558,900 +150,901,200 +Gross profit +9,211,000 +6,663,400 +5,790,300 +4,557,200 +26,221,900 +General and administrative expenses +961,400 +998,400 +1,143,200 +1,042,700 +4,145,700 +Interest expense +213,900 +213,700 +249,400 +316,400 +993,400 +1,175,300 +1,212,100 +1,392,600 +1,359,100 +5,139,100 +Income before +Income taxes +8,035,700 +5,451,300 +4,397,700 +3,198,100 +21,082,800 +Income taxes +2,410,700 +1,635,400 +1,220,200 +848,700 +6,115,000 +Net income +$5,625,000 +$ 3,815,900 +$ 3,177,500 +$ 2,349,400 +$14,967,800 +========= +========= +========= +========= +========= +Basic earnings per share +$ .35 +$ .23 +$ .20 +$ .14 +$ .92 +==== +==== +===== +==== +==== +Diluted earnings per share +$ .34 +$ .23 +$ .19 +$ .14 +$ .90 +==== +==== +===== +==== +==== +Cost of operations include cost of oil and gas well drilling operations, cost of gas marketing activities, oil and gas production costs and depreciation, depletion and amortization. +F-24 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS +AND RESERVES +Years Ended December 31, 2002, 2001 and 2000 +Column A +Column B +Column C +Column D +Column E +Additions, +Balance at +Charged to +Balance +Beginning +Costs and +at End +Description +of Period +Expenses +Deductions +of Period +Allowance for doubtful accounts deducted +From accounts and notes receivable in the +Balance sheet +2002 +$524,500 +$ - +$ 29,500 +$495,000 +======= +======= +======= +======= +2001 +$524,500 +$ - +$ - +$524,500 +======= +======= +======= +======= +2000 +$438,400 +$573,000 +$486,900 +$524,500 +======= +======= +======= +======= +F-25 \ No newline at end of file diff --git a/raw/filings/0000077877/2002/0000077877-03-000003/filing_metadata.csv b/raw/filings/0000077877/2002/0000077877-03-000003/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..b77c184c511ff01beae0f9ecf51e01fb262cfa8f --- /dev/null +++ b/raw/filings/0000077877/2002/0000077877-03-000003/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 +0000077877,PDCE,"PDC ENERGY, INC.",10-K,2003-03-07,2002-12-31,2003-03-07T22:11:02.000Z,0000077877-03-000003,pdc10k2002.htm,PDC 2002 FORM 10-K,1160087,0,0,https://www.sec.gov/Archives/edgar/data/77877/000007787703000003/pdc10k2002.htm,https://www.sec.gov/Archives/edgar/data/77877/000007787703000003/,2002,2002,1 diff --git a/raw/filings/0000077877/2002/0000077877-03-000003/item1.txt b/raw/filings/0000077877/2002/0000077877-03-000003/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..49392713c4c3e96298e6616c9a01c4f2d39832c6 --- /dev/null +++ b/raw/filings/0000077877/2002/0000077877-03-000003/item1.txt @@ -0,0 +1,98 @@ +Item 1. Business +The Company is an independent energy company engaged primarily in the development, production and marketing of natural gas and oil. The Company has grown primarily through drilling and development activities, the acquisition of natural gas and oil producing wells and the expansion of its natural gas marketing activities. As of December 31, 2002, the Company operates approximately 2,200 wells located in the Appalachian basin, Michigan, and the Rocky Mountain Region, with gross proved reserves of 364 billion cubic feet equivalent of natural gas ("Bcfe", based on one barrel of oil equals 6 thousand cubic feet equivalent of natural gas ("Mcfe")) of which the Company's share is 141 Bcfe. The wells operated by the Company currently produce an aggregate of approximately 55,000 thousand cubic feet equivalent of gas per day, of which the Company's share is approximately 21,500 Mcfe. +The Company's operations are divided into three regions, the Appalachian Basin, Michigan Basin, and the Rocky Mountain Region. The Company has conducted operations in Appalachian Basin since its inception in 1969, in Michigan Basin since 1997, and the Rocky Mountain Region since 1999. During 2002 approximately 27% of production was generated by Appalachian Basin wells, 28% by Michigan Basin wells and 45% by Rocky Mountain wells. As of the end of 2002, the Company's total proved reserves were located as follows: Appalachian Basin 32%, Michigan Basin 20% and Rocky Mountain Region 48%. The majority of the Company's undeveloped reserves are in the Rocky Mountain Region and the planned drilling for 2003 will be focused in that area. +In all three regions the Company has historically targeted shallow, developmental natural gas reserves for development. In some areas of the Rocky Mountain Region, Michigan and the Appalachian Basin the wells also produce oil in conjunction with natural gas. +The Company owns Riley Natural Gas (RNG), a natural gas marketing company, which aggregates and resells natural gas developed by the Company and other producers. This allows the Company to diversify its operations beyond natural gas drilling and production. RNG has established relationships with many of the natural gas producers in the Appalachian Basin and has significant expertise in the natural gas end-user market. In addition, RNG has extensive experience in the use of hedging strategies, which the Company utilizes to manage the financial impact on the Company of changes in the price of natural gas. +Since 1984, the Company has sponsored limited partnerships formed to engage in drilling operations. The Company typically purchases a 20% ownership interest in these drilling limited partnerships. In 2002, the Company, through four public drilling partnerships, raised $56.9 million making it the sponsor of the largest public oil and gas partnership program in the United States as it has been for the last several years. The drilling programs have provided the Company with access to the capital resources necessary to expand its drilling opportunities and to maintain the infrastructure necessary to support such activities. +Available Information +The Company's Internet address is www.petd.com. Electronic copies of the Company's annual report on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, and amendments to those reports are available free of charge by visiting the "Investor Relations - Edgar Link" section of www.petd.com. These reports are posted as soon as reasonably practicable after they are electronically filed with the Securities and Exchange Commission. +Industry Overview +Natural gas is the second largest energy source in the United States, after liquid petroleum. The 21.5 Tcf of natural gas consumed in 2002 represented approximately 23% of the total energy used in the United States. Natural gas is consumed in the United States as follows: 37% by industrial end-users as feedstock for products such as plastic and fertilizer or as the energy source for producing products such as glass; 23% and 15% by residential and commercial end-users, respectively, for uses including heating, cooling and cooking; and 25% by utilities for the generation of electricity. (Source U.S. Energy Information Administration) +-2- +The Company believes that the market for natural gas will grow in the future. The demand for natural gas has increased due to four main factors: +Efficiency. Relative to other energy sources, natural gas losses during transportation from source to destination are slight, averaging only about 9% of the natural gas energy. +Environmentally favorable. Natural gas is the cleanest and most environmentally safe of the fossil fuels. +Safety. The delivery of natural gas is among the safest means of distributing energy to customers, as the natural gas transmission system is fixed and is located underground. +Price. The deregulation of the natural gas industry and a favorable regulatory environment have resulted in end-users' ability to purchase natural gas on a competitive basis from a greater variety of sources. +The Company believes that the foregoing factors, together with the increased availability of natural gas as a form of energy for residential, commercial and industrial uses, should increase the demand for natural gas as well as create new markets for natural gas. +As local supplies of natural gas are inadequate to meet demand in certain sections of the country, the West Coast and the Northeast import natural gas from producing areas via interstate natural gas pipelines. The cost of transporting natural gas from the major producing areas to markets creates a price advantage for production located closer to the consuming regions. The natural gas industry in the Appalachian Basin and Michigan benefit from proximity to the northeastern United States. In contrast, much of the production in the Rocky Mountains is transported significant distances to end use markets. +In the early 1980's, natural gas companies began exploiting the northern portion of Michigan's lower peninsula, when certain favorable tax credits for natural gas development were enacted. The result of such development was new advances in drilling technology, which made natural gas drilling in this area profitable even after the expiration of these tax credits. In Michigan's lower peninsula, there is an abundance of shallow Antrim gas shale, which can provide significant reserves per well drilled. Additionally, this area is close to certain end-user markets, which has provided favorable premiums in gas sales prices. +During 1998 the Company began to establish a lease position in the Rocky Mountain producing region. The region is believed to hold substantial undeveloped natural gas resources. Recent and planned additions to pipeline capacity in the region have made the area more attractive for development. Gas from the region will generally sell for less than gas in the Appalachian and Michigan Basins, but costs of development are expected to be less. The Company currently has over 150 development locations in the Wattenberg field in the DJ Basin, and 63,000 acres available for development in the Piceance Basin, both basins are located in Colorado. +Business Strategy +The Company's objective is to expand its natural gas reserves, production and revenues through a strategy that includes the following key elements: +-3- +Expand drilling operations. For its size, the Company has had one of the most active drilling programs in the country. The Company drilled 70 wells in 2002, compared to 141 wells in 2001. The Company believes that it will be able to drill a substantial number of new wells on its current undeveloped leased properties. As of December 31, 2002, the Company had leases or other development rights to 3,500 undeveloped acres in the Michigan Basin, 950 undeveloped acres in the Appalachian Basin and 69,300 undeveloped acres in the Rocky Mountain Region. As drilling activity increases, the Company benefits as its fixed costs may be spread over a larger number of wells. +Acquire producing properties. The Company's acquisition efforts are focused on properties that fit well within existing operations or that help to build critical mass in areas where the Company is establishing new operations. Acquisitions will likely offer economies in management and administration, and therefore the Company believes that it will be able to acquire more producing wells without incurring substantial increases in its administrative costs. +Pursue geographic expansion. The Company has proven its ability to drill and operate in geographically diverse domestic areas. Since 1996, the Company expanded its operations from the Appalachian Basin, first to Michigan, and more recently to the Rocky Mountains. In 2002 over two-thirds of the Company's production was generated in the two newer regions. The Company plans to conduct the majority of its drilling activities in the Rocky Mountain region during 2003, but will continue to seek additional opportunities for expansion to areas where the Company's experience and expertise can be applied successfully. +Reduce risks inherent in natural gas development and marketing. An integral part of the Company's strategy has been and will continue to be to concentrate on shallow development, (rather than exploratory) drilling, and geographical diversification to reduce risk levels associated with natural gas and oil production. Development drilling is less risky than exploratory drilling and is likely to generate cash returns more quickly. The focus on shallow wells builds on the Company's knowledge and experience, and also provides greater investment diversification than an equal investment in a smaller number of deeper and/or more expensive wells. Geographical diversification can help to offset possible weakness in the natural gas market or disappointing drilling results in one area. The Company believes that successful natural gas marketing is essential to profitable operations in a deregulated gas market. To further this goal, the Company has the expertise of RNG, an experienced natural gas marketer. The Company also uses natural gas and oil hedges to reduce the effects of volatility of energy prices. The Company intends to continue to expand its marketing capabilities to keep pace with the changing natural gas industry. +Exploration and Development Activities +The Company's development activities focus on the identification and drilling of new productive wells and the acquisition of existing producing wells from other producers. +Prospect Generation +The Company's staff of professional geologists is responsible for identifying areas with potential for economic production of natural gas and oil. These geologists have decades of cumulative experience drilling natural gas and oil wells. They utilize results from logs and other tools to evaluate existing wells and to predict the location of attractive new gas reserves. To further this process, the Company has collected and continues to collect logs, core data, production information and other raw data available from state and private agencies, other companies and individuals actively drilling in the regions being evaluated. From this information the geologists develop models of the subsurface structures and formations that are used to predict areas with above-average prospects for economic development. +-4- +On the basis of these models, the geologists instruct the Company's land department to obtain available natural gas leaseholds, farmouts and other development rights in these prospective areas. These rights are then obtained, if possible, by the Company's land department or contract landmen under the direction of the Company's land manager. In most cases, the Company pays a lease bonus and annual rental payments, converting, upon initiation of production, to a royalty on gross production revenue in return for obtaining the leases. In addition overriding royalty payments may be made to third parties in conjunction with the acquisition of drilling rights initially leased by others. As of December 31, 2002, the Company had a total leasehold inventory of approximately 183,950 acres. See--"Properties--Oil and Natural Gas Leases." +Drilling Activities +When prospects have been identified and leased, the Company develops these properties by drilling wells. In 2002, the Company drilled a total of 70 wells all of which were successfully completed as producing wells. Typically, the Company will act as driller-operator for these prospects, entering into contracts with partnerships, primarily Company-sponsored partnerships, and other entities that are interested in exploration or development of the prospects. The Company generally retains an interest in each well it drills. See "Financing of Drilling Activities." +Much of the work associated with drilling, completing and connecting wells, including drilling, fracturing, logging and pipeline construction, is performed by subcontractors specializing in those operations, as is common in the industry. A large part of the material and services used by the Company in the development process is acquired through competitive bidding by approved vendors. The Company also directly negotiates rates and costs for services and supplies when conditions indicate that such an approach is warranted. As the prices paid to the Company by its investor partners for the Company's services are frequently fixed before the wells are drilled or are determined solely on the well depth, the Company is subject to the risk that prices of goods or services used in the development process could increase, rendering its contracts with its investor partners less profitable or unprofitable. In addition, problems encountered in the process can substantially increase development costs, sometimes without recourse for the Company to recover its costs from its partners. To minimize these risks, the Company seeks to lock in its development costs in advance of drilling and, when possible, at the time of negotiation and execution of its investor partnership agreements. +Acquisitions of Producing Properties +In addition to drilling new wells, the Company continues to pursue opportunities to purchase existing wells from other producers and greater ownership interests in the wells it operates. Generally, outside interests purchased include a majority interest in the wells and well operations. +During 1999, the Company purchased a 100% working interest in 53 producing wells in the D-J Basin of Colorado which added 3.6 Bcf of natural gas and 370,000 barrels of oil to the Company's reserves. During 2000, the Company purchased 100% of the working interest in 168 producing wells in the DJ Basin of Colorado which added 4.9 Bcf of natural gas and 560,000 barrels of oil to the Company's reserves. Certain well interests in its Company sponsored partnerships were also purchased in 2002, 2001 and 2000. +-5- +Production +The following table shows the Company's net production in Bbls of crude oil and in Mcf of natural gas and the costs and weighted average selling prices thereof, for the last five years. +Year Ended December 31, +2002 +2001 +2000 +1999 +1998 +Production(1): +Oil(MBbls) +227 +195 +109 +8 +8 +Natural Gas (MMcf) +6,462 +6,085 +5,737 +3,451 +2,453 +Equivalent MMcfs(2) +7,824 +7,255 +6,391 +3,499 +2,501 +Average sales price: +Oil (per Bbl) +$24.41 +$22.53 +$29.99 +$18.75 +$10.61 +Natural gas (per Mcf)(3) +$2.68 +$3.53 +$2.74 +$2.46 +$2.46 +Average production cost (lifting cost) Per equivalent Mcf(4) +$0.82 +$0.83 +$0.66 +$0.69 +$0.61 +---------- +(1) Production as shown in the table is net to the Company and is determined by multiplying the gross production volume of properties in which the Company has an interest by the percentage of the leasehold or other property interest owned by the Company. +(2) A ratio of energy content of natural gas and oil (six Mcf of natural gas equals one barrel of oil) was used to obtain a conversion factor to convert oil production into equivalent Mcfs of natural gas. +(3) The Company utilizes commodity-based derivative instruments as hedges to manage a portion of its exposure to price volatility of its natural gas sales. The effect of hedges on the average sales price of natural gas for the years ended December 31, 2002, 2001, 2000, 1999 and 1998 was $0.02, $(0.56), $(0.91), $(0.01) and $0.14, respectively. +(4) Production costs represent oil and gas operating expenses as reflected in the financial statements of the Company. +Well Operations +The Company currently operates approximately 1,502 wells in the Appalachian Basin, 204 wells in the Michigan Basin and 463 wells in the Rocky Mountain Region. The Company's ownership interest in these wells ranges from 0% to 100%, and, on average, the Company has an approximate 50% ownership interest in the wells it operates. Currently these wells produce an aggregate of about 55,000 Mcfe of natural gas per day, including the Company's share of 21,500 Mcfe per day. +The Company is paid a monthly operating charge for each well it operates for outside owners. The rate is competitive with rates charged by other operators in the area. The charge covers monthly operating and accounting costs, insurance and other recurring costs. The Company may also receive additional compensation for special non-recurring activities, such as reworks and recompletions. +Transportation +Natural gas wells are connected by pipelines to natural gas markets. Over the years, the Company has developed extensive gathering systems in some of its areas of operations. The Company also continues to construct new trunklines as necessary to provide for the marketing of natural gas being developed from new areas and to enhance or maintain its existing systems. +The Company is paid a transportation fee for natural gas that is moved by other shippers through these pipeline systems. In many cases the Company has been able to receive higher natural gas prices as a result of its ability to move natural gas to more attractive markets through this pipeline system, to the benefit of both the Company and its investor partners. +-6- \ No newline at end of file diff --git a/raw/filings/0000077877/2002/0000077877-03-000003/item13.txt b/raw/filings/0000077877/2002/0000077877-03-000003/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..18e060e0a58b4b5fbe785f4026acf4eb03f4b864 --- /dev/null +++ b/raw/filings/0000077877/2002/0000077877-03-000003/item13.txt @@ -0,0 +1,2 @@ +Item 13. Certain Relationships and Related Transactions +The response to this item is set forth herein in Note 8 in the Notes to Consolidated Financial Statements and under "Election of Directors - Interest of Management in Certain Transactions," in the Company's definitive proxy statement for its 2003 annual meeting of stockholders filed or to be filed with the Commission on or before April 30, 2003. \ No newline at end of file diff --git a/raw/filings/0000077877/2002/0000077877-03-000003/item9a.txt b/raw/filings/0000077877/2002/0000077877-03-000003/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2002/0000077877-03-000003/rp_note.txt b/raw/filings/0000077877/2002/0000077877-03-000003/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2002/0000077877-03-000003/rpt_disclosure.txt b/raw/filings/0000077877/2002/0000077877-03-000003/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..18e060e0a58b4b5fbe785f4026acf4eb03f4b864 --- /dev/null +++ b/raw/filings/0000077877/2002/0000077877-03-000003/rpt_disclosure.txt @@ -0,0 +1,2 @@ +Item 13. Certain Relationships and Related Transactions +The response to this item is set forth herein in Note 8 in the Notes to Consolidated Financial Statements and under "Election of Directors - Interest of Management in Certain Transactions," in the Company's definitive proxy statement for its 2003 annual meeting of stockholders filed or to be filed with the Commission on or before April 30, 2003. \ No newline at end of file diff --git a/raw/filings/0000077877/2003/0000077877-04-000012/filing.txt b/raw/filings/0000077877/2003/0000077877-04-000012/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..03f89401b9cdafb2888669a2fd24b145be51b6dd --- /dev/null +++ b/raw/filings/0000077877/2003/0000077877-04-000012/filing.txt @@ -0,0 +1,2900 @@ +10-K +1 +pdc10k2003.htm +PDC 10K +CONFORMED COPY +CONFORMED COPY +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 +Commission File Number 0-7246 +[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transaction period from to +PETROLEUM DEVELOPMENT CORPORATION +(Exact name of registrant as specified in its charter) +Nevada +95-2636730 +(State or other jurisdiction of +(I.R.S. Employer +incorporation or organization) +Identification No.) +103 East Main Street, Bridgeport, West Virginia 26330 +(Address of principal executive offices) (zip code) +Registrant's telephone number, including area code (304) 842-3597 +SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: NONE +SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: +Petroleum Development Corporation Common Stock, $.01 par value +(Title of class) +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 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 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 definition in Rule 12b-2 of the Exchange Act). Yes X No +As of February 27, 2004, 15,960,894 shares of the Registrant's Common Stock were issued and outstanding, and the aggregate market value of such shares held by non-affiliates of the Registrant on June 30, 2003, the last business day of the Registrant's most recently completed second quarter was $105,785,917 (based on the last traded price of $9.12). +DOCUMENTS INCORPORATED BY REFERENCE +Document +Form 10-K Part III +Proxy +Items 10, 11, 12, and 13 +(except as presented herein) +PART I +Item 1. Business +The Company is an independent energy company engaged primarily in the development, production and marketing of natural gas and oil. The Company has grown primarily through drilling and development activities, the acquisition of natural gas and oil producing wells and the expansion of its natural gas marketing activities. As of December 31, 2003, the Company operates over 2,500 wells located in the Appalachian basin, Michigan, and the Rocky Mountain Region, with gross proved reserves of 468 billion cubic feet equivalent of natural gas ("Bcfe", based on one barrel of oil equals 6 thousand cubic feet equivalent of natural gas ("Mcfe")) of which the Company's share is 199 Bcfe. The Company's share of production for the fourth quarter of 2003 averaged 34,000 Mcfe per day compared to 21,000 Mcfe per day during the fourth quarter of 2002. +The Company's operations are divided into three regions, the Appalachian Basin, Michigan, and the Rocky Mountain Region. The Company has conducted operations in Appalachian Basin since its inception in 1969, in Michigan Basin since 1997, and the Rocky Mountain Region since 1999. During 2003 approximately 19% of production was generated by Appalachian Basin wells, 18% by Michigan Basin wells and 63% by Rocky Mountain wells. As of the end of 2003, the Company's total proved reserves were located as follows: Appalachian Basin 21%, Michigan 13% and Rocky Mountain Region 66%. The majority of the Company's undeveloped reserves are in the Rocky Mountain Region and the planned drilling for 2004 will be focused in that area. +In all three regions the Company has historically targeted shallow, developmental natural gas reserves for development. In some areas of the Rocky Mountain Region, Michigan and the Appalachian Basin the wells also produce oil in conjunction with natural gas. +The Company owns Riley Natural Gas (RNG), a natural gas marketing company, which aggregates and resells natural gas developed by the Company and other producers. This allows the Company to diversify its operations beyond natural gas drilling and production. RNG has established relationships with many of the natural gas producers in the Appalachian Basin and has significant expertise in the natural gas end-user market. In addition, RNG has extensive experience in the use of hedging strategies, which the Company utilizes to manage the financial impact on the Company of changes in the price of natural gas and oil. +Since 1984, the Company has sponsored limited partnerships formed to engage in drilling operations. The Company typically purchases a 20% ownership interest in these drilling limited partnerships. In 2003, the Company, through four public drilling partnerships, raised $78.3 million making it the sponsor of the largest public oil and gas partnership program in the United States as it has been for the last several years. The drilling programs have provided the Company with access to the capital resources necessary to expand its drilling opportunities and to maintain the infrastructure necessary to support such activities. +Available Information +The Company's Internet address is www.petd.com. Electronic copies of the Company's annual report on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, and amendments to those reports are available free of charge by visiting the "Financial Information" section of www.petd.com. These reports are posted as soon as reasonably practicable after they are electronically filed with the Securities and Exchange Commission. Additionally, information including the Company's Code of Business Conduct and Ethics is also available at the site. +Industry Overview +Natural gas is the second largest energy source in the United States, after liquid petroleum. The estimated 22.1 Tcf of natural gas consumed in 2003 represented approximately 23% of the total energy used in the United States. Natural gas is consumed in the United States as follows: 36% by industrial end-users as feedstock for products such as plastic and fertilizer or as the energy source for producing products such as glass; 23% and 14% by residential and commercial end-users, respectively, for uses including heating, cooling and cooking; and 23% by utilities for the generation of electricity; and 4% for other users. (Source U.S. Energy Information Administration) +-2- +The Company believes that the market for natural gas will grow in the future. The demand for natural gas has increased due to four main factors: +Efficiency. Relative to other energy sources, natural gas losses during transportation from source to destination are slight, averaging only about 5% of the natural gas energy. +Environmentally favorable. Natural gas is the cleanest and most environmentally safe of the fossil fuels. +Safety. The delivery of natural gas is among the safest means of distributing energy to customers, as the natural gas transmission system is fixed and is located underground. +Price. The deregulation of the natural gas industry and a favorable regulatory environment have resulted in end-users' ability to purchase natural gas on a competitive basis from a greater variety of sources. +The Company believes that the foregoing factors, together with the increased availability of natural gas as a form of energy for residential, commercial and industrial uses, should increase the demand for natural gas as well as create new markets for natural gas. +Because local supplies of natural gas are inadequate to meet demand in certain sections of the country, the West Coast and the Northeast import natural gas from producing areas via interstate natural gas pipelines. The cost of transporting natural gas from the major producing areas to markets creates a price advantage for production located closer to the consuming regions. The natural gas industry in the Appalachian Basin and Michigan benefit from proximity to the northeastern United States. In contrast, much of the production in the Rocky Mountains is transported significant distances to end use markets. +During 1998 the Company began to establish a lease position in the Rocky Mountain producing region. The region is believed to hold substantial undeveloped natural gas resources. Recent and planned additions to pipeline capacity in the region have made the area more attractive for development. Gas from the region will generally sell for less than gas in the Appalachian and Michigan Basins, but costs of development are expected to be less. The Company currently has over 150 development locations in the Wattenberg field in the DJ Basin, and 22,500 acres available for development in the Piceance Basin, both basins are located in Colorado. +Business Strategy +The Company's objective is to expand its oil and natural gas reserves, production and revenues through a strategy that includes the following key elements: +Expand drilling operations. For its size, the Company has had one of the most active drilling programs in the country. The Company drilled 111 wells in 2003, compared to 70 wells in 2002. The Company believes that it will be able to drill a substantial number of new wells on its current undeveloped leased properties. As of December 31, 2003, the Company had leases or other development rights to 3,100 undeveloped acres in the Michigan Basin, 850 undeveloped acres in the Appalachian Basin and 181,400 undeveloped acres in the Rocky Mountain Region. As drilling activity increases, the Company benefits as its fixed costs may be spread over a larger number of wells. +Acquire producing properties. The Company's acquisition efforts are focused on properties that fit well within existing operations or in areas where the Company is establishing new operations. Acquisitions have historically offered economies in management and administration, and therefore the Company believes that it will be able to acquire more producing wells without incurring substantial increases in its administrative costs. +-3- +Pursue geographic expansion. The Company has proven its ability to drill and operate in geographically diverse domestic areas. In 1997, the Company expanded its operations from the Appalachian Basin, to Michigan and in late 1999 to the Rocky Mountains. In 2003 over 63% of the Company's production was generated in the Rocky Mountains. The Company plans to conduct the majority of its drilling activities in the Rocky Mountain region during 2004, but will continue to seek additional opportunities for expansion to areas where the Company's experience and expertise can be applied successfully. +Reduce risks inherent in oil and natural gas development and marketing. An integral part of the Company's strategy has been and will continue to be to concentrate on shallow development (rather than exploratory) drilling, and geographical diversification to reduce risk levels associated with natural gas and oil production. Development drilling is less risky than exploratory drilling and is likely to generate cash returns more quickly. The focus on shallow wells builds on the Company's knowledge and experience, and also provides greater investment diversification than an equal investment in a smaller number of deeper and/or more expensive wells. Geographical diversification can help to offset possible weakness in the natural gas market or disappointing drilling results in one area. The Company believes that successful natural gas marketing is essential to profitable operations in a deregulated gas market. To further this goal, the Company has the expertise of RNG, an experienced natural gas marketer. The Company also uses natural gas and oil hedges to reduce the effects of volatility of energy prices. The Company intends to continue to expand its marketing capabilities to keep pace with the changing natural gas industry. +Exploration and Development Activities +The Company's development activities focus on the identification and drilling of new productive wells and the acquisition of existing producing wells from other producers. +Prospect Generation +The Company's staff of professional geologists is responsible for identifying areas with potential for economic production of natural gas and oil. These geologists have decades of cumulative experience drilling natural gas and oil wells. They utilize results from logs and other tools to evaluate existing wells and to predict the location of attractive new gas reserves. To further this process, the Company has collected and continues to collect logs, core data, production information and other raw data available from state and private agencies, other companies and individuals actively drilling in the regions being evaluated. From this information the geologists develop models of the subsurface structures and formations that are used to predict areas with prospects for economic development. +On the basis of these models, the geologists instruct the Company's land department to obtain available natural gas leaseholds, farmouts and other development rights in these prospective areas. These rights are then obtained, if possible, by the Company's land department or contract landmen under the direction of the Company's land manager. In most cases, the Company pays a lease bonus and annual rental payments, converting, upon initiation of production, to a royalty on gross production revenue in return for obtaining the leases. In addition overriding royalty payments may be made to third parties in conjunction with the acquisition of drilling rights initially leased by others. As of December 31, 2003, the Company had leasehold rights to approximately 185,350 acres available for development. See--"Properties--Oil and Natural Gas Leases." +Drilling Activities +When prospects have been identified and leased, the Company develops these properties by drilling wells. In 2003, the Company drilled a total of 110 development wells all of which were successfully completed as producing wells. During the fourth quarter the Company drilled one exploratory well in Alabama which was dry and according to Successful Efforts Accounting was expensed as an exploratory dry hole. Such dry hole cost amounted to $332,000. Typically, the Company will act as driller-operator for these prospects, entering into contracts with partnerships, primarily Company-sponsored partnerships, and other entities that are interested in exploration or development of the prospects. The Company generally retains an interest in each well it drills. See "Financing of Drilling Activities." +-4- +Much of the work associated with drilling, completing and connecting wells, including drilling, fracturing, logging and pipeline construction, is performed by subcontractors specializing in those operations, as is common in the industry. A large part of the material and services used by the Company in the development process is acquired through competitive bidding by approved vendors. The Company also directly negotiates rates and costs for services and supplies when conditions indicate that such an approach is warranted. As the prices paid to the Company by its investor partners for the Company's services are frequently fixed before the wells are drilled or are determined solely on the well depth, the Company is subject to the risk that prices of goods or services used in the development process could increase, rendering its contracts with its investor partners less profitable or unprofitable. In addition, problems encountered in the process can substantially increase development costs, sometimes without recourse for the Company to recover its costs from its partners. To minimize these risks, the Company seeks to lock in its development costs in advance of drilling and, when possible, at the time of negotiation and execution of its investor partnership agreements. +Acquisitions of Producing Properties +In addition to drilling new wells, the Company continues to pursue opportunities to purchase existing wells from other producers and greater ownership interests in the wells it operates. Generally, outside interests purchased include a majority interest in the wells and well operations. +During the second quarter of 2003, the Company purchased 166 wells in the Denver Julesburg Basin in northeastern Colorado from Williams Production RMT Company for $28 million. The Company estimates the acquisition included approximately 22.6 billion cubic feet (Bcf) of proved developed producing (PDP) and 3.4 Bcf of proved developed non-producing reserves (PDNP), all of which is natural gas. +During the fourth quarter of 2003, the Company purchased from one of its joint venture partners in the Denver-Julesburg Basin in Weld County, Colorado approximately 3.1 billion cubic feet equivalent (Bcfe) of proved developed producing reserves from interests in 20.6 net wells (230 gross) and 1.8 Bcfe of proved developed non-producing reserves from interests in 17 net wells (183 gross). The purchase price was $5.2 million. +During the fourth quarter of 2003, the Company purchased 97 gross wells (73 net) wells in the Denver-Julesburg Basin located in northeast Colorado and northwestern Kansas for $6.0 million. This purchase adds approximately 4.5 billion cubic feet equivalent (Bcfe) of proved developed producing and proved developed non-producing reserves to the Company's oil and gas reserves along with 100,000 acres of oil and gas leases. +Certain well interests in its Company sponsored partnerships were also purchased in 2003, 2002 and 2001. +-5- +Production +The following table shows the Company's net production in Bbls of crude oil and in Mcf of natural gas and the costs and weighted average selling prices thereof, for the last five years. +Year Ended December 31, +2003 +2002 +2001 +2000 +1999 +Production(1): +Oil(MBbls) +289 +227 +195 +109 +8 +Natural Gas (MMcf) +8,712 +6,462 +6,085 +5,737 +3,451 +Equivalent MMcfs(2) +10,449 +7,824 +7,255 +6,391 +3,499 +Average sales price: +Oil (per Bbl) +$29.39 +$24.41 +$22.53 +$29.99 +$18.75 +Natural gas (per Mcf)(3) +$4.42 +$2.68 +$3.53 +$2.74 +$2.46 +Average production cost (lifting cost) +per equivalent Mcf(4) +$0.98 +$0.82 +$0.83 +$0.66 +$0.69 +---------- +(1) Production as shown in the table is net to the Company and is determined by multiplying the gross production volume of properties in which the Company has an interest by the percentage of the leasehold or other property interest owned by the Company. +(2) A ratio of energy content of natural gas and oil (six Mcf of natural gas equals one barrel of oil) was used to obtain a conversion factor to convert oil production into equivalent Mcfs of natural gas. +(3) The Company utilizes commodity-based derivative instruments as hedges to manage a portion of its exposure to price volatility of its natural gas sales. The effect of hedges on the average sales price of natural gas for the years ended December 31, 2003, 2002, 2001, 2000 and 1999 was $(0.09), $0.02, $(0.56), $(0.91), and $(0.01), respectively. +(4) Production costs represent oil and gas operating expenses which include severance and advalorem taxes as reflected in the financial statements of the Company. See Oil and Gas Production Costs in Management's Discussion and Analysis. +Well Operations +The Company currently operates approximately 1,492 wells in the Appalachian Basin, 204 wells in the Michigan Basin and 834 wells in the Rocky Mountain Region. The Company's ownership interest in these wells ranges from 0% to 100%, and, on average, the Company has an approximate 52% ownership interest in the wells it operates. +The Company is paid a monthly operating fee for each well it operates for outside owners including the limited partnerships sponsored by the Company. The fee is competitive with rates charged by other operators in the area. The fee covers monthly operating and accounting costs, insurance and other recurring costs. The Company may also receive additional compensation for special non-recurring activities, such as reworks and recompletions. +Transportation +Natural gas wells are connected by pipelines to natural gas markets. Over the years, the Company has developed extensive gathering systems in some of its areas of operations. The Company also continues to construct new trunklines as necessary to provide for the marketing of natural gas being developed from new areas and to enhance or maintain its existing systems. +The Company is paid a transportation fee for natural gas that is moved by other shippers through these pipeline systems. In many cases the Company has been able to receive higher natural gas prices as a result of its ability to move natural gas to more attractive markets through this pipeline system, to the benefit of both the Company and its investor partners. +-6- +Item 2. Properties +Drilling Activity +The following table summarizes the Company's development drilling activity for the last five years. There is no correlation between the number of productive wells completed during any period and the aggregate reserves attributable to those wells. The Company's exploratory wells drilled in the past five years consist of one dry hole (1.0 net) drilled in 2003 and five dry holes (2.44 net) drilled in 1999. +Development Wells Drilled +Total +Productive +Dry +Drilled +Net +Drilled +Net +Drilled +Net +1999 +173 +54.64 +165 +53.10 +8 +1.54 +2000 +97 +27.39 +97 +27.39 +- +- +2001 +141 +40.00 +135 +37.94 +6 +2.06 +2002 +70 +13.71 +70 +13.71 +- +- +2003 +110 +28.51 +110 +28.51 +- +- +Total +591 +164.25 +577 +160.65 +14 +3.6 +Summary of Productive Wells +The table below shows the number of the Company's productive gross and net wells at December 31, 2003. +Productive Wells +Gas +Oil +Location +Gross +Net +Gross +Net +Colorado +805 +480.20 +- +- +Kansas +26 +21.69 +- +- +Michigan +197 +109.63 +7 +2.66 +North Dakota +- +- +3 +.60 +Ohio +10 +3.10 +- +- +Pennsylvania +531 +168.33 +- +- +Tennessee +1 +0.71 +35 +13.62 +West Virginia +911 +514.24 +4 +1.72 +Total +2,481 +1,297.90 +49 +18.60 +Reserves +All of the Company's oil and natural gas reserves are located in the United States. The Company's approximate net proved reserves were estimated by Wright & Company Inc., independent petroleum engineers ("Wright & Company"), to be 180,998,000 Mcf of natural gas and 3,029,000 Bbls of oil at December 31, 2003, 128,851,000 Mcf of natural gas and 2,073,000 Bbls of oil at December 31, 2002 and 118,608,000 Mcf of natural gas and 2,126,000 Bbls of oil at December 31, 2001. +The Company's approximate net proved developed reserves were estimated, by Wright & Company to be 134,936,000 Mcf of natural gas and 2,889,000 Bbls of oil at December 31, 2003, 94,847,000 Mcf of natural gas and 1,849,000 Bbls of oil at December 31, 2002 and 88,477,000 Mcf of natural gas and 1,801,000 Bbls of oil at December 31, 2001. +-7- +The Company's oil and natural gas reserves by region are as follows as of December 31, 2003: +Oil +(Mbbl) +Gas +(Mmcf) +Natural Gas +Equivalent +(Mmcfe) +% +Proved Developed Reserves +Appalachian Basin +49 +41,715 +42,009 +27.59% +Michigan Basin +43 +23,811 +24,069 +15.81% +Rocky Mountain Region +2,797 +69,410 +86,192 +56.60 % +Total Proved Developed Reserves +2,889 +134,936 +152,270 +100.00% +Proved Undeveloped Reserves +Appalachian Basin +0 +0 +0 +0.00% +Michigan Basin +0 +1,488 +1,488 +3.17% +Rocky Mountain Region +140 +44,574 +45,414 +96.83 % +Total Proved Undeveloped +140 +46,062 +46,902 +100.00% +Total Proved Reserves +Appalachian Basin +49 +41,715 +42,009 +21.09% +Michigan Basin +43 +25,299 +25,557 +12.83% +Rocky Mountain Region +2,937 +113,984 +131,606 +66.08 % +Total Proved Reserves +3,029 +180,998 +199,172 +100.00% +No major discovery or other favorable or adverse event that would cause a significant change in estimated reserves is believed by the Company to have occurred since December 31, 2003. Reserves cannot be measured exactly, as reserve estimates involve subjective judgment. The estimates must be reviewed periodically and adjusted to reflect additional information gained from reservoir performance, new geological and geophysical data and economic changes. +The standardized measure of discounted future estimated net cash flows attributable to the Company's proved oil and gas reserves, giving effect to future estimated income tax expenses, was estimated by Wright & Company to be $217.3 million as of December 31, 2003, $98.5 million as of December 31, 2002 and $46.4 million as of December 31, 2001. These amounts are based on year-end prices. The values expressed are estimates only, and may not reflect realizable values or fair market values of the natural gas and oil ultimately extracted and recovered. The standardized measure of discounted future net cash flows may not accurately reflect proceeds of production to be received in the future from the sale of natural gas and oil currently owned and does not necessarily reflect the actual costs that would be incurred to acquire equivalent natural gas and oil reserves. +-8- +Net Proved Natural Gas and Oil Reserves +The proved reserves of natural gas and oil of the Company as estimated by Wright & Company at December 31, 2003 are set forth below. These reserves have been prepared in compliance with the rules of the Securities and Exchange Commission (the "SEC") based on year-end prices. An analysis of the change in estimated quantities of natural gas and oil reserves from January 1, 2003 to December 31, 2003, all of which are located within the United States, is shown below: +Natural Gas (Mcf) +Oil (Bbls) +Proved developed and undeveloped reserves: +Beginning of year +128,851,000 +2,073,000 +Revisions of previous estimates +4,394,000 +533,000 +Beginning of year as revised +133,245,000 +2,606,000 +New discoveries and extensions +Rocky Mountain region +27,719,000 +517,000 +Dispositions to partnerships +(4,410,000) +(112,000) +Acquisitions +Michigan Basin +265,000 +- +Rocky Mountain region +32,169,000 +307,000 +Appalachian basin +722,000 +- +Production +(8,712,000 ) +(289,000 ) +End of year +180,998,000 +3,029,000 +Proved developed reserves: +Beginning of year +98,847,000 +1,849,000 +End of year +134,936,000 +2,889,000 +Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Natural Gas and +Oil Reserves +Summarized in the following table is information for the Company with respect to the standardized measure of discounted future net cash flows relating to proved natural gas and oil reserves. Future cash inflows are computed by applying year-end prices of natural gas and oil relating to the Company's proved reserves to year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs, assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the statutory rate in effect at December 31, 2003 to the future pretax net cash flows, less the tax basis of the properties, and gives effect to permanent differences, tax credits and allowances related to the properties. +As of +December 31, 2003 +Future estimated revenues +$1,088,415,000 +Future estimated production costs +(250,735,000) +Future estimated development costs +(65,275,000) +Future estimated income tax expense +(265,707,000 ) +Future net cash flows +506,698,000 +10% annual discount for estimated timing of cash flows +(289,408,000 ) +Standardized measure of discounted +future estimated net cash flows +$ 217,290,000 +-9- +The following table summarizes the principal sources of change in the standardized measure of discounted future estimated net cash flows from January 1, 2003 through December 31, 2003: +Sales of oil and natural gas production, net of production costs +$(36,810,000) +Net changes in prices and production costs +162,422,000 +Extensions, discoveries and improved recovery, less related costs +114,533,000 +Dispositions to partnerships +(12,936,000) +Acquisitions +139,078,000 +Development costs incurred during the period +30,630,000 +Revisions of previous quantity estimates +21,388,000 +Changes in estimated income taxes +(159,831,000) +Accretion of discount +(139,653,000 ) +$118,821,000 +It is necessary to emphasize that the data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves, as the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision, and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods and the limitations inherent therein. +Substantially all of the Company's natural gas and oil reserves have been mortgaged or pledged as security for the Company's credit agreement. See Note 3 of Notes to Consolidated Financial Statements. +Oil and Natural Gas Leases +The following table sets forth, as of December 31, 2003, the acres available for development of oil and natural gas available to the Company, listed alphabetically by state. +Alabama +350 +Colorado +152,300 +Kansas +28,400 +Michigan +3,100 +North Dakota +700 +West Virginia +500 +Total +185,350 +Title to Properties +The Company believes that it holds good and indefeasible title to its properties, in accordance with standards generally accepted in the natural gas industry, subject to such exceptions stated in the opinion of counsel employed in the various areas in which the Company conducts its exploration activities, which exceptions, in the Company's judgment, do not detract substantially from the use of such property. As is customary in the natural gas industry, only a perfunctory title examination is conducted at the time the properties believed to be suitable for drilling operations are acquired by the Company. Prior to the commencement of drilling operations, an extensive title examination is conducted and curative work is performed with respect to defects which the Company deems to be significant. A title examination has been performed with respect to substantially all of the Company's producing properties. No single property owned by the Company represents a material portion of the Company's holdings. +-10- +The properties owned by the Company are subject to royalty, overriding royalty and other outstanding interests customary in the industry. The properties are also subject to burdens such as liens incident to operating agreements, current taxes, development obligations under natural gas and oil leases, farm-out arrangements and other encumbrances, easements and restrictions. The Company does not believe that any of these burdens will materially interfere with the use of the properties. +Natural Gas Sales +Natural gas is sold by the Company under contracts with terms ranging from one month to three years. Virtually all of the Company's contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. As a result, the Company's revenues from the sale of natural gas will suffer if market prices decline and benefit if they increase. The Company believes that the pricing provisions of its natural gas contracts are customary in the industry. +The Company sells its natural gas to industrial end-users and utilities. Three customers accounted for 16.6%, 17.4% and 14.3%, respectively of the Company's revenues from oil and gas sales (9.8%, 10.3% and 8.5% of total revenues in 2003.) Two customers accounted for 21.1% and 11.0%, respectively of the Company's revenues from oil and gas sales (10.8% and 5.6% of total revenues) in 2002. One customer accounted for 25.2% of the Company's revenues from oil and gas sales (13.1% of total revenues) in 2001. No other single purchaser of the Company's natural gas accounted for 10% or more of the Company's total revenues during 2003, 2002 and 2001. +At December 31, 2003, natural gas produced by the Company sold at prices per Mcf ranging from $0.90 to $7.36, depending upon well location, the date of the sales contract and other factors. The weighted net average price of natural gas sold by the Company during 2003 was $4.42 per Mcf. +In general, the Company, together with its marketing subsidiary, RNG, has been and expects to continue to be able to produce and sell natural gas from its wells without significant curtailment by providing natural gas to purchasers at competitive prices. Open access transportation on the country's interstate pipeline system has greatly increased the range of potential markets. Whenever feasible the Company allows for multiple market possibilities from each of its gathering systems, while seeking the best available market for its natural gas at any point in time. +Oil Sales +Some of the Company's wells in the Appalachian Basin and Michigan, and most of the Company's wells in Wattenberg field in Colorado, produce oil in addition to natural gas. At the end of 2003 oil was about 9% of the Company's total equivalent reserves. +The Company is currently able to sell all the oil that it can produce under existing sales contracts with petroleum refiners and marketers. The Company does not refine any of its oil production. The Company's crude oil production is sold to purchasers at or near the Company's wells under short-term purchase contracts at prices and in accordance with arrangements that are customary in the oil industry. One purchaser accounted for 11.0% and 11.9% of the Company's revenues from oil and gas sales (6.5% and 5.6% of total revenues) in 2003 and 2002. No customer accounted for more than 10% of the Company's revenues from oil and gas sales in 2001. At December 31, 2003, oil produced by the Company sold at prices ranging from $27.45 to $29.66 per barrel, depending upon the location and quality of oil. In 2003, the weighted net average price per barrel of oil sold by the Company was $29.39. +-11- +Oil production is subject to many of the same operating hazards and environmental concerns as natural gas production, but is also subject to the risk of oil spills. Federal regulations require certain owners or operators of facilities that store or otherwise handle oil, such as the Company, to procure and implement spill prevention, control, counter-measures and response plans relating to the possible discharge of oil into surface waters. The Oil Pollution Act of 1990 ("OPA") subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from oil spills. Noncompliance with OPA may result in varying civil and criminal penalties and liabilities. Operations of the Company are also subject to the Federal Clean Water Act and analogous state laws relating to the control of water pollution, which laws provide varying civil and criminal penalties and liabilities for release of petroleum or its derivatives into surface waters or into the ground. +Natural Gas Marketing +The Company's natural gas marketing activities involve the aggregation and reselling of natural gas produced by the Company and others. The Company believes that in a deregulated market, successful natural gas marketing is essential to profitable operations. A variety of factors affect the market for natural gas, including the availability of other domestic production, natural gas imports, the availability and price of alternative fuels, the proximity and capacity of natural gas pipelines, general fluctuations in the supply and demand for natural gas and the effects of state and federal regulations on natural gas production and sales. The natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual customers. +RNG, a wholly owned subsidiary, is a natural gas marketing company that specializes in the acquisition, aggregation and marketing of natural gas production in the Company's operating areas. RNG markets natural gas produced by the Company and also purchases natural gas from other producers and resells to utilities, end users or other marketers. The employees of RNG have extensive knowledge of natural gas markets in the Company's areas of operations. Such knowledge assists the Company in maximizing its prices as it markets natural gas from Company-operated wells. The gas is marketed to natural gas utilities, pipelines and industrial and commercial customers, either directly through the Company's gathering system, or utilizing transportation services provided by regulated interstate pipeline companies. +Hedging Activities +The Company utilizes commodity-based derivative instruments as hedges to manage a portion of its exposure to price volatility stemming from its natural gas sales and marketing activities. These instruments consist of NYMEX-traded natural gas futures and option contracts for Appalachian and Michigan production, and CIG (Colorado Interstate Gas Index)-based contracts for Colorado production. The contracts hedge committed and anticipated natural gas purchases and sales, generally forecasted to occur within the next twelve-month period. Company policy prohibits the use of natural gas futures or options for speculative purposes and permits utilization of hedges only if there is an underlying physical position. +The Company has extensive experience with the use of financial hedges to reduce the risk and impact of natural gas price changes. These hedges are used by RNG to coordinate fixed and variable priced purchases and sales, and by the Company to "lock in" fixed prices from time to time for the Company's share of production, and to establish "floors" and "ceilings" or "collars" on the possible range of the price realized for the sale of natural gas and oil. In order for contracts to serve as effective hedges, there must be sufficient correlation to the underlying hedged transaction. While hedging can help provide price protection if spot prices drop, hedges can also limit upside potential. +For unhedged natural gas sales not subject to fixed price contracts, the Company is subject to price fluctuations for natural gas sold in the spot market. The Company continues to evaluate the potential for reducing these risks by entering into hedge transactions. In addition, the Company may also close out any portion of hedges that may exist from time to time which may result in a gain or loss on that hedge transaction. There are no hedge contracts outstanding as of December 31, 2003 related to oil production, however subsequent to year-end the Company did enter into oil hedge contracts for 2004. +-12- +Financing of Drilling Activities +The Company conducts development drilling activities for its own account and for other investors. In 1984, the Company began sponsoring private drilling limited partnerships, and, in 1989, the Company began to register the partnership interests offered under public drilling programs with the SEC. The Company's public partnerships had $78.3 million in subscriptions in 2003, $56.9 million in subscriptions in 2002 and $57.1 million in subscriptions in 2001. The Company generally invests, as its equity contribution to each drilling partnership, an additional sum approximating 22% of the aggregate subscriptions received for that particular drilling partnership. As a result, the Company is subject to substantial cash commitments at the closing of each drilling partnership. The funds received from these programs are restricted to use in future drilling operations. While funds were received by the Company pursuant to drilling contracts in the years indicated, the Company recognizes revenues from drilling operations on the percentage of completion method as the wells are drilled, rather than when funds are received. All of the Company's drilling and development funds now are received from partnerships in which the Company serves as managing general partner. However, because wells produce for a number of years, the Company continues to serve as operator for a number of unaffiliated parties. In addition to the partnership structure, the Company also utilizes joint venture arrangements for financing drilling activities. +The financing process begins when the Company enters into a development agreement with an investor partner, pursuant to which the Company agrees to assign its rights in the property to be drilled to the partnership or other entity. The partnership or other entity thereby becomes owner of a working interest in the property. +The Company's development contracts with its investor partners have historically taken many different forms. Generally the agreements can be classified as on a "footage-based" rate, whereby the Company receives drilling and completion payments based on the depth of the well; "cost-plus," in which the Company is reimbursed for its actual cost of drilling plus some additional amount for overhead and profit; or "turnkey," in which a specified amount is paid for drilling and another amount for completion. The Company's development contracts may provide for a combination of several of the foregoing payment options. Basic drilling and completion operations are performed on a footage-based rate, with leases and gathering pipelines being contributed at Company cost. The Company may also purchase a working interest in the subject properties. +The level of the Company's drilling and development activity is dependent upon the amount of subscriptions in its public drilling partnerships and investments from other partnerships or other joint venture partners. The use of partnerships and similar financing structures enables the Company to diversify its holdings, thereby reducing the risks of its development investments. Additionally, the Company benefits through such arrangements by its receipt of fees for its management services and/or through an increased share in the revenues produced by the developed properties. The Company believes that investments in drilling activities, whether through Company-sponsored partnerships or other sources, are influenced in part by the favorable treatment that such investments enjoy under the federal income tax laws. No assurance can be given that the Company will continue to have access to funds generated through these financing vehicles. +Governmental Regulation +The Company's business and the natural gas industry in general are heavily regulated. The availability of a ready market for natural gas production depends on several factors beyond the Company's control. These factors include regulation of natural gas production, federal and state regulations governing environmental quality and pollution control, the amount of natural gas available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. State and federal regulations generally are intended to prevent waste of natural gas, protect rights to produce natural gas between owners in a common reservoir and control contamination of the environment. Pipelines are subject to the jurisdiction of various federal, state and local agencies. The Company takes the steps necessary to comply with applicable regulations both on its own behalf and as part of the services it provides to its investor partnerships. The Company believes that it is in substantial compliance with such statutes, rules, regulations and governmental orders, although there can be no assurance that this is or will remain the case. The following discussion of the regulation of the United States natural gas industry is not intended to constitute a complete discussion of the various statutes, rules, regulations and environmental orders to which the Company's operations may be subject. +-13- +Regulation of Oil and Natural Gas Exploration and Production +The Company's oil and natural gas operations are subject to various types of regulation at the federal, state and local levels. Prior to commencing drilling activities for a well, the Company must procure permits and/or approvals for the various stages of the drilling process from the applicable state and local agencies in the state in which the area to be drilled is located. Such permits and approvals include those for the drilling of wells, and such regulation includes maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties on which wells are drilled, the plugging and abandoning of wells and the disposal of fluids used in connection with operations. The Company's operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units and the density of wells which may be drilled and the unitization or pooling of natural gas properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely primarily or exclusively on voluntary pooling of lands and leases. In areas where pooling is voluntary, it may be more difficult to form units, and therefore, more difficult to develop a project if the operator owns less than 100% of the leasehold. In addition, state conservation laws may establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations may limit the amount of oil and natural gas the Company can produce from its wells and may limit the number of wells or the locations at which the Company can drill. The regulatory burden on the oil and natural gas industry increases the Company's costs of doing business and, consequently, affects its profitability. In as much as such laws and regulations are frequently expanded, amended and reinterpreted, the Company is unable to predict the future cost or impact of complying with such regulations. +Regulation of Sales and Transportation of Natural Gas +Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 (the "NGPA") and the regulations promulgated thereunder by the Federal Energy Regulatory Commission(FERC). Maximum selling prices of certain categories of natural gas sold in "first sales," whether sold in interstate or intrastate commerce, were regulated pursuant to the NGPA. The Natural Gas Wellhead Decontrol Act (the "Decontrol Act") removed, as of January 1, 1993, all remaining federal price controls from natural gas sold in "first sales" on or after that date. FERC's jurisdiction over natural gas transportation was unaffected by the Decontrol Act. While sales by producers of natural gas and all sales of crude oil, condensate and natural gas liquids can currently be made at market prices, Congress could reenact price controls in the future. +The Company's sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive regulation. In recent years, FERC has undertaken various initiatives to increase competition within the natural gas industry. As a result of initiatives like FERC Order No.636, issued in April 1992, the interstate natural gas transportation and marketing system has been substantially restructured to remove various barriers and practices that historically limited non-pipeline natural gas sellers, including producers, from effectively competing with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. The most significant provisions of Order No.636 require that interstate pipelines provide transportation separate or "unbundled" from their sales service, and require that pipelines provide firm and interruptible transportation service on an open access basis that is equal for all natural gas suppliers. In many instances, the result of Order No.636 and related initiatives have been to substantially reduce or eliminate the interstate pipelines' traditional role as wholesalers of natural gas in favor of providing only storage and transportation services. Another effect of regulatory restructuring is the greater transportation access available on interstate pipelines. In some cases, producers and marketers have benefited from this availability. However, competition among suppliers has greatly increased and traditional long-term producer-pipeline contracts are rare. Furthermore, gathering facilities of interstate pipelines are no longer regulated by FERC, thus allowing gatherers to charge higher gathering rates. +Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC, state commissions 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 FERC and Congress will continue. The Company cannot determine to what extent future operations and earnings of the Company will be affected by new legislation, new regulations, or changes in existing regulation, at federal, state or local levels. +-14- +Environmental Regulations +The Company's operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stricter environmental legislation and regulations could continue. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the natural gas industry in general, the business and prospects of the Company could be adversely affected. +The Company generates wastes that may be subject to the Federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes. The U.S. Environmental Protection Agency ("EPA") and various state agencies have limited the approved methods of disposal for certain hazardous and nonhazardous wastes. Furthermore, certain wastes generated by the Company's operations that are currently exempt from treatment as "hazardous wastes" may in the future be designated as "hazardous wastes," and therefore be subject to more rigorous and costly operating and disposal requirements. +The Company currently owns or leases numerous properties that for many years have been used for the exploration and production of oil and natural gas. Although the Company believes that it has utilized good operating and waste disposal practices, prior owners and operators of these properties may not have utilized similar practices, and hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by the Company or on or under locations where such wastes have been taken for disposal. These properties and the wastes disposed thereon may be subject to the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), RCRA and analogous state laws as well as state laws governing the management of oil and natural gas wastes. Under such laws, the Company 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) or to perform remedial plugging operations to prevent future contamination. +CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed of or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for release of 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, and 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. +The Company's operations may be subject to the Clean Air Act ("CAA") and comparable state and local requirements. Amendments to the CAA were adopted in 1990 and contain provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from the operations of the Company. The EPA and states have been developing regulations to implement these requirements. The Company may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues. +The Company's expenses relating to preserving the environment during 2003 were not significant in relation to operating costs and the Company expects no material change in 2004. Environmental regulations have had no materially adverse effect on the Company's operations to date, but no assurance can be given that environmental regulations will not, in the future, result in a curtailment of production or otherwise have a materially adverse effect on the Company's business, financial condition or results of operations. +-15- +Operating Hazards and Insurance +The Company's exploration and production operations include a variety of operating risks, including the risk of fire, explosions, blowouts, craterings, pipe failure, casing collapse, abnormally pressured formations, and environmental hazards such as gas leaks, ruptures and discharges of toxic gas, the occurrence of any of which could result in substantial losses to the Company due to injury and loss of life, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. The Company's pipeline, gathering and distribution operations are subject to the many hazards inherent in the natural gas industry. These hazards include damage to wells, pipelines and other related equipment, and surrounding properties caused by hurricanes, floods, fires and other acts of God, inadvertent damage from construction equipment, leakage of natural gas and other hydrocarbons, fires and explosions and other hazards that could also result in personal injury and loss of life, pollution and suspension of operations. +Any significant problems related to its facilities could adversely affect the Company's ability to conduct its operations. In accordance with customary industry practice, the Company maintains insurance against some, but not all, potential risks; however, there can be no assurance that such insurance will be adequate to cover any losses or exposure for liability. The occurrence of a significant event not fully insured against could materially adversely affect the Company's operations and financial condition. The Company cannot predict whether insurance will continue to be available at premium levels that justify its purchase or whether insurance will be available at all. +Competition +The Company believes that its exploration, drilling and production capabilities and the experience of its management and professional staff generally enable it to compete effectively. The Company encounters competition from numerous other oil and natural gas companies, drilling and income programs and partnerships in all areas of its operations, including drilling and marketing natural gas and obtaining desirable natural gas leases. Many of these competitors possess larger staffs and greater financial resources than the Company, which may enable them to identify and acquire desirable producing properties and drilling prospects more economically. The Company's ability to explore for oil and natural gas prospects and to acquire additional properties in the future depends upon its ability to conduct its operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. The Company competes with a number of other companies, which offer interests in drilling partnerships with a wide range of investment objectives and program structures. Competition for investment capital for both public and private drilling programs is intense. The Company also faces intense competition in the marketing of natural gas from competitors including other producers as well as marketing companies. Also, international developments and the possible improved economics of domestic natural gas exploration may influence other companies to increase their domestic oil and natural gas exploration. Furthermore, competition among companies for favorable prospects can be expected to continue, and it is anticipated that the cost of acquiring properties may increase in the future. Factors affecting competition in the natural gas industry include price, location, availability, quality and volume of natural gas. The Company believes that it can compete effectively in the oil and natural gas industry on each of the foregoing factors. Nevertheless, the Company's business, financial condition or results of operations could be materially adversely affected by competition. +Employees +As of December 31, 2003, the Company had 110 employees, including 17 in finance and data processing, 7 in administration, 11 in exploration and development, 70 in production and 5 in natural gas marketing. The Company's engineers, supervisors and well tenders are responsible for the day-to-day operation of wells and pipeline systems. In addition, the Company retains subcontractors to perform drilling, fracturing, logging, and pipeline construction functions at drilling sites. The Company's employees act as supervisors of the subcontractors. +The Company's employees are not covered by a collective bargaining agreement. The Company considers relations with its employees to be excellent. +-16- +Facilities +The Company owns and occupies three buildings in Bridgeport, West Virginia, two of which serve as the Company's headquarters and one which serves as a field operating site. The Company also owns a field operating building in Gilmer County, West Virginia. The Company leases field operating offices in Colorado, Michigan and Pennsylvania under operating leases. The Company has purchased a parcel of land in Greeley Colorado and will construct a field operating office during 2004. +Item 3. Legal Proceedings +From time to time the Company is a party to various legal proceedings in the ordinary course of business. The Company is not currently a party to any litigation that it believes would materially affect the Company's business, financial condition or results of operations. +Item 4. Submission of Matters to a Vote of Security Holders +No matters were submitted to a vote of security holders during the fourth quarter of the fiscal year covered by this report. +PART II +Item 5. Market for the Company's Common Stock and Related Stockholders Matters +The common stock of the Company is traded in the Nasdaq National Market under the symbol PETD. The following table sets forth, for the periods indicated, the high and low bid quotations per share of the Company's common stock in the over-the-counter market, as reported by Nasdaq. These quotations represent inter-dealer prices without retail markups, markdowns, commissions or other adjustments and may not represent actual transactions. +High +Low +2003 +First Quarter +$ 6.30 +$ 5.30 +Second Quarter +9.70 +6.16 +Third Quarter +12.33 +8.63 +Fourth Quarter +25.05 +12.09 +2002 +First Quarter +6.65 +5.70 +Second Quarter +6.66 +5.86 +Third Quarter +5.95 +4.60 +Fourth Quarter +5.70 +4.75 +As of December 31, 2003, there were approximately 1,177 record holders of the Company's common stock. +The Company has not paid any dividends on its common stock and currently intends to retain earnings for use in its business. Therefore, it does not expect to declare cash dividends in the foreseeable future. Further, the Company's Credit Agreement restricts the payment of dividends. +-17- +Item 6. Selected Condensed Financial Data (1) +Year Ended December 31, +2003 +2002 +2001 +2000 +1999 +Revenues +Oil and gas well +drilling operations +$71,841,500 +$57,149,100 +$76,291,200 +$43,194,700 +$42,115,600 +Oil and gas sales +120,162,700 +69,223,000 +92,095,300 +90,419,700 +46,988,100 +Well operations income +7,347,700 +6,116,200 +5,604,200 +5,061,600 +5,314,500 +Other income +3,499,100 +2,853,600 +3,132,400 +2,540,500 +2,392,400 +Total +$202,851,000 +$135,341,900 +$177,123,100 +$141,216,500 +$96,810,600 +Costs and Expenses (excluding +interest and depreciation, +depletion and amortization) +$152,445,000 +$108,816,600 +$144,468,600 +$118,813,300 +$82,496,500 +Interest Expense +$ 1,329,100 +$ 1,339,800 +$ 993,400 +$1,186,000 +$ 182,400 +Depreciation, depletion and +Amortization +$14,153,400 +$12,103,300 +$10,578,300 +$6,943,500 +$ 4,031,200 +Net Income +$22,619,100 +$ 9,284,800 +$14,967,800 +$10,681,000 +$ 7,824,300 +Basic earnings per common +Share +$1.45 +$.59 +$.92 +$.66 +$.50 +Diluted earnings per share +$1.39 +$.58 +$.90 +$.65 +$.48 +Average Common and Common +equivalent Shares Outstanding +during the Year +16,297,793 +16,143,414 +16,639,634 +16,437,488 +16,286,852 +December 31, +2003 +2002 +2001 +2000 +1999 +Total Assets +$306,722,000 +$212,251,600 +$199,852,100 +$187,684,500 +$132,083,600 +Working Capital +$ 6,230,700 +$ 1,770,500 +$ 3,419,600 +$ 780,700 +$ (2,503,900) +Long-Term Debt, excluding +current maturities +$ 53,000,000 +$ 25,000,000 +$ 28,000,000 +$ 17,350,000 +$ 9,300,000 +Stockholders' Equity +$123,604,600 +$101,122,200 +$ 96,772,800 +$ 82,256,900 +$70,724,900 +See Consolidated Financial Statements elsewhere herein. +-18- +Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations +Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995 +Statements, other than historical facts, contained in this Annual Report on Form 10-K, including statements of estimated oil and gas production and reserves, drilling plans, future cash flows, anticipated capital expenditures and Management's strategies, plans and objectives, are "forward looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Although the Company believes that its forward looking statements are based on reasonable assumptions, it cautions that such statements are subject to a wide range of risks and uncertainties incidental to the exploration for, acquisition, development and marketing of oil and gas, and it can give no assurance that its estimates and expectations will be realized. Important factors that could cause actual results to differ materially from the forward looking statements include, but are not limited to, changes in production volumes, worldwide demand, and commodity prices for petroleum natural resources; the timing and extent of the Company's success in discovering, acquiring, developing and producing oil and gas reserves; the Company's ability to acquire leases and drilling rigs at reasonable prices; risks incident to the drilling and operation of oil and gas wells; future production and development costs; the effect of existing and future laws, governmental regulations and the political and economic climate of the United States; the effect of hedging activities; and conditions in the capital markets. Other risk factors are discussed elsewhere in this Form 10-K. +Results of Operations +Management Overview +The strong market prices for oil and natural gas had a positive impact on many of the Company's operations. High prices directly increased revenue and profitability of sales of oil and gas from Company wells. News of higher oil and gas prices and improved results from prior programs also spurred a significant increase in sales of the Company sponsored drilling programs, and associated profits. To a lesser degree our well operations and gas marketing also benefited from higher prices. +Another major factor contributing to the Company's profitability was the acquisition of producing properties from Williams Company. The increase in production from the acquired properties and high gas prices added to the positive production and revenue numbers. +Year Ended December 31, 2003 Compared with December 31, 2002 +Revenues +Total revenues for the year ended December 31, 2003 were $202.9 million compared to $135.3 million for the year ended December 31, 2002, an increase of approximately $67.6 million, or 50.0 percent. Such increase was a result of increased drilling revenues, gas sales from gas marketing activities, oil and gas sales and well operations and pipeline income. +Drilling Revenue +Drilling revenues for the year ended December 31, 2003 were $71.8 million compared to $57.1 million for the year ended December 31, 2002, an increase of approximately $14.7 million or 25.7 percent. Such increase was due to the increased drilling funds raised through the Company's Public Drilling Programs. The four drilling programs of 2003 raised $78.3 million compared to $56.9 million in 2002. We believe this increase is fueled by the increase in oil and natural gas prices which has improved the performance of our prior programs which in turn has helped to increase our drilling program sales. +-19- +Natural Gas Marketing Activities +Natural gas sales from the marketing activities of Riley Natural Gas (RNG), the Company's marketing subsidiary for the year ended December 31, 2003 were $73.1 million compared to $46.4 million for the year ended December 31, 2002, an increase of approximately $26.7 million or 57.5 percent. Such increase was due to natural gas sold at significantly higher average sales prices offset in part by slightly lower volumes sold. +Oil and Gas Sales +Oil and gas sales from the Company's producing properties for the year ended December 31, 2003 were $47.0 million compared to $22.9 million for the year ended December 31, 2002, an increase of $24.1 million or 105.2 percent. The increase was due to significantly increased volumes sold at substantially higher average sales prices of oil and natural gas. The volume of natural gas sold for the year ended December 31, 2003 was 8.7 million Mcf at an average sales price of $4.42 per Mcf compared to 6.5 million Mcf at an average sales price of $2.68 per Mcf for the year ended December 31, 2002. Oil sales were 289,000 barrels at an average sales price of $29.39 per barrel for the year ended December 31, 2003 compared to 227,000 barrels at an average sales price of $24.41 per barrel for the year ended December 31, 2002. The increase in natural gas volumes was the result of the Company's increased investment in oil and gas properties, primarily the Williams property acquisition in the second quarter, recompletions of existing wells, two fourth quarter acquisitions of oil and gas properties in Colorado and Kansas and to a lesser extent the investment in oil and gas properties we own with our public drilling program partnerships. The table below outlines our increased production in Mcf equivalents of our 2003 recompletions and acquisitions by quarter. +Mcfe +1 st Quarter +2 nd Quarter +3 rd Quarter +4 th Quarter +Total +Recompletions +40,000 +161,000 +223,000 +285,000 +709,000 +Williams Acquisition +- +453,000 +573,000 +519,000 +1,545,000 +4 th Quarter Acquisitions +- +- +- +196,000 +196,000 +40,000 +614,000 +796,000 +1,000,000 +2,450,000 +Oil and Gas Production +The Company's oil and gas production by area of operations along with average sales price is presented below: +Year Ended December 31, 2003 +Year Ended December 31, 2002 +Natural +Natural Gas +Natural +Natural Gas +Oil +Gas +Equivalents +Oil +Gas +Equivalents +(Bbl) +(Mcf) +(Mcfe) +(Bbl) +(Mcf) +(Mcfe) +Appalachian Basin +3,992 +1,921,200 +1,945,152 +5,814 +2,095,903 +2,130,787 +Michigan Basin +6,627 +1,832,737 +1,872,499 +8,443 +2,146,101 +2,196,759 +Rocky Mountains +278,874 +4,958,245 +6,631,489 +212,779 +2,220,033 +3,496,707 +Total +289,493 +8,712,182 +10,449,140 +227,036 +6,462,037 +7,824,253 +Average Price +$29.39 +$4.42 +$4.50 +$24.41 +$2.68 +$2.92 +-20- +Financial results depend upon many factors, particularly the price of natural gas and our ability to market our production on economically attractive terms. Price volatility in the natural gas and oil markets has remained prevalent in the last few years and can have a material impact on our financial results. Natural gas prices declined dramatically at the end of 2001 and during the entire first quarter of 2002. However, in the second quarter of 2002, the Company saw a significant strengthening of natural gas prices in its Appalachian and Michigan producing areas. Natural gas prices in Colorado remained low for most of 2002. In the fourth quarter of 2002 and continuing in 2003, Colorado prices began to increase, although they continue to trail prices in other areas. The Company believes the lower prices in the Rocky Mountain Region, including Colorado, resulted from increasing local supplies that exceeded the local demand and pipeline capacity available to move gas from the region. On May 1st of 2003, the Kern River pipeline expansion was completed and placed into service. The Kern River Pipeline Company has announced that the additional facilities added about 900 million cubic feet per day of capacity for deliveries to Arizona, Nevada and southern California. This represents almost 30% of the prior pipeline capacity from the region to the West Coast and other markets outside the region. The Company believes that the completion and start-up of the pipeline eliminated or reduced the local supply surplus, leading to improved natural gas prices in the region. Since the startup of the new Kern River pipeline the Colorado Interstate Gas price index has improved to a range of from 83% to over 90% of the NYMEX price, levels consistent with historical price relationships before the recent local demand/pipeline capacity problem. The Company has commodity price hedging contracts for oil and natural gas production from January 2004 through October 2005 to protect against possible short-term price weaknesses. +Oil and Gas Hedging Activities +Because of uncertainty surrounding natural gas prices we have used various hedging instruments to manage some of the impact of fluctuations in prices. Through October of 2005 we have in place a series of floors and ceilings on part of our natural gas production. Under the arrangements, if the applicable index rises above the ceiling price, we pay the counterparty, however if the index drops below the floor the counterparty pays us. During the three months ended December 31, 2003 the Company averaged natural gas volumes sold of 857,000 Mcf per month and oil sales of 31,400 barrels per month. The current positions in effect on the Company's share of production are shown in the following table. +Floors +Ceilings +Month +Monthly Quantity +Mmbtu +Contract +Price +Monthly Quantity +Mmbtu +Contract +Price +NYMEX Based Hedges - (Appalachian and Michigan Basins) +Jan 2004 +114,000 +$4.45 +57,000 +$5.40 +Feb 2004 +114,000 +$4.30 +57,000 +$5.25 +Mar 2004 +114,000 +$4.20 +57,000 +$5.00 +Apr 2004 - Oct 2004 +81,000 +$4.00 +81,000 +$5.65 +Apr 2004 - Oct 2004* +122,000 +$5.00 +- +- +Apr 2005 - Oct 2005* +122,000 +$4.28 +61,000 +$5.00 +Colorado Interstate Gas (CIG) Based Hedges (Piceance Basin) +Jan 2004 - Mar 2004 +20,000 +$3.50 +20,000 +$5.25 +Apr 2004 - Oct 2004 +25,000 +$3.20 +25,000 +$4.70 +Apr 2004 - Oct 2004* +25,000 +$4.17 +- +- +Apr 2005- Oct 2005* +33,000 +$3.10 +16,000 +$4.43 +NYMEX Based Hedges (Williams acquisition) +Jan 2004 - Dec 2004 +150,000 +$4.50 +- +- +Apr 2005 - Oct 2005* +150,000 +$4.26 +75,000 +$5.00 +Oil hedges (Wattenberg Field) +Month +Monthly Quantity +Bbl +Contract +Price +Mar 2004 - Dec 2004* +10,000 +$31.60 +*Entered into during 2004 +-21- +Well Operations, Pipeline & Other Income +Well operations and pipeline income for the year ended December 31, 2003 was $7.3 million compared to $6.1 million for the year ended December 31, 2002, an increase of approximately $1.2 million or 19.7 percent. Such increase was due to an increase in the number of wells and pipeline systems operated by the Company for our Drilling Fund Partnerships as well as joint ventures. Other income for the year ended December 31, 2003 was $3.5 million compared to $2.9 million for the year ended December 31, 2002. Such increase was due to receiving the proceeds of $1.0 million in life insurance offset in part by a reduction in sales of miscellaneous items. +Costs and Expenses +Costs and expenses for the year ended December 31, 2003 were $167.9 million compared to $122.3 million for the year ended December 31, 2002, an increase of approximately $45.6 million or 37.3 percent. Such increase was primarily the result of increased cost of oil and gas well drilling operations, gas purchased for gas marketing activities, oil and gas production costs and depreciation, depletion and amortization. +Oil and Gas Well Drilling Costs +Oil and gas well drilling operations costs for the year ended December 31, 2003 were $61.3 million compared to $49.2 million for the year ended December 31, 2002, an increase of approximately $12.1 million or 24.6 percent. Such increase was due to the higher levels of drilling activity from our Public Drilling Programs referred to above. +Cost of Gas Marketing Activities +The cost of gas marketing activities for the year ended December 31, 2003 were $72.4 million compared to $46.2 million for the year ended December 31, 2002, an increase of $26.2 million or 56.7 percent. The increase was due to the significantly higher average prices of natural gas purchased and offset in part by slightly lower volumes purchased for resale. Income before income taxes for the Company's natural gas marketing subsidiary improved from $174,000 for the year ended December 31, 2002 to $689,000 for the year ended December 31, 2003. Based on the nature of the Company's gas marketing activities, hedging did not have a significant impact on the Company's net margins from marketing activities during either period. +Oil and Gas Production Costs +Oil and gas production costs from the Company's producing properties for the year ended December 31, 2003 were $13.7 million compared to $9.1 million for the year ended December 31, 2002, an increase of approximately $4.6 million or 50.5% percent. Such increase was due to the increased production costs and severance and property taxes on the increased volumes and higher sales prices of natural gas and oil sold, along with the increased number of wells and pipelines operated by the Company. Lifting cost per Mcfe increased from $.82 per Mcfe to $.98 per Mcfe which is almost entirely attributed to the increase in severance and property taxes on the significantly increased oil and gas sales prices. +General and Administrative Costs +General and administrative expenses for the year ended December 31, 2003 increased to $4.9 million compared with $4.4 million for the year ended December 31, 2002 an increase of approximately $500,000 or 11.4%, such increase was due to the increased administrative activity associated with a growing Company. +Depreciation, Depletion, and Amortization +Depreciation, depletion, and amortization costs for the year ended December 31, 2003 increased to $14.2 million from approximately $12.1 million for the year ended December 31, 2002, an increase of approximately $2.1 million or 17.4%. Such increase was due to the significantly increased production and investment in oil and gas properties by the Company as referred to above. +-22- +Interest Expense +Interest costs for the year ended December 31, 2003 and 2002 were $1.3 million. The lower average effective interest rates in 2003 more than offset the higher average borrowing levels the Company experienced during 2003, primarily a result of the oil and gas property acquisitions mentioned above. +Provision for Income Taxes +The effective income tax rate for the Company's provision for income taxes increased from 29% to 34.7% primarily as a result of the expired non-conventional source fuel tax credit and the effect of the federal rate change to 35% because of significantly increased earnings of the Company during 2003. +Change in Accounting Principle +The Company adopted SFAS No. 143 "Accounting for Asset Retirement Obligations" on January 1, 2003 and booked the cumulative effect on prior years of $198,600 (net of taxes of $121,700). +Net income and Earnings Per Share +Net income for the year ended December 31, 2003 was $22.6 million compared to a net income of $9.3 million for the year ended December 31, 2002, an increase of approximately $13.3 million or 143% percent. +Diluted earnings per share for the year ended December 31, 2003 was $1.39 per share compared to $.58 per share for the year ended December 31, 2002, an increase of $.81 per share or 139.7 percent. +Year Ended December 31, 2002 Compared with December 31, 2001 +Revenues. Total revenues for the year ended December 31, 2002 were $135.3 million compared to $177.1 million for the year ended December 31, 2001, a decrease of approximately $41.8 million or 23.6%. Such decrease was primarily a result of reduced drilling revenues, gas marketing activities and oil and gas sales. Drilling revenues for the year ended December 31, 2002 were $57.1 million compared to $76.3 million for the year ended December 31, 2001, a decrease of approximately $19.2 million or 25.2%. The decrease was a result of higher drilling activity carried over from the Company's public drilling programs at the end of 2000. The wells were drilled and completed during the first three quarters of 2001. The carryover resulted from a shortage of drilling rigs and field services during the second half of 2000 which delayed the drilling and completion of the wells which normally would have been drilled during the second half of 2000. Natural gas sales from the marketing activities of Riley Natural Gas (RNG), the Company's natural gas marketing subsidiary for the year ended December 31, 2002 was $46.4 million compared to $66.2 million for the year ended December 31, 2001, a decrease of approximately $19.8 million or 29.9%. Such decrease was due to natural gas sold at significantly lower average sales prices along with slightly lower volumes sold. Oil and gas sales from the Company's producing properties for the year ended December 31, 2002 were $22.9 million compared to $25.9 million for the year ended December 31, 2001, a decrease of approximately $3.0 million or 11.6%. Such decrease was due to lower average sales prices of natural gas offset in part by an increase in volumes produced and sold of natural gas and oil from the Company's producing properties. Financial results depend upon many factors, particularly the price of natural gas and our ability to market our production on economically attractive terms. Price volatility in the natural gas market has remained prevalent in the last few years. Natural gas prices declined dramatically at the end of the fourth quarter of 2001 and during the entire first quarter of 2002. However, in the second quarter of 2002, the Company saw a significant strengthening of natural gas prices in its Appalachian and Michigan producing areas. Natural gas prices in Colorado remained low for most of 2002. In the fourth quarter, Colorado prices began to increase, although they continue to trail prices in other areas by a greater than normal margin. The Company believes the low prices in the Rocky Mountain Region, including Colorado, result from increasing local supplies that exceed the local demand and pipeline capacity available to move gas from the region. In May of 2003, the Kern River Pipeline is scheduled to complete a capacity addition that will add about 900 million cubic feet of capacity for deliveries to Utah and southern California. This represents almost 30% of the current pipeline capacity from the region to the West Coast and other markets outside the region. The Company believes that the completion and start-up of the pipeline will eliminate or reduce the local supply surplus, leading to improved prices in the region compared to other producing areas. +-23- +If the pipeline is not completed on schedule, the price of natural gas in the Rocky Mountains is likely to continue to be discounted compared to other areas. If this occurs, the Company's oil and gas sales in 2003 will be lower than they might otherwise be, and the sales of the Company's drilling programs, which focus on Colorado development, could be adversely impacted. Beginning in the second quarter and continuing later in the year, the Company entered into some commodity price hedging contracts for production from May 2002 through October 2003 to protect ourselves against possible short-term price weaknesses. Well operations and pipeline income for the year ended December 31, 2002 was $6.1 million compared to $5.6 million for the year ended December 31, 2001, an increase of approximately $500,000 or 8.9%. Such increase was due to an increase in the number of wells and pipelines operated by the Company. Other income for the year ended December 31, 2002 was $2.9 million compared to $3.1 million for the year ended December 31, 2001, a decrease of approximately $200,000 or 6.5%. +Costs and expenses. Costs and expenses for the year ended December 31, 2002 were $122.3 million compared to $156.0 million for the year ended December 31, 2001, a decrease of approximately $33.7 million, or 21.6%. Oil and gas well drilling operations costs for the year ended December 31, 2002 were $49.2 million compared to $66.0 million for the year ended December 31, 2001, a decrease of approximately $16.8 million or 25.5%. Such decrease was due to the reduced drilling activity referred to above. The costs of gas marketing activities of RNG for the year ended December 31, 2002 were $46.2 million compared to $65.7 million for the year ended December 31, 2001, a decrease of $19.5 million or 29.7%. Such decrease was due to lower average prices of natural gas purchased for resale and slightly lower volumes purchased. Based on the nature of RNG's gas marketing activities, hedging did not have a significant impact on RNG's net margins from marketing activities during either period. Oil and gas production costs from the Company's producing properties for the year ended December 31, 2002 were $9.1 million compared to $8.6 million for the year ended December 31, 2001 an increase of approximately $500,000 or 5.8%. Such increase was due to the increased sales volumes from the Company's oil and gas producing properties and increased number of wells operated by the Company. General and administrative expenses for the year ended December 31, 2002 were $4.4 million compared to $4.1 million for the year ended December 31, 2001, an increase of approximately $300,000. Depreciation, depletion and amortization costs for the year ended December 31, 2002 were $12.1 million compared to $10.6 million for the year ended December 31, 2001, an increase of approximately $1.5 million or 14.2%. Such increase was due to the increased amount of production and investment in oil and gas properties owned by the Company. Interest costs for the year ended December 31, 2002 were $1.3 million compared to $1.0 million for the year ended December 31, 2001 an increase of approximately $300,000. Such increase was due to higher average debt balances offset in part by lower average interest rates. +Net income. Net income for the year ended December 31, 2002 was $9.3 million compared to $15.0 million for the year ended December 31, 2001, a decrease of approximately $5.7 million or 38.0%. +Liquidity and Capital Resources +The Company funds its operations through a combination of cash flow from operations, capital raised through drilling partnerships, and use of the Company's credit facility. Operational cash flow is generated by sales of natural gas and oil from the Company's well interests, natural gas marketing, well drilling and operating activities from the Company's public drilling programs, and natural gas gathering and transportation. Cash payments from Company-sponsored partnerships are used to drill and complete wells for the partnerships, with operating cash flow accruing to the Company to the extent payments exceed drilling costs. The Company utilizes its revolving credit arrangement to meet the cash flow requirements of its operating and investment activities. +Natural Gas Pricing and Pipeline Capacity +Natural gas and oil prices have been unusually volatile for the past few years, and the Company anticipates continued volatility in the future. Currently, the NYMEX futures reflect a market expectation of gas prices at Henry Hub close to or above record prices per million Btu's (Mmbtu). These prices look strong for 2004 although natural gas storage levels are near normal levels following a period when storage levels had been at a five-year low. The Company believes this situation creates the possibility of both periods of low prices and continued high prices. +-24- +Natural gas prices declined dramatically at the end of 2001 and during the entire first quarter of 2002. However, in the second quarter of 2002, the Company saw a significant strengthening of natural gas prices in its Appalachian and Michigan producing areas. Natural gas prices in Colorado remained low for most of 2002. In the fourth quarter of 2002 and continuing in 2003, Colorado prices began to increase, although they continue to trail prices in other areas. The Company believes the lower prices in the Rocky Mountain Region, including Colorado, resulted from increasing local supplies that exceeded the local demand and pipeline capacity available to move gas from the region. On May 1st of 2003, the Kern River pipeline expansion was completed and placed into service. The Kern River Pipeline Company has announced that the additional facilities added about 900 million cubic feet per day of capacity for deliveries to Arizona, Nevada and southern California. This represents almost 30% of the prior pipeline capacity from the region to the West Coast and other markets outside the region. The Company believes that the completion and start-up of the pipeline eliminated or reduced the local supply surplus, leading to improved natural gas prices in the region. Since the startup of the new Kern River pipeline the Colorado Interstate Gas price index has improved to a range of from 83% to over 90% of the NYMEX price, levels consistent with historical price relationships before the recent local demand/pipeline capacity problem. +Oil and Gas Hedging Activities +Because of the uncertainty surrounding natural gas and oil prices we have used various hedging instruments to manage some of the impact of fluctuations in prices. Through October of 2005 we have in place a series of floors and ceilings on part of our natural gas production. Under the arrangements, if the applicable index rises above the ceiling price, we pay the counterparty, however if the index drops below the floor the counterparty pays us. See previous pages in this Management's Discussion and Analysis for a schedule of hedging positions. +The Company hedges prices for its partners' share of production as well as its own production. Actual wellhead prices will vary based on local contract conditions, gathering and other costs and factors. +Oil Pricing +Oil prices have strengthened since the middle of 2003. While oil prices are influenced by supply and demand, global geopolitics may be the single most important determinant. Since the percentage of the Company's production reflected by oil sales has increased to 17%, variations in oil prices will have a greater impact on the Company than in the past. The Company also has in place hedges on 10,000 barrels a month for its Wattenburg Field oil production for the period from March 2004 through December 2004 at a price of $31.60 per barrel. +Public Drilling Programs +The Company closed four public drilling partnerships during 2003. The total amount received during 2003 was $78.3 million compared to $56.9 million for 2002. The Company closed its fourth program of 2003 on December 15, 2003 in the amount of $35.0 million and will drill the wells during the first quarter of 2004. The last three drilling partnerships of 2003 closed at their maximum allowable subscriptions, earlier than the scheduled close. The result of these maximum closings is that the Company has a drilling carryover to 2004 of $50.5 million compared with $37.3 million at the end of 2002. The response to the Company's first program of 2004 is strong. It is scheduled to close on April 30, 2004, its maximum allowable subscriptions is $30.0 million. Additional programs are scheduled to close in August, October and December of 2004. The Company invests, as its equity contribution to each drilling partnership, an additional sum of 21.75% of the aggregate subscriptions received for that particular drilling partnership. As a result, the Company is subject to substantial cash commitments at the closing of each drilling partnership. No assurance can be made that the Company will continue to receive this level of funding from these or future programs. +-25- +Substantially all of the Company's drilling programs contain a repurchase provision where Investors may request the Company to repurchase their partnership units at any time beginning with the third anniversary of the first cash distribution. The provision provides that the Company is obligated to purchase an aggregate of 10% of the initial subscriptions per calendar year (at a minimum price of four times the most recent 12 months' cash distributions), only if investors request the Company to repurchase such units subject to the Company's financial ability to do so. The maximum annual 10% repurchase obligation, if requested by the investors, is currently approximately $4.8 million. The Company has adequate liquidity to meet this obligation. During 2003 the Company has spent $266,500 under this provision. +Acquisition of Oil and Gas Properties +During the second quarter of 2003, the Company purchased 166 wells in the Denver Julesburg Basin in northeastern Colorado from Williams Production RMT Company for $28 million. The Company estimates the acquisition included approximately 22.6 billion cubic feet (Bcf) of proved developed producing (PDP) and 3.4 Bcf of proved developed non-producing reserves (PDNP), all of which is natural gas. +During the fourth quarter of 2003, the Company purchased from one of its joint venture partners in the Denver-Julesburg Basin in Weld County, Colorado approximately 3.1 billion cubic feet equivalent (Bcfe) of proved developed producing reserves from interests in 20.6 net wells (230 gross) and 1.8 Bcfe of proved developed non-producing reserves from interests in 17 net wells (183 gross). The purchase price was $5.2 million. +During the fourth quarter of 2003, the Company purchased 97 gross wells (73 net) wells in the Denver-Julesburg Basin located in northeast Colorado and northwestern Kansas for $6.0 million. This purchase adds approximately 4.5 billion cubic feet equivalent (Bcfe) of proved developed producing and proved developed non-producing reserves to the Company's oil and gas reserves along with 100,000 acres of oil and gas leases. The Company funded the above acquisitions through its bank credit facility. +Costs incurred by the Company in oil and gas acquisitions, exploration and development for the year ended December 31, 2003 are presented below: +Property acquisition cost: +Proved undeveloped properties +$ 6,167,800 +Producing properties +33,946,600 +Development costs +30,630,100 +$70,744,500 +Common Stock Repurchase +On March 13, 2003 the Company publicly announced a common stock repurchase program to repurchase up to 5% of the Company's outstanding common stock (785,000 shares) expiring on December 31, 2004. From inception of the program until December 31, 2003, the Company has repurchased 109,200 shares at an average price of $6.86 per share. The Company intends to fund this repurchase of common stock through internally generated cash flow. +Long-Term Debt +The Company has a credit facility with Bank One, NA and BNP Paribas of $100 million subject to adequate oil and natural gas reserves. The current borrowing base is $80.0 million, of which the Company has activated $60.0 million of the facility. As of December 31, 2003, the outstanding balance on the line of credit was $53.0 million of which $10.0 million was subject to an interest rate swap at a rate of 8.39% , $15.0 million was subject to a 90-day LIBOR rate of 2.87%, $5.0 million subject to a 30-day LIBOR rate of 2.92% and the remaining $23.0 million was subject to a prime rate of 4.00%. The line of credit is at prime, with LIBOR alternatives available at the discretion of the Company. No principal payments are required until the credit agreement expires on July 3, 2005. The Company anticipates extending the expiration date during the first half of 2004. +-26- +Contractual Obligations +Contractual obligations and due dates are as follows: +Payments due by period +Contractual Obligations +Total +Less than +1 year +1-3 +years +3-5 +years +More than +5 years +Long-Term Debt +$53,000,000 +- +$53,000,000 +- +- +Operating Leases +833,200 +$366,300 +308,300 +$158,600 +- +Asset Retirement Obligation +731,200 +- +50,000 +50,000 +$631,200 +Other Liabilities +2,449,100 +100,000 +250,000 +250,000 +1,849,100 +Total +$57,013,500 +$466,300 +$53,608,300 +$458,600 +$2,480,300 +The Company continues to pursue capital investment opportunities in producing natural gas properties as well as its plan to participate in its sponsored natural gas drilling partnerships, while pursuing opportunities for operating improvements and costs efficiencies. Management believes that the Company has adequate capital to meet its operating requirements. +Commitments and Contingencies +As Managing General Partner of 10 private partnership and 58 public partnerships (See Item 2. Properties - Financing of Drilling Activities) the Company has liability for any potential casualty losses in excess of the partnership assets and insurance. The Company believes its and its subcontractors casualty insurance coverage is adequate to meet this potential liability. +Critical Accounting Policies and Estimates +We have identified the following policies as critical to our business operations and the understanding of our results of operations. This listing is not a comprehensive list of all of our accounting policies. In many cases, the accounting treatment of a particular transaction is specifically dictated by accounting principles generally accepted in the United States, with no need for management's judgment in their application. There are also areas in which management's judgment in selecting any available alternative would not produce a materially different result. However, certain of our accounting policies are particularly important to the portrayal of our financial position and results of operations and may require the application of significant judgment by our management; as a result, they are subject to an inherent degree of uncertainty. In applying those policies, our management uses its judgment to determine the appropriate assumptions to be used in the determination of certain estimates. Those estimates are based on our historical experience, our observance of trends in the industry, and information available from other outside sources, as appropriate. For a more detailed discussion on the application of these and other accounting policies, see "Note 1 - Summary of significant account policies" in our financial statements and related notes. Our critical accounting policies and estimates are as follows: +Revenue Recognition +Oil and gas wells are drilled primarily on a contract basis. The Company follows the percentage-of-completion method of income recognition for drilling operations in progress. +Sales of natural gas are recognized when sold, oil revenues are recognized when produced into a stock tank. +Well operations and pipeline income consists of operation charges for well upkeep, maintenance, transportation of natural gas and operating lease income on tangible well equipment. +Valuation of Accounts Receivable +Management reviews accounts receivable to determine which are doubtful of collection. In making the determination of the appropriate allowance for doubtful accounts, management considers the Company's history of write-offs, relationships and overall credit worthiness of its customers, and well production data for receivables related to well operations. +-27- +Accounting for Derivatives Contracts at Fair Value +The Company uses derivative instruments to manage its commodity and financial market risks. Accounting requirements for derivatives and hedging activities are complex; interpretation of these requirements by standard-setting bodies is ongoing. +Derivatives are reported on the Consolidated Balance Sheets at fair value. Changes in fair value of derivatives that are not designated as accounting hedges are recorded in earnings. +The measurement of fair value is based on actively quoted market prices, if available. Otherwise, the Company seeks indicative price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available, measurement involves judgment and estimates. These estimates are based on valuation methodologies considered appropriate by the Company's management. +For individual contracts, the use of different assumptions could have a material effect on the contract's estimated fair value. In addition, for hedges of forecasted transactions, the Company must estimate the expected future cash flows of the forecasted transactions, as well as evaluate the probability of the occurrence and timing of such transactions. Changes in conditions or the occurrence of unforeseen events could affect the timing of recognition in earnings for changes in fair value of certain hedging derivatives. +Use of Estimates in Long-Lived Asset Impairment Testing +Exploration and development costs are accounted for by the successful efforts method. +Impairment testing for long-lived assets and intangible assets with definite lives is required when circumstances indicate those assets may be impaired. In performing the impairment test, the Company would estimate the future cash flows associated with individual assets or groups of assets. Impairment must be recognized when the undiscounted estimated future cash flows are less than the related asset's carrying amount. In those circumstances, the asset must be written down to its fair value, which, in the absence of market price information, may be estimated as the present value of its expected future net cash flows, using an appropriate discount rate. Although cash flow estimates used by the Company are based on the relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results. +Unproved properties or leases are written-off to expense when it is determined that they will expire or be abandoned. +Deferred Tax Asset Valuation Allowance +Deferred tax assets are recognized for deductible temporary differences, net operating loss carryforwards, and credit carryforwards if it is more likely than not that the tax benefits will be realized. To the extent a deferred tax asset cannot be recognized under the preceding criteria, a valuation allowance has been established. +The judgments used in applying the above policies are based on management's evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results may differ from those estimates. See additional discussions in this Management's Discussion and Analysis. +New Accounting Standards +In June 2001, the Financial Accounting Standard Board issued SFAS No. 143, "Accounting for Asset Retirement Obligations" that requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. This statement is effective for fiscal years beginning after June 15, 2002. The Company adopted SFAS No. 143 on January 1, 2003 and recorded a net asset of $271,800 and a related liability of $592,100 (using a 6% discount rate) and a cumulative effect on change in accounting principle on prior years of $198,600 (net of taxes of $121,700). +-28- +In December 2002, the FASB issued SFAS 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 123 to require prominent disclosures in both annual and interim financial statements. Disclosures required by this standard are included in the notes to these financial statements. +A reporting issue has arisen regarding the application of certain provisions of SFAS No. 141 and SFAS no. 142 to companies in the extractive industries, including oil and gas companies. The issue is whether SFAS No. 142 requires registrants to classify the costs of mineral rights (leases) associated with extracting oil and gas intangible assets in the balance sheets, apart from other capitalized oil and gas property costs, and provide specific footnote disclosures. Historically, the Company has included the costs of mineral rights associated with extracting oil and gas as a component of oil and gas properties. If it is ultimately determined that SFAS No. 142 requires oil and gas companies to classify costs of mineral rights associated with extracting oil and gas as a separate intangible assets line item on the balance sheet, the Company would be required to reclassify the historical cost of approximately $7,576,900 and $4,208,800 of mineral rights associated with undeveloped oil and gas properties and $15,485,500 and $10,898,700 of mineral rights associated with developed oil and gas properties as of December 31, 2003 and December 31, 2002, respectively, out of oil and gas properties and into a separate intangible mineral rights assets line item. The Company's total balance sheet, cash flows and results of operations would be not affected since such intangible assets would continue to be amortized and assessed for impairment. +Item 7A. Quantitative and Qualitative Disclosure About Market Risk . +Market-Sensitive Instruments and Risk Management +The Company's primary market risk exposures are interest rate risk and commodity price risk. These exposures are discussed in detail below: +Interest Rate Risk +The Company's exposure to market risk for changes in interest rates relates primarily to the Company's interest-bearing cash and cash equivalents and long-term debt. Interest-bearing cash and cash equivalents includes money market funds, certificates of deposit and checking and savings accounts with various banks. The amount of interest-bearing cash and cash equivalents as of December 31, 2003 is $85,184,700 with an average interest rate of 0.57%. As of December 31, 2003, the Company has long-term debt of $53,000,000 of which $10,000,000 is subject to an interest rate swap at a rate of 8.39%, $15,000,000 subject to a 90-day LIBOR rate of 2.87%, $5,000,000 was subject to a 30-day LIBOR rate of 2.92% and $23,000,000 was subject to a prime rate of 4.00%. +Commodity Price Risk +The Company utilizes commodity-based derivative instruments as hedges to manage a portion of its exposure to price risk from its natural gas sales and marketing activities. These instruments consist of NYMEX-traded natural gas futures contracts and option contracts for Appalachian and Michigan production and CIG-based contracts traded by Bank One for Colorado production. These hedging arrangements have the effect of locking in for specified periods (at predetermined prices or ranges of prices) the prices the Company will receive for the volume to which the hedge relates and, in the case of RNG, the cost of gas supplies purchased for marketing activities. As a result, while these hedging arrangements are structured to reduce the Company's exposure to changes in price associated with the hedged commodity, they also limit the benefit the Company might otherwise have received from price changes associated with the hedged commodity. The Company's policy prohibits the use of natural gas future and option contracts for speculative purposes. +-29- +As of December 31, 2003 RNG had entered into a series of natural gas future contracts stemming from its marketing activities. Total open futures contracts are for the sale of 2,660,000 Mmbtu of natural gas with a weighted average price of $4.58 Mmbtu resulting in a total contract amount of $12,174,100 and a fair market value of $(1,810,500) and for the purchase of 820,000 Mmbtu of natural gas with a weighted average price of $5.17 Mmbtu resulting in a total contract amount of $4,243,400 and a fair market value of $270,200. Open future contracts maturing in 2004 are for the sale of 2,060,000 mmbtu of natural gas with a weighted average price of $4.66 mmbtu resulting in a total contract amount of $9,594,200 and a fair market value of $(1,562,100) and for the purchase of 820,000 mmbtu of natural gas with a weighted average price of $5.17 mmbtu resulting in a total contract amount of $4,243,400 and a fair market value of $270,200. The maximum term over which RNG is hedging exposure to the variability of cash flows for commodity price risk is 25 months. There were no open option contracts stemming from RNG's marketing activities as of December 31, 2003. As of December 31, 2002, RNG had entered into a series of natural gas future contracts and option contracts stemming from its marketing activities. Open future contracts as of December 31, 2002 that matured in 2003 were for the sale of 3,210,000 mmbtu of natural gas with a weighted average price of $3.18 Mmbtu resulting in a total contract amount of $12,728,100 and a fair market value of $(1,912,200). +As of December 31, 2003, PDC had entered into a series of natural gas future contracts and option contracts stemming from its natural gas production. Open future contracts maturing in 2004 are for the sale of 53,300 Mmbtu of natural gas with a weighted average price of $5.40 Mmbtu resulting in a total contract amount of $288,000 and a fair market value of $(40,000) and for the purchase of 45,700 Mmbtu of natural gas with a weighted average price of $4.77 resulting in a total contract amount of $218,100 and a fair value of $30,400. Open option contracts maturing in 2004 are for the sale of 2,597,800 Mmbtu with a weighted average floor price of $4.29 Mmbtu and a fair value of $185,300 and 691,200 Mmbtu with a weighted average ceiling price of $5.23 Mmbtu and a fair value of $(127,800). The maximum term over which PDC is hedging exposure to variability of cash flows for commodity price risk is 12 months. As of December 31, 2002, PDC had entered into a series of natural gas future contracts and option contracts stemming from its natural gas production. Open future contracts as of December 31, 2002 that matured in 2003 were for the sale of 280,000 mmbtu of natural gas with a weighted average price of $4.25 mmbtu resulting in a total contract amount of $1,190,000 and a fair market value of $(209,700). Open option contracts as of December 31, 2002 that matured in 2003 were for the sale of 2,155,600 mmbtu with a weighted average floor price of $3.15 mmbtu and a fair value of $105,600 and 794,800 mmbtu with a weighted average ceiling price of $3.80 mmbtu and a fair value of $(442,800). +The average NYMEX closing price for natural gas for the years 2003, 2002 and 2001 was $5.39 Mmbtu, $3.22 Mmbtu, and $4.27 Mmbtu. The average NYMEX closing price for oil for the years 2003, 2002 and 2001 was $30.98 bbl, $26.98 bbl and $26.60 bbl. Future near-term gas prices will be affected by various supply and demand factors such as weather, government and environmental regulation and new drilling activities within the industry. +Disclosure of Limitations +As the information above incorporates only those exposures that exist at December 31, 2003, it does not consider those exposures or positions which could arise after that date. As a result, the Company's ultimate realized gain or loss with respect to interest rate and commodity price fluctuations will depend on the exposures that arise during the period, the Company's hedging strategies at the time, and interest rates and commodity prices at the time. +Item 8. Financial Statements and Supplementary Data: +The response to this Item is set forth herein in a separate section of this Report, beginning on Page F-1. +Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. +None. +-30- +Item 9A Controls and Procedures +Under the supervision and with the participation of the Company's management, including the Company's Chief Executive Officer and Chief Financial Officer, the Company has evaluated the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Exchange Act Rule 13a-14(c)) as of the end of the period covered by this annual report on Form 10-K, and, based on their evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these disclosure controls and procedures are effective in all material respects, including those to ensure that information required to be disclosed in reports filed or submitted under the Securities Exchange Act is recorded, processed, summarized, and reported, within the time periods specified in the Commission's rules and forms, and is accumulated and communicated to management, including the Company's Chief Executive Officer and Chief Financial Officer, as appropriate to allow for timely disclosure. There have been no significant changes in our internal controls or in other factors that could significantly affect these controls in the fourth quarter and subsequent to the date of their evaluation. +PART III +Item 10. Directors and Executive Officers of the Company +Directors and Executive Officers of the Company +The executive officers and directors of the Company, their principal occupations for the past five years and additional information are set forth below: +Name +Age +Positions and Offices Held +Held Current +Position Since +Steven R. Williams +52 +Chairman, Chief Executive Officer, +President and Director +January 2004 +March 1983 +Darwin L. Stump +48 +Chief Financial Officer and Treasurer +November 2003 +Thomas E. Riley +51 +Executive Vice President Production, Natural Gas +Marketing and Business Development, and Director +November 2003 +Eric R. Stearns +46 +Executive Vice President Exploration and Development +November 2003 +Roger J. Morgan +76 +Secretary +November 1969 +Vincent F. D'Annunzio +51 +Director +February 1989 +Jeffrey C. Swoveland +48 +Director +March 1991 +Donald B. Nestor +55 +Director +March 2000 +Kimberly Luff Wakim +45 +Director +January 2003 +David C. Parke +37 +Director +November 2003 +Steven R. Williams was elected Chairman and Chief Executive Officer in January 2004. Mr. Williams has served as President and Director of PDC since March 1983. Prior to joining PDC, Mr. Williams was employed by Exxon until 1979 and attended Stanford Graduate School of Business, graduating in 1981. He then worked with Texas Oil and Gas until July 1982, when he joined Exco Enterprises, an oil and gas investment company as manager of operations. +Darwin L. Stump was appointed Chief Financial Officer and Treasurer in November 2003. Mr. Stump has been an officer of the Company since April 1995 and held the position of Corporate Controller since 1980. Mr. Stump, a CPA, was a senior accountant with Main Hurdman, Certified Public Accountants prior to joining PDC. +Thomas E. Riley was elected Director in January 2004 by the Board of Directors and appointed Executive Vice President of Production, Natural Gas Marketing and Business Development in November 2003. Prior thereto, Mr. Riley served as Vice President Gas Marketing and Acquisitions of PDC since April 1996. Prior to joining PDC, Mr. Riley was president of Riley Natural Gas Company, a natural gas marketing company which PDC acquired in April 1996. +-31- +Eric R. Stearns was appointed Executive Vice President of Exploration and Development in November 2003. Prior thereto, Mr. Stearns was Vice President of Exploration and Development since April 1995. Mr. Stearns joined PDC as a geologist in 1985 after working for Hywell, Incorporated and for Petroleum Consultants. +Roger J. Morgan has been a member of the law firm of Young, Morgan & Cann, Clarksburg, West Virginia since 1955. Mr. Morgan is not active in the day-to-day business of PDC, but his law firm provides legal services to PDC. +Vincent F. D'Annunzio has served as president of Beverage Distributors, Inc. located in Clarksburg, West Virginia since 1985. +Jeffrey C. Swoveland has served as Chief Financial Officer of Body Media since September, 2000. Prior thereto, Mr. Swoveland was Vice President-Finance and Treasurer of Equitable Resources Inc since 1994. +Donald B. Nestor, is a Certified Public Accountant and a Partner in the CPA firm of Toothman Rice, P.L.L.C. and is in charge of the firm's Buckhannon, West Virginia office. Mr. Nestor has served in that capacity since 1975. +Kimberly Luff Wakim, an Attorney and Certified Public Accountant, is a Partner with the law firm Thorp, Reed & Armstrong LLP. Ms. Wakim joined Thorp Reed & Armstrong LLP in 1990. +David C. Parke was elected Director by the Board of Directors in November 2003. In 2003, Mr. Parke joined Mufson/Howe/Hunter & Company LLC, an investment banking firm as a founder and Director. From 1992-2003, Mr. Parke was with the corporate finance department of Investec, Inc. and its predecessor Pennsylvania Merchant Group Ltd., investment banking companies. Prior to joining Pennsylvania Merchant Group, Mr. Parke served in the corporate finance departments of Wheat First Butcher & Singer, now part of Wachovia Securities, and Legg Mason, Inc. +The Company's By-Laws provide that the directors of the Company shall be divided into three classes and that, at each annual meeting of stockholders of the Company, successors to the class of directors whose term expires at the annual meeting will be elected for a three-year term. The classes are staggered so that the term of one class expires each year. Mr. D'Annunzio is a member of the class whose term expires in 2004; Mr. Parke and Mr. Riley were elected by the Board to fulfill unexpired terms that expire in 2004. Mr. Swoveland is a member of the class whose term expires in 2005. Mr. Williams, Mr. Nestor and Ms. Wakim are members of the class whose term expires in 2006. There is no family relationship between any director or executive officer and any other director or executive officer of the Company. There are no arrangements or understandings between any director or officer and any other person pursuant to which such person was selected as an officer. +On January 24, 2003, the Company adopted a Code of Business Conduct and Ethics Policy meeting the specified standards applicable to the Chief Executive Officer and Chief Financial Officer. The policy also covers all the corporate officers. The policy is posted on the Company's website at www.petd.com. +The Audit Committee of the Board of Directors is comprised entirely of independent directors as defined by the NASDAQ rule 4200(a)(15). Donald B. Nestor, CPA, a partner in the certified public accounting firm of Toothman Rice PLLC, chairs the committee. Mr. Nestor and the other audit committee members, qualify as audit committee financial experts and are independent of management. +The Nominating and Governance and Compensation Committees are also comprised entirely of independent directors of the Company. Vincent F. D'Annunzio chairs the Nominating and Governance Committee, and Jeffrey C. Swoveland chairs the Compensation Committee. +Shareholders wishing to communicate with the Board of Directors or a committee may do so by writing to the attention of the Board or Committee at the corporate headquarters or by emailing the Board at board@petd.com, with "Board" or appropriate committee in the subject line. +-32- +Item 11. Executive Compensation +There is incorporated by reference herein in response to this Item the material under the heading "Election of Directors - Remuneration of Directors and Officers", "Election of Directors - Stock Options" and "Election of Directors - Interest of Management in Certain Transactions" in the Company's definitive proxy statement for its 2004 annual meeting of stockholders filed or to be filed with the Commission on or before April 30, 2004. +Item 12. Security Ownership of Certain Beneficial Owners, Management and Related Stockholder Matters +There is incorporated by reference herein in response to this Item, the material under the heading "Election of Directors", in the Company's definitive proxy statement for its 2004 annual meeting of stockholders filed or to be filed with the Commission on or before April 30, 2004. +The Company has the following common stock options outstanding under the stock option plans approved by the stockholders: +Equity Compensation Plan Information +December 31, 2003 +Plan Category +Number of securities to +be issued upon exercise +of outstanding options, +warrants and rights +(a) +Weighted-average +exercise price of +outstanding options, +warrants and rights +(b) +Number of securities +remaining available for +future issuance under +equity compensation plans +(excluding securities +reflected in column (a)) +(c) +Equity compensation plans +approved by security holders +1,160,000 shares +$4.48 +- +Equity compensation plans not +approved by security holders +- +- +- +Total +1,160,000 shares +$4.48 +- +Item 13. Certain Relationships and Related Transactions +The response to this item is set forth herein in Note 8 in the Notes to Consolidated Financial Statements and under "Election of Directors - Interest of Management in Certain Transactions," in the Company's definitive proxy statement for its 2004 annual meeting of stockholders filed or to be filed with the Commission on or before April 30, 2004. +Item 14. Principal Accounting Fees and Services +The information under the caption "Fees Billed by Independent Public Accountants for Services in 2003 and 2002" in the Company's definitive Proxy Statement in connection with the 2004 annual stockholders' meeting is incorporated by reference. +Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K +(a) (1) Financial Statements: +See Index to Financial Statements and Schedules on page F-1. +(2) Financial Statement Schedules: +See Index to Financial Statements and Schedules on page F-1. +Schedules and Financial Statements Omitted +All other financial statement schedules are omitted because they are not required, inapplicable, or the information is included in the Financial Statements or Notes thereto. +(3) Exhibits: +See Exhibits Index on page E-1. +-33- +CONFORMED COPY +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. +PETROLEUM DEVELOPMENT CORPORATION +By /s/ Steven R. Williams +Steven R. Williams, Chairman +March 2, 2004 +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/ Steven R. Williams +Steven R. Williams +Chairman, Chief Executive Officer, President and +Director +March 2, 2004 +/s/ Darwin L. Stump +Darwin L. Stump +Chief Financial Officer and Treasurer +(principal financial and accounting officer) +March 2, 2004 +/s/ Thomas E. Riley +Thomas E. Riley +Executive Vice President of Production , Natural +Gas Marketing and Business Development and +Director +March 2, 2004 +/s/ Donald B. Nestor +Donald B. Nestor +Director, Chairman of Audit Committee +March 2, 2004 +/s/ Vincent F. D'Annunzio +Vincent F. D'Annunzio +Director +March 2, 2004 +/s/ Jeffrey C. Swoveland +Jeffrey C. Swoveland +Director +March 2, 2004 +/s/ Kimberly Luff Wakim +Kimberly Luff Wakim +Director +March 2, 2004 +/s/ David C. Parke +David C. Parke +Director +March 2, 2004 +-34- +Exhibits Index +(a) Exhibitis +Exhibit Name +Exhibit +Number +Location +Articles of Incorporation +3.1 +Incorporated by reference to Exhibit 3.1 to Form S-2 SEC File No. 333-36369 filed on September 25, 1997 +By Laws +3.2 +Incorporated by reference to Exhibit 3.2 to Form 8-K SEC File No. 0-07246 filed on January 24, 2003 +Credit Agreement, dated as of July 3, 2002 by and between Petroleum Development Corporation and the lenders, Bank One N.A. and BNP Paribas +10.1 +Incorporated by reference to Exhibit 10.1 to Form 10-K for year ended December 31, 2002, SEC File No. 0-07246 filed on March 7, 2003 +Employment Agreement -Steven R. Williams, President +10.2 +Incorporated by reference to Exhibit 10.2 to Form 10-K for year ended December 31, 2002, SEC File No. 0-07246 filed on March 7, 2003 +Employment Agreement - Darwin L. Stump, +Chief Financial Officer +10.3 +Incorporated by referenced to Exhibit 99 to Form 8-K, SEC File No. 0-07246 filed on January 5, 2004 +Employment Agreement -Thomas E. Riley, +Executive Vice President +10.4 +Incorporated by reference to Exhibit 99 to Form 8-K, SEC File No. 0-07246 filed on January 5, 2004 +Employment Agreement - Eric R. Stearns, +Executive Vice President +10.5 +Incorporated by reference to Exhibit 99 to Form 8-K SEC File No. 0-07246 filed on January 5, 2004 +Code of Business Conduct and Ethics +14 +Incorporated by reference to Exhibit 3.1 to +Form 10-K for the year ended December 31, 2002, SEC File No. 0-07246 filed on March 7, 2003 +Subsidiaries +21 +Riley Natural Gas Company, a West Virginia Corporation +21 +PDC Securities Incorporated, a West Virginia Corporation +Rule 13a-14(a)/15d-14(a) Certification by Chief +Executive Officer +31.1 +Filed herewith. +Rule 13a-14(a)/15d-14(a)Certification by Chief +Financial Officer +31.2 +Filed herewith. +Section 1350 Certifications by Chief Executive Officer +32.1 +Filed herewith. +Section 1350 Certifications by Chief Financial Officer +32.2 +Filed herewith. +Reports on Form 8-K during quarter ended December 31, 2003. +Form 8-K current report dated December 23, 2003, under Item 5. "Other Matters" the Company issued a news release announcing it closed the purchase of interests in oil and natural gas properties in the Denver-Julesburg Basin. +Form 8-K current report dated December 5, 2003, under Item 5. "Other Matters" the Company issued a news release announcing the closing of the fourth 2003 drilling program +Form 8-K current reported dated November 19, 2003, under Item 5. "Other Matters" the Company issued a news release announcing the appointment of several new officers for Petroleum Development. +E-1 +Form 8-K current report dated November 10, 2003, under Item 5. "Other Matters" the Company issued a news release announcing that David C. Parke has been appointed by the Board of Directors to fill the position vacated by Dale G. Rettinger in October. Mr. Rettinger passed away unexpectedly on October 3 after a brief illness. +Form 8-K current report dated November 4, 2003, under Item 5. "Other Matters" the Company issued a news release announcing the Petroleum Development Reports Record Closing for Third 2003 Drilling Program and on November 5, 2003, the Company issued a news release announcing the Petroleum Development Adds to Natural Gas Commodities Options Positions. +Form 8-K current report dated November 3, 2003, under Item 5. "Other Matters" the Company issued a news release announcing 3rd quarter 2003 earnings. +Form 8-K current report dated October 22, 2003, under Item 5. "Other Matters" the Company issued a news release announcing its upcoming third quarter earnings release on November 3 rd and upcoming conference call to discuss earnings on November 4th. +Form 8-K current report dated October 6, 2003, under Item 5. "Other Matters", the Company issued a news release announcing the passing of Dale G Rettinger, Executive Vice President and Chief Financial Officer and that Darwin L. Stump, the Company's controller, has been named as acting CFO. +E-2 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Index to Financial Statements and Financial Statement Schedules +1. +Financial Statements: +Independent Auditors' Report +F-2 +Consolidated Balance Sheets - December 31, 2003 and 2002 +F-3 & 4 +Consolidated Statements of Income - +Years Ended December 31, 2003, 2002 and 2001 +F-5 +Consolidated Statements of Stockholders' Equity - +Years Ended December 31, 2003, 2002 and 2001 +F-6 +Consolidated Statements of Cash Flows - +Years Ended December 31, 2003, 2002 and 2001 +F-7 +Notes to Consolidated Financial Statements +F-8 -26 +2. +Financial Statement Schedule: +Schedule II - Valuation and Qualifying Accounts and Reserves +F-27 +F-1 +Independent Auditors' Report +The Stockholders and Board of Directors +Petroleum Development Corporation: +We have audited the consolidated financial statements of Petroleum Development Corporation and subsidiaries as listed in the accompanying index. In connection with our audits of the consolidated financial statements, we also have audited the financial statement schedule as listed in the accompanying index. These consolidated financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits. +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, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Petroleum Development Corporation and subsidiaries as of December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. +As discussed in note 1 to the consolidated financial statements, the Company adopted the provisions of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, in 2003. As discussed in note 13 to the consolidated financial statements, the Company changed its method of accounting for derivative instruments and hedging activities in 2001. +KPMG LLP +Pittsburgh, Pennsylvania +February 27, 2004 +F-2 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Consolidated Balance Sheets +December 31, 2003 and 2002 +Assets +2003 +2002 +Current assets: +Cash and cash equivalents +$ 78,512,900 +$ 48,263,000 +Restricted cash +1,866,400 +2,760,500 +Notes and accounts receivable +22,523,600 +15,336,500 +Inventories +2,557,700 +1,174,100 +Prepaid expenses +5,907,000 +4,125,300 +Total current assets +111,367,600 +71,659,400 +Properties and equipment: +Oil and gas properties (successful +efforts accounting method) +251,558,900 +183,614,200 +Pipelines +9,097,000 +7,015,000 +Transportation and other equipment +3,460,900 +3,174,200 +Land and buildings +1,747,500 +1,455,400 +265,864,300 +195,258,800 +Less accumulated depreciation, +depletion and amortization +71,182,100 +57,143,700 +194,682,200 +138,115,100 +Other assets +672,200 +2,477,100 +$306,722,000 +$212,251,600 +(Continued) +F-3 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Consolidated Balance Sheets +December 31, 2003 and 2002 +2003 +2002 +Liabilities and Stockholders' Equity +Current liabilities: +Accounts payable +$ 29,453,000 +$ 17,425,500 +Other accrued expenses +16,814,200 +11,261,700 +Advances for future drilling contracts +50,458,800 +37,283,800 +Funds held for future distribution +8,410,900 +3,917,900 +Total current liabilities +105,136,900 +69,888,900 +Long-term debt +53,000,000 +25,000,000 +Other liabilities +2,449,100 +4,137,200 +Deferred income taxes +21,800,200 +12,103,300 +Asset retirement obligation +731,200 +- +Commitments and contingencies +Stockholders' equity: +Common stock, par value $.01 per share; +authorized 50,000,000 shares; issued and +outstanding 15,628,433 and 15,734,767 shares +156,200 +157,300 +Additional paid-in capital +28,578,100 +29,316,800 +Retained earnings +96,049,200 +73,430,100 +Accumulated other comprehensive loss, net of tax +(1,178,900 ) +(1,782,000 ) +Total stockholders' equity +123,604,600 +101,122,200 +$306,722,000 +$212,251,600 +See accompanying notes to consolidated financial statements. +F-4 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Consolidated Statements of Income +Years Ended December 31, 2003, 2002 and 2001 +2003 +2002 +2001 +Revenues: +Oil and gas well drilling operations +$71,841,500 +57,149,100 +76,291,200 +Gas sales from marketing activities +73,141,100 +46,365,900 +66,207,400 +Oil and gas sales +47,021,600 +22,857,100 +25,887,900 +Well operations and pipeline income +7,347,700 +6,116,200 +5,604,200 +Other income +3,499,100 +2,853,600 +3,132,400 +202,851,000 +135,341,900 +177,123,100 +Costs and expenses: +Cost of oil and gas well drilling operations +61,277,800 +49,166,200 +65,999,900 +Cost of gas marketing activities +72,443,600 +46,184,300 +65,740,300 +Oil and gas production and well operations costs +13,749,200 +9,074,200 +8,582,700 +General and administrative expenses +4,974,400 +4,391,900 +4,145,700 +Depreciation, depletion and amortization +14,153,400 +12,103,300 +10,578,300 +Interest +1,329,100 +1,339,800 +993,400 +167,927,500 +122,259,700 +156,040,300 +Income before income taxes and cumulative effect of +change in accounting principle +34,923,500 +13,082,200 +21,082,800 +Income taxes +12,105,800 +3,797,400 +6,115,000 +Net income before cumulative effect of change in +accounting principle +22,817,700 +9,284,800 +14,967,800 +Cumulative effect of change in accounting principle +(net of taxes of $121,700) +(198,600 ) +- +- +Net income +$22,619,100 +9,284,800 +14,967,800 +Basic earnings per common share before accounting change +$1.46 +.59 +.92 +Cumulative effect of change in accounting principle +(0.01) +- +- +Basic earnings per common share +$1.45 +.59 +.92 +Diluted earnings per share before accounting change +$1.40 +.58 +.90 +Cumulative effect of change in accounting principle +(0.01) +- +- +Diluted earnings per common and common equivalent share +$1.39 +.58 +.90 +See accompanying notes to consolidated financial statements. +F-5 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Consolidated Statements of Stockholders' Equity +Years Ended December 31, 2003, 2002 and 2001 +Common stock issued +Number +Of +Shares +Amount +Additional +Paid-in- +capital +Retained +Earnings +Accumulated +Other +Comprehensive +Income +Total +Balance, December 31, 2000 +16,244,044 +$162,400 +32,917,000 +49,177,500 +- +82,256,900 +Issuance of common stock +1,708 +- +- +- +- +Amortization of stock award +- +- +5,500 +- +- +5,500 +Net income +14,967,800 +14,967,800 +Comprehensive income: +Cumulative effect of change in accounting principle - +January 1, 2001 (net of tax of $8,052,700) +- +- +- +- +(12,079,100) +Reclassification adjustment for settlement of contracts +Included in net income (net of tax of $3,046,900) +- +- +- +- +4,971,200 +Changes in fair value of outstanding hedging positions +(net of tax of $4,076,100) +- +- +- +- +6,650,500 +Other comprehensive loss +(457,400) +(457,400 ) +Comprehensive income +_________ +___________ +_________ +___________ +________ +14,510,400 +Balance, December 31, 2001 +16,245,752 +162,400 +32,922,500 +64,145,300 +(457,400) +96,772,800 +Issuance of common stock: +Exercise of employee stock options +70,000 +700 +78,100 +- +- +78,800 +Amortization of stock award +- +5,500 +- +- +5,500 +Repurchase and cancellation of treasury stock +(580,985) +(5,800) +(3,689,300) +(3,695,100) +Net income +- +- +- +9,284,800 +- +9,284,800 +Comprehensive income: +Reclassification adjustment for settlement of contracts +Included in net income (net of tax of $9,100) +- +- +- +- +14,800 +Changes in fair value of outstanding hedging positions +and interest rate swap (net of tax of $820,900) +- +- +- +- +(1,339,400 ) +Other comprehensive loss +(1,324,600) +(1,324,600 ) +Comprehensive income +_________ +___________ +_________ +___________ +________ +7,960,200 +Balance, December 31, 2002 +15,734,767 +157,300 +29,316,800 +73,430,100 +(1,782,000) +101,122,200 +Amortization of stock award +- +8,900 +- +- +8,900 +Repurchase and cancellation of treasury stock, net +(106,334) +(1,100) +(747,600) +(748,700) +Net income +- +- +- +22,619,100 +- +22,619,100 +Comprehensive income: +Reclassification adjustment for settlement of contracts +Included in net income (net of tax of $583,900) +- +- +- +- +917,200 +Changes in fair value of outstanding hedging positions +and interest rate swap (net of tax of $200,000) +- +- +- +- +(314,100 ) +Other comprehensive income +603,100 +603,100 +Comprehensive income +_________ +___________ +_________ +___________ +________ +23,222,200 +Balance, December 31, 2003 +15,628,433 +$ 156,200 +28,578,100 +96,049,200 +(1,178,900) +123,604,600 +See accompanying notes to consolidated financial statements. +F-6 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Consolidated Statements of Cash Flows +Years Ended December 31, 2003, 2002 and 2001 +2003 +2002 +2001 +Cash flows from operating activities: +Net income +$22,619,100 +9,284,800 +14,967,800 +Adjustment to reconcile net income to cash provided by +operating activities: +Deferred income taxes +8,870,700 +2,986,400 +4,002,400 +Depreciation, depletion and amortization +14,153,400 +12,103,300 +10,578,300 +Cumulative effect of change in accounting principle +198,600 +- +- +Gain from sale of assets +(115,800) +(25,800) +(132,400) +Expired and abandoned leases +1,418,400 +1,129,400 +919,100 +Amortization of stock award +8,900 +5,500 +5,500 +(Increase) decrease in notes and accounts receivable +(7,187,100) +(4,583,900) +12,895,400 +Increase in inventories +(1,383,600) +(56,200) +(20,000) +(Increase) decrease in prepaid expenses +(1,095,900) +369,200 +3,243,900 +Decrease in other assets +1,696,200 +56,300 +336,700 +Increase (decrease) in accounts payable and accrued expenses +16,757,000 +1,945,200 +(8,219,900) +Increase (decrease) in advances for future drilling contracts +13,175,000 +5,691,600 +(12,217,200) +Increase (decrease) in funds held for future distribution +4,493,000 +(732,900 ) +2,210,700 +Total adjustments +50,988,800 +18,888,100 +13,602,500 +Net cash provided by operating activities +73,607,900 +28,172,900 +28,570,300 +Cash flows from investing activities: +Capital expenditures +(73,042,300) +(19,777,000) +(42,661,100) +Proceeds from sale of leases +1,382,100 +1,042,500 +4,732,200 +Proceeds from sale of fixed assets +156,800 +25,800 +12,200 +Decrease (increase) in restricted cash +894,100 +(2,477,200 ) +2,655,000 +Net cash used in investing activities +(70,609,300 ) +(21,185,900 ) +(35,261,700 ) +Cash flows from financing activities: +Proceeds from (retirement of) debt, net +28,000,000 +(3,000,000) +10,650,000 +Proceeds from issuance of stock +- +78,800 +- +Repurchase and cancellation of treasury stock +(748,700 ) +(3,695,100 ) +- +Net cash provided by (used in) financing activities +27,251,300 +(6,616,300 ) +10,650,000 +Net increase in cash and cash equivalents +30,249,900 +370,700 +3,958,600 +Cash and cash equivalents, beginning of year +48,263,000 +47,892,300 +43,933,700 +Cash and cash equivalents, end of year +$78,512,900 +48,263,000 +47,892,300 +See accompanying notes to consolidated financial statements. +F-7 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +Years Ended December 31, 2003, 2002 and 2001 +(1) Summary of Significant Accounting Policies +Principles of Consolidation +The accompanying consolidated financial statements include the accounts of Petroleum Development Corporation (PDC) and its wholly owned subsidiaries, Riley Natural Gas (RNG) and PDC Securities Incorporated. All material intercompany accounts and transactions have been eliminated in consolidation. The Company accounts for its investment in limited partnerships under the proportionate consolidation method. Under this method, the Company's financial statements include its prorata share of assets and liabilities and revenues and expenses, respectively, of the limited partnerships in which it participates. +The Company is involved in four business segments. The segments are drilling and development, natural gas marketing, oil and gas sales and well operations. (See Note 19) +The Company grants credit to purchasers of oil and gas and the owners of managed properties, substantially all of whom are located in West Virginia, Tennessee, Pennsylvania, Ohio, Michigan, North Dakota, Colorado and Kansas. +Cash Equivalents +For purposes of the statement of cash flows, the Company considers all highly liquid debt instruments with original maturities of three months or less to be cash equivalents. +Inventories +Inventories of well equipment, parts and supplies are valued at the lower of average cost or market. An inventory of natural gas is recorded when gas is purchased in excess of deliveries to customers and is recorded at the lower of cost or market. An inventory of oil located in stock tanks on well locations, is carried at market at the end of each period. +Oil and Gas Properties +Exploration and development costs are accounted for by the successful efforts method. +The Company assesses impairment of capitalized costs of proved oil and gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using expected prices. Prices utilized in each year's calculation for measurement purposes and expected costs are held constant throughout the estimated life of the properties. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value which would consider future discounted cash flows. +Property acquisition costs are capitalized when incurred. Geological and geophysical costs and delay rentals are expensed as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether the wells have discovered economically producible reserves. If reserves are not discovered, such costs are expensed as dry holes. Development costs, including equipment and intangible drilling costs related to both producing wells and developmental dry holes, are capitalized. +(Continued) +F-8 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +Unproved properties or leases are written-off to expense when it is determined that they will expire or be abandoned. +Costs of proved properties, including leasehold acquisition, exploration and development costs and equipment, are depreciated or depleted by the unit-of-production method based on estimated proved developed oil and gas reserves. +Upon sale or retirement of complete fields of depreciable or depletable property, the book value thereof, less proceeds or salvage value, is credited or charged to income. Upon retirement of a partial unit of property, the procceds are charged to accumulated depreciation and depletion. +Transportation Equipment, Pipelines and Other Equipment +Transportation equipment, pipelines and other equipment are carried at cost. Depreciation is provided principally on the straight-line method over useful lives of 3 to 17 years. The Company adopted SFAS No. 144 on January 1, 2002. The adoption of SFAS No. 144 did not affect the Company's financial statements. +In accordance with SFAS No. 144, long-lived assets, such as property, plant, and equipment, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. +Prior to the adoption of SFAS No. 144, the Company accounted for long-lived assets in accordance with SFAS No. 121, Accounting for Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of. +Maintenance and repairs are charged to expense as incurred. Major renewals and betterments are capitalized. Upon the sale or other disposition of assets, the cost and related accumulated depreciation, depletion and amortization are removed from the accounts, the proceeds applied thereto and any resulting gain or loss is reflected in income. +Buildings +Buildings are carried at cost and depreciated on the straight-line method over estimated useful lives of 30 years. +Advances for Future Drilling Contracts +Represents funds received from Partnerships and other joint ventures for drilling activities which have not been completed and accordingly have not yet been recognized as income in accordance with the Company's income recognition policies. +Retirement Plans +The Company has a 401-K contributory retirement plan (401-K Plan) covering full-time employees. The Company provides a discretionary matching of employee contributions to the plan. +The Company also has a profit sharing plan covering full-time employees. The Company's contributions to this plan are discretionary. +(Continued) +F-9 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +The Company has a deferred compensation arrangement covering executive officers of the Company as a supplemental retirement benefit. +In prior years, the Company had split dollar life insurance arrangements with certain executive officers. The arrangements were terminated during 2002. Under these arrangements, advances were made to these officers equal to the premiums due. The advances were collateralized by the cash surrender value of the policies. The Company recorded as other assets its share of the cash surrender value of the policies. +Revenue Recognition +Oil and gas wells are drilled primarily on a contract basis. The Company follows the percentage-of-completion method of income recognition for drilling operations in progress. +Sales of natural gas are recognized when sold, oil revenues are recognized when produced into a stock tank. +Well operations and pipeline income consists of operation charges for well upkeep, maintenance, transportation of natural gas and operating lease income on tangible well equipment. +Income Taxes +Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. +Derivative Financial Instruments +All derivatives are recognized on the consolidated balance sheet at their fair value. On the date the derivative contract is entered into, the Company designates the derivative as either a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability ("Cash flow" hedge), or a non-hedging derivative. The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk-management objective and strategy for undertaking various hedge transactions. This process includes linking all derivatives that are designated as cash-flow hedges to specific firm commitments. The Company also formally assesses, both at the hedge's inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. When it is determined that a derivative is not highly effective as a hedge or that it has ceased to be a highly effective hedge, the Company discontinues hedge accounting prospectively. No hedging activities were discontinued during 2003 or 2002. +Changes in fair value of a derivative that is highly effective and that is designated and qualifies as a cash-flow hedge are recorded in other comprehensive income, until earnings are affected by the variability in cash flows of the designated hedged item. Changes in the fair value of non-hedging derivatives are reported in current-period earnings. The Company discontinues hedge accounting prospectively when it is determined that the derivative is no longer effective in offsetting changes in the cash flows of the hedged item, the derivative expires or is sold, terminated, or exercised. Additionally, if the derivative is dedesignated as a hedging instrument, because it is probable that a forecasted transaction will not occur or management determines that designation of the derivative as a hedging instrument is no longer appropriate, hedge accounting will discontinue. +(Continued) +F-10 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +During 2000, the Company entered into an interest rate swap agreement which expires October 11, 2004 to reduce its exposure to variability from changing interest rates. The interest rate differential to be paid or received is accrued and recognized as interest expense in the period incurred. +Stock Compensation +The Company has adopted SFAS No. 123, "Accounting for Stock-Based Compensation," which permits entities to recognize as expense over the vesting period the fair value of all stock-based awards on the date of grant. Alternatively, SFAS 123 allows entities to continue to measure compensation cost for stock-based awards using the intrinsic value based method of accounting prescribed by APB Opinion No. 25, "Accounting for Stock Issued to Employees," and to provide pro forma net income and pro forma earnings per share disclosures as if the fair value based method defined in SFAS 123 had been applied. The Company has elected to continue to apply the provisions of APB 25 and provide the pro forma disclosure provisions of SFAS 123. For stock options granted, the option price was not less than the market value of shares on the grant date, therefore, no compensation cost has been recognized. Had compensation cost been determined under the provisions of SFAS 123, the Company's net income and earnings per share would have been the following on a pro forma basis: +2003 +2002 +2001 +Net income, as reported +$22,619,100 +$9,284,800 +$14,967,800 +Deduct total stock-based employee +compensation expense determined +under fair-value-based method for +all awards, net of tax +- +- +(486,100 ) +Pro forma net income +$22,619,100 +$9,284,800 +$14,481,700 +Pro forma basic earnings per share +$1.45 +$0.59 +$0.89 +Pro forma diluted earnings per share +$1.39 +$0.58 +$0.87 +Use of Estimates +Management of the Company has made a number of estimates and assumptions relating to the reporting of assets and liabilities and revenues and expenses and the disclosure of contingent assets and liabilities to prepare these financial statements in conformity with generally accepted accounting principles. Actual results could differ from those estimates. Estimates which are particularly significant to the consolidated financial statements include estimates of oil and gas reserves and future cash flows from oil and gas properties. +Fair Value of Financial Instruments +The carrying values of the Company's receivables, payables and debt obligations are estimated to be substantially the same as the fair values as of December 31, 2003, 2002 and 2001. +(Continued) +F-11 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +New Accounting Standards +In June 2001, the Financial Accounting Standard Board issued SFAS No. 143, "Accounting for Asset Retirement Obligations" that requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. This statement is effective for fiscal years beginning after June 15, 2002. The Company adopted SFAS No. 143 on January 1, 2003 and recorded a net asset of $271,800 and a related liability of $592,100 (using a 6% discount rate) and a cumulative effect on change in accounting principle on prior years of $198,600 (net of taxes of $121,700). During 2003 the liability has increased to $731,200 due to the additional wells purchased and drilled by the Company. +In December 2002, the FASB issued SFAS 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 123 to require prominent disclosures in both annual and interim financial statements. Disclosures required by this standard are included in the notes to these financial statements. +A reporting issue has arisen regarding the application of certain provisions of SFAS No. 141 and SFAS no. 142 to companies in the extractive industries, including oil and gas companies. The issue is whether SFAS No. 142 requires registrants to classify the costs of mineral rights (leases) associated with extracting oil and gas intangible assets in the balance sheets, apart from other capitalized oil and gas property costs, and provide specific footnote disclosures. Historically, the Company has included the costs of mineral rights associated with extracting oil and gas as a component of oil and gas properties. If it is ultimately determined that SFAS No. 142 requires oil and gas companies to classify costs of mineral rights associated with extracting oil and gas as a separate intangible assets line item on the balance sheet, the Company would be required to reclassify the historical cost of approximately $7,576,900 and $4,208,800 of mineral rights associated with undeveloped oil and gas properties and $15,485,500 and $10,898,700 of mineral rights associated with developed oil and gas properties as of December 31, 2003 and December 31, 2002, respectively, out of oil and gas properties and into a separate intangible mineral rights assets line item. The Company's total balance sheet, cash flows and results of operations would be not affected since such intangible assets would continue to be amortized and assessed for impairment. +(2) Notes and Accounts Receivable +Included in other assets are noncurrent accounts receivable as of December 31, 2003 and 2002, in the amounts of $819,700 and $445,600 less of an allowance for doubtful accounts of $338,100 and $445,600, respectively. +The allowance for doubtful current accounts receivable as of December 31, 2003 and 2002 was $149,200 and $78,900, respectively. +(3) Long-Term Debt +On July 3, 2002 the Company executed a $100 million credit facility with Bank One, NA and BNP Paribas. The agreement provides for borrowing up to $100 million subject to and secured by adequate levels of oil and gas reserves. The current total borrowing base is $80.0 million of which the Company has activated $60 million of the facility. The Company is required to pay a commitment fee of 1/4 percent on the unused portion of the activated credit facility. Interest accrues at prime, with LIBOR (London Interbank Market Rate) alternatives available at the discretion of the Company. No principal payments are required until the credit agreement expires on July 3, 2005. +(Continued) +F-12 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +As of December 31, 2003 and 2002 the outstanding balance was $53,000,000 and $25,000,000, respectively. Any amounts outstanding under the credit facility are secured by substantially all properties of the Company. The credit agreement requires, among other things, the existence of satisfactory levels of natural gas reserves, maintenance of certain working capital and tangible net worth ratios along with a restriction on the payment of dividends. As of December 31, 2003 and 2002 the Company was in compliance with all financial covenants in the credit agreement. +At December 31, 2003, $10,000,000 of the outstanding balance was subject to an interest rate swap at a rate of 8.39%, $15,000,000 was subject to a 90-day LIBOR rate of 2.87%, $5,000,000 was subject to a 30-day LIBOR rate of 2.92%, and $23,000,000 was subject to a prime rate of 4.00%. +(4) Income Taxes +The Company's provision for income taxes consisted of the following: +2003 +2002 +2001 +Current: +Federal +$2,401,000 +604,200 +1,639,300 +State +834,100 +206,800 +473,300 +Total current income taxes +3,235,100 +811,000 +2,112,600 +Deferred: +Federal +7,802,800 +2,461,200 +3,898,600 +State +1,067,900 +525,200 +103,800 +Total deferred income taxes +8,870,700 +2,986,400 +4,002,400 +Total income taxes +$12,105,800 +3,797,400 +6,115,000 +Income tax expense differed from the amounts computed by applying the U.S. federal income tax rate of 35 percent in 2003 and 34 percent in 2002 and 2001 to pretax income as a result of the following: +2003 +2002 +2001 +Computed "expected" tax +$12,223,200 +4,447,900 +7,168,200 +State income tax +1,362,000 +483,100 +380,900 +Percentage depletion +(935,000) +(680,000) +(935,000) +Nonconventional source fuel credit +- +(491,500) +(1,184,700) +Effect of state rate change +- +- +556,500 +Revision of prior estimate - Nonconventional +Source Fuel Credit +(186,600) +- +- +Other permanent items, officers life insurance +(360,000) +- +- +Surtax exemption +(100,000) +- +- +Change in federal rate bracket +254,700 +- +- +Other +(152,500 ) +37,900 +129,100 +$12,105,800 +3,797,400 +6,115,000 +(Continued) +F-13 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2003 and 2002 are presented below: +2003 +2002 +Deferred tax assets: +Allowance for doubtful accounts +$ 189,500 +199,300 +Drilling notes +73,500 +84,500 +Alternative minimum tax credit carryforwards (Section 29) +437,400 +2,055,500 +Future abandonment +614,900 +505,900 +Deferred compensation +1,784,200 +2,000,400 +Other +27,700 +40,600 +Total gross deferred tax assets +3,127,200 +4,886,200 +Less valuation allowance +- +- +Deferred tax assets +3,127,200 +4,886,200 +Less current deferred tax assets (included in prepaid expenses) +(1,957,400 ) +(1,351,200 ) +Net non-current deferred tax assets +1,169,800 +3,535,000 +Deferred tax liabilities: +Properties and equipment, principally due to differences in +Depreciation and amortization +(23,842,200 ) +(16,730,500 ) +Total gross deferred tax liabilities +(23,842,200 ) +(16,730,500 ) +Net non-current deferred tax liability +(22,672,400) +(13,195,500) +Deferred income tax assets related to adoption of FASB 143 +121,700 +- +Deferred income tax assets related to AOCI +750,500 +1,092,200 +Net deferred tax liability +$(21,800,200 ) +(12,103,300 ) +At December 31, 2003, the Company has alternative minimum tax credit carryforwards (Section 29) of approximately $437,400 which are available to reduce future federal regular income taxes over an indefinite period. +Accumulated other comprehensive loss is net of tax of $750,500, $1,092,200 and $280,500 as of December 31, 2003, 2002 and 2001, respectively. +(5) Common Stock +Options +Options amounting to 185,000 shares were granted during 2001 to certain employees and directors under the Company's Stock Option Plans. These options were granted with an exercise price equal to market value as of the date of grant and vest over a six month period. The outstanding options expire from 2005 to 2011. +The estimated fair value of the options granted during 2001 was $3.70 per option. The fair value was estimated using the Black-Scholes option pricing model with the following assumptions for the 2001 grant: risk-free interest rate of 5.88%, expected dividend yield of 0%, expected volatility of 50.23% and expected life of 7 years. +(Continued) +F-14 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +Number +of Shares +Average +Exercise +Price +Range of +Exercise +Prices +Outstanding December 31, 2000 +1,045,000 +$3.95 +1.125 - 6.125 +Granted +185,000 +$6.25 +6.25 - 6.25 +Outstanding December 31, 2001 +1,230,000 +$4.29 +1.125 - 6.25 +Exercised +(70,000 ) +$1.125 +1.125 - 1.125 +Outstanding December 31, 2002 +1,160,000 +$4.48 +1.125 - 6.25 +Granted +- +- +- +Exercised +- +- +- +Outstanding December 31, 2003 +1,160,000 +$4.48 +1.125 - 6.25 +As of December 31, 2003, there were 140,000 options outstanding and exercisable at the $1.125 exercise price which have a weighted average remaining contractual life of 1.9 years. Also as of December 31, 2003 there were 1,020,000 options outstanding and exercisable at a $3.75 to $6.25 exercise price range having a weighted average remaining contractual life of 4.9 years and weighted average exercise price of $4.95. +Common Stock Repurchase +On March 13, 2003 the Company publicly announced the authorization by its Board of Directors to repurchase up to 5% of the Company's common stock (785,000 shares) at fair market value at the date of purchase. Under the program, the Board has discretion as to the dates of purchase and amounts of stock to be purchased and whether or not to make purchases. From inception of the program until December 31, 2003, the Company has repurchased 109,200 shares at an average price of $6.86. This program is scheduled to expire on December 31, 2004. The following activity has occurred since inception of the plan on March 13, 2003 until December 31, 2003. +Month of Purchase +March, 2003 +April, 2003 +September, 2003 +Average Price paid per share +$6.08 +$6.48 +$11.15 +Broker/Dealer +McDonald Investments +McDonald Investments +McDonald Investments +Number of Shares Purchased +46,500 +49,900 +12,800 +Remaining Number of Shares to +Purchase +738,500 +688,600 +675,800 +(Continued) +F-15 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +Stock Repurchase Agreement +The Company has stock repurchase agreements with two officers of the Company. The agreements require the Company to maintain life insurance on each executive in the amount of $1,000,000. The agreements provide that the Company shall utilize the proceeds from such insurance to purchase from such executives' estates or heirs, at their option, shares of the Company's stock. The purchase price for the outstanding common stock is to be based upon the average closing asked price for the Company's stock as quoted by NASDAQ during a specified period. The Company is not required to purchase any shares in excess of the amount provided for by such insurance. During the fourth quarter of 2003, the Company received $1,000,000 in life insurance proceeds which was recorded as other income from the death of the Company's Chief Financial Officer who had a stock repurchase agreement referred to above. The Company has not purchased shares from such executive's estate as of December 31, 2003. +(6) Employee Benefit Plans +The Company made 401-K Plan contributions of $305,500, $288,000 and $260,800 for 2003, 2002 and 2001, respectively. +The Company has a profit sharing plan (the Plan) covering full-time employees. The Company contributed $250,000, $200,000 and $200,000 to the plan in cash during 2003, 2002 and 2001, respectively. +During 2003, 2002 and 2001 the Company expensed $90,000 each year under a deferred compensation arrangement with certain executive officers of the Company. These amounts were paid during 2003 to such executive officers. +At December 31, 2002, the Company had recorded as other assets $501,000, related to the cash surrender value of the life insurance on certain executive officers, during 2003 such policies were distributed to the participants. +The Company has a deferred compensation arrangement covering certain executive officers of the Company as a supplemental retirement benefit. During 2003, 2002 and 2001 the Company expensed $181,900, $171,600, and $171,600, respectively, and has recorded a related liability in the amount $868,300 and $686,400 as of December 31, 2003 and 2002, respectively. +(7) Earnings Per Share +Basic earnings per share is based on the weighted average number of common shares outstanding of 15,659,591 for 2003, 15,866,363 for 2002 and 16,244,931 for 2001. +Diluted earnings per share is based on the weighted average number of common and common equivalent shares outstanding of 16,297,793 for 2003, 16,143,414 for 2002 and 16,639,634 for 2001. Stock options are considered to be common stock equivalents and to the extent appropriate, have been added to the weighted average common shares outstanding. +(Continued) +F-16 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +(8) Transactions with Affiliates +As part of its duties as well operator, the Company received $108,507,800 in 2003, $60,620,200 in 2002, and $71,802,700 in 2001 representing proceeds from the sale of oil and gas and made distributions to investor groups according to their working interests in the related oil and gas properties. Funds held for future distribution on the consolidated balance sheet of $8,410,900 and $3,917,900 includes amounts owed to affiliated partnerships as of December 31, 2003 and 2002, respectively. +The Company provided oil and gas well drilling services to affiliated partnerships. Substantially all of the Company's oil and gas well drilling operations was for such partnerships. The Company also provided related services of operation of wells, reimbursement of syndication costs, management fees, tax return preparation and other services relating to the operation of the partnerships. The Company received $26,539,400 in 2003, $20,008,900 in 2002 and $16,072,500 in 2001 for various services and other reimbursements. Amounts due from the partnerships as of December 31, 2003 and 2002 were $929,600 and $1,028,000, and are included in notes and accounts receivable. +During 2003, 2002 and 2001, the Company paid $30,000, $51,800 and $30,100, respectively, to the Corporate Secretary's (former Board Member) law firm for various legal services. +(9) Commitments and Contingencies +The nature of the independent oil and gas industry involves a dependence on outside investor drilling capital and involves a concentration of gas sales to a few customers. The Company sells natural gas to various public utilities and industrial customers. One customer accounted for 10.3%, 10.8% and 13.1% of total revenues in 2003, 2002 and 2001, respectively. +The Company would be exposed to natural gas price fluctuations on underlying purchase and sale contracts should the counterparties to the Company's hedging instruments or the counterparties to the Company's gas marketing contracts not perform. Such nonperformance is not anticipated. There were no counterparty default losses in 2003, 2002 or 2001. +Substantially all of the Company's drilling programs contain a repurchase provision where Investing Partners may request the Company to purchase their partnership units at any time beginning with the third anniversary of the first cash distribution. The provision provides that the Company is obligated to purchase an aggregate of 10% of the initial subscriptions per calendar year (at a minimum price of four times the most recent 12 months' cash distributions), only if such units are requested by the investors, subject to the Company's financial ability to do so. The maximum annual 10% repurchase obligation, if requested by the investors, is currently approximately $4.8 million. The Company has adequate liquidity to meet this obligation. During 2003, the Company paid $266,500 under this provision for the repurchase of partnership units. +The Company's drilling programs formed since 1996 contain a performance standard which states that if certain performance levels are not met, the Company must remit a payment equal to one-half of its share of revenue from such partnership to the investing partners. During 2003, 2002, and 2001 the Company paid partnerships a total of $385,400, $198,500 and $287,200, respectively in accordance with the provision. +During the fourth quarter of 2003, the Company recorded a liability in accordance with the death benefit of the employment contract of the Company's Chief Financial Officer in the amount of $852,700. +The Company is not party to any legal action that would materially affect the Company's results of operations or financial condition. +(Continued) +F-17 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +(10) Lease Obligations +The Company has entered into certain operating leases on behalf of itself and its Partnerships principally for the leasing of natural gas compressors on its Michigan operating facilities and office printing and copying equipment. The future minimum lease payments under these non-cancellable operating leases as of December 31, 2003 are as follows: +Year +Lease Amount +2004 +$ 366,300 +2005 +211,000 +2006 +97,300 +2007 +90,600 +2008 +68,000 +$833,200 +The Company's share of this lease expense for operating leases for the years ended December 31, 2003, 2002 and 2001 was $574,700, $660,700 and $693,000, respectively. +(11) Supplemental Disclosure of Cash Flows +The Company paid $1,274,003, $1,290,400 and $1,173,100 for interest in 2003, 2002 and 2001, respectively. The Company paid income taxes in 2003, 2002 and 2001 in the amounts of $3,649,600, $175,000 and $2,830,000, respectively. +(12) Acquisitions of Oil and Gas Properties +During the second quarter of 2003, the Company purchased 166 wells in the Denver Julesburg Basin in northeastern Colorado from Williams Production RMT Company for $28 million. The Company estimates the acquisition included approximately 22.6 billion cubic feet (Bcf) of proved developed producing (PDP) and 3.4 Bcf of proved developed non-producing reserves (PDNP), all of which is natural gas. The acquired property may also include up to 150 additional locations subject to approval of revised spacing from the State of Colorado. +During the fourth quarter of 2003, the Company purchased from one of its joint venture partners in the Denver-Julesburg Basin in Weld County, Colorado approximately 3.1 billion cubic feet equivalent (Bcfe) of proved developed producing reserves from interests in 20.6 net wells (230 gross) and 1.8 Bcfe of proved developed non-producing reserves from interests in 17 net wells (183 gross). The purchase price was $5.2 million which also included over 30 additional drilling locations. +During the fourth quarter of 2003, the Company purchased 97 gross wells (73 net) wells in the Denver-Julesburg Basin located in northeast Colorado and northwestern Kansas for $6.0 million. This purchase adds approximately 4.5 billion cubic feet equivalent (Bcfe) of proved developed producing and proved developed non-producing reserves to the Company's oil and gas reserves along with 100,000 acres of oil and gas leases. +(Continued) +F-18 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +(13) Derivative Financial Instruments +The futures and option contracts hedge forecasted natural gas purchases and sales, generally forecasted to occur within a 12 month period. The Company does not hold or issue derivatives for trading or speculative purposes. In addition, interest rate swap agreements are used to reduce the potential impact of increases in interest rates on variable rate long-term debt. +Statement of Accounting Standards No. 133 and No. 138, Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133/138), was issued by the Financial Accounting Standards Board. SFAS No. 133/138 standardized the accounting for derivative instruments, including certain derivative instruments embedded in other contracts. The Company adopted the provisions of the SFAS 133/138 effective January 1, 2001. On adoption of this Statement on January 1, 2001, the Company recorded a net transition adjustment of $(12,079,100) (net of related income tax benefit of $8,052,700) which was recorded in accumulated other comprehensive income (AOCI). The natural gas futures and options and the interest rate swap are derivatives pursuant to SFAS 133/138. The Company's derivatives are treated as hedges of forecasted transactions and had a total estimated fair value of $(1,178,900) (net of tax) on December 31, 2003 and a total estimated fair value of $(1,782,000) (net of tax) on December 31, 2002. +Natural gas futures and option contracts for the sale or purchase of natural gas are as follows: +December 31, 2003 +Amount +(mmbtu) +Fair Value +Fair Value +net of tax +Futures contracts +Marketing activities +3,480,000 +$(1,540,400) +$(941,200) +Production activities +99,100 +(9,600) +(5,900) +3,579,100 +$ (1,550,000 ) +$ (947,100 ) +Option contracts +Marketing activities +- +- +- +Production activities +3,289,000 +$ 57,500 +$ 35,100 +3,289,000 +$ 57,500 +$ 35,100 +December 31, 2002 +Futures contracts +Marketing activities +3,950,000 +$(1,431,400) +$(887,400) +Production activities +280,000 +(209,700) +(130,000) +4,230,000 +$ (1,641,100 ) +$ (1,017,400 ) +Option contracts +Marketing activities +- +- +- +Production activities +2,950,400 +$ (337,200 ) +$ (209,100 ) +2,950,400 +$ (337,200 ) +$ (209,100 ) +(Continued) +F-19 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +The Company utilizes commodity-based derivative instruments as hedges to manage a portion of its exposure to price risk from its natural gas sales and marketing activities. These instruments consist of NYMEX-traded natural gas futures contracts and option contracts for Appalachian and Michigan production and CIG-based contracts traded by Bank One for Colorado production. These hedging arrangements have the effect of locking in for specified periods (at predetermined prices or ranges of prices) the prices the Company will receive for the volume to which the hedge relates and, in the case of RNG, the cost of gas supplies purchased for marketing activities. As a result, while these hedging arrangements are structured to reduce the Company's exposure to changes in price associated with the hedged commodity, they also limit the benefit the Company might otherwise have received from price increases associated with the hedged commodity. The Company's policy prohibits the use of natural gas future and option contracts for speculative purposes. +As of December 31, 2003 RNG had entered into a series of natural gas future contracts stemming from its marketing activities. Total open futures contracts are for the sale of 2,660,000 Mmbtu of natural gas with a weighted average price of $4.58 Mmbtu resulting in a total contract amount of $12,174,100 and a fair market value of $(1,810,500) and for the purchase of 820,000 Mmbtu of natural gas with a weighted average price of $5.17 Mmbtu resulting in a total contract amount of $4,243,400 and a fair market value of $270,200. Open future contracts maturing in 2004 are for the sale of 2,060,000 mmbtu of natural gas with a weighted average price of $4.66 mmbtu resulting in a total contract amount of $9,594,200 and a fair market value of $(1,562,100) and for the purchase of 820,000 mmbtu of natural gas with a weighted average price of $5.17 mmbtu resulting in a total contract amount of $4,243,400 and a fair market value of $270,200. The maximum term over which RNG is hedging exposure to the variability of cash flows for commodity price risk is 25 months. There were no open option contracts stemming from RNG's marketing activities as of December 31, 2003. As of December 31, 2002, RNG had entered into a series of natural gas future contracts and option contracts stemming from its marketing activities. Open future contracts as of December 31, 2002 that matured in 2003 were for the sale of 3,210,000 mmbtu of natural gas with a weighted average price of $3.18 Mmbtu resulting in a total contract amount of $12,728,100 and a fair market value of $(1,912,200). +As of December 31, 2003, PDC had entered into a series of natural gas future contracts and option contracts stemming from its natural gas production. Open future contracts maturing in 2004 are for the sale of 53,300 Mmbtu of natural gas with a weighted average price of $5.40 Mmbtu resulting in a total contract amount of $288,000 and a fair market value of $(40,000) and for the purchase of 45,700 Mmbtu of natural gas with a weighted average price of $4.77 resulting in a total contract amount of $218,100 and a fair value of $30,400. Open option contracts maturing in 2004 are for the sale of 2,597,800 Mmbtu with a weighted average floor price of $4.29 Mmbtu and a fair value of $185,300 and 691,200 Mmbtu with a weighted average ceiling price of $5.23 Mmbtu and a fair value of $(127,800). The maximum term over which the Company is hedging exposure to the variability of cash flows for commodity price risk is 12 months. As of December 31, 2002, PDC had entered into a series of natural gas future contracts and option contracts stemming from its natural gas production. Open future contracts as of December 31, 2002 that matured in 2003 were for the sale of 280,000 mmbtu of natural gas with a weighted average price of $4.25 mmbtu resulting in a total contract amount of $1,190,000 and a fair market value of $(209,700). Open option contracts as of December 31, 2002 that matured in 2003 were for the sale of 2,155,600 mmbtu with a weighted average floor price of $3.15 mmbtu and a fair value of $105,600 and 794,800 mmbtu with a weighted average ceiling price of $3.80 mmbtu and a fair value of $(442,800). +The Company is required to maintain margin deposits with brokers for outstanding futures contracts. As of December 31, 2003 and 2002, cash in the amount of $1,866,400 and $2,760,500 was on deposit. +Interest rate swap agreements are used to reduce the potential impact of increases in interest rates on variable rate long-term debt. At December 31, 2003 and 2002, the Company was a party to an interest rate swap agreement expiring on October 11, 2004. The agreement requires the Company, on a quarterly basis, to make a fixed-rate interest payment of 6.89% plus its current LIBOR rate margin (+1.50% At December 31, 2003) on a $10,000,000 amount related to its outstanding line of credit. +(Continued) +F-20 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +The fair value of the interest rate swap agreement was $(436,800), $(266,900) net of tax at December 31, 2003 and $(896,000), $(555,000) net of tax at December 31, 2002. Current market pricing models were used to estimate fair value. +By using derivative financial instruments to hedge exposures to changes in interest rates and commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates repayment risk. The Company minimizes the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties. +Changes in the fair value of natural gas futures contracts designated as hedging instruments and that effectively offset the variability of cash flows associated with anticipated sales of natural gas are reported in accumulated other comprehensive income (AOCI). These amounts subsequently are reclassified into gas purchases for RNG and gas sales for PDC when the related gas is sold and affects earnings. Changes in the fair value of the interest rate swap agreement are reclassified into interest expense monthly. +(14) Costs Incurred in Oil and Gas Property Acquisition, Exploration and +Development Activities +Costs incurred by the Company in oil and gas property acquisition, exploration and development are presented below: +Years Ended December 31, +2003 +2002 +2001 +Property acquisition cost: +Proved undeveloped properties +$ 6,167,800 +1,892,700 +3,670,500 +Producing properties +33,946,600 +240,000 +75,700 +Development costs +30,630,100 +16,429,400 +35,411,900 +$70,744,500 +18,562,100 +39,158,100 +The proved reserves attributable to the development costs in the above table were 27,719,000 Mcf and 517,000 bbls for 2003, 19,607,000 Mcf and 130,000 bbls for 2002, and 23,896,000 Mcf and 715,000 bbls for 2001 (amounts unaudited). Of the above development costs incurred for the years ended December 31, 2003, 2002 and 2001 the amounts of $4,289,600, $2,699,500 and $7,026,900, respectively, were incurred to develop proved undeveloped properties from the prior year end. +Property acquisition costs include costs incurred to purchase, lease or otherwise acquire a property. Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells and to provide facilities to extract, treat, gather and store oil and gas. +(Continued) +F-21 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +(15) Oil and Gas Capitalized Costs +Aggregate capitalized costs for the Company related to oil and gas exploration and production activities with applicable accumulated depreciation, depletion and amortization are presented below: +December 31, +2003 +2002 +Proved properties: +Tangible well equipment +$133,356,900 +114,431,800 +Intangible drilling costs +110,087,300 +64,973,600 +Undeveloped properties +7,576,900 +4,208,800 +Capitalized asset retirement cost +537,800 +- +251,558,900 +183,614,200 +Less accumulated depreciation, +depletion and amortization +64,205,100 +50,664,600 +$187,353,800 +132,949,600 +(16) Results of Operations for Oil and Gas Producing Activities +The results of operations for oil and gas producing activities (excluding marketing) are presented below: +Years Ended December 31, +2003 +2002 +2001 +Revenue: +Oil and gas sales +$47,021,600 +22,857,100 +25,887,900 +Expenses: +Production costs +10,212,500 +6,407,900 +6,012,400 +Depreciation, depletion and amortization +12,997,600 +11,149,000 +9,665,300 +23,210,100 +17,556,900 +15,677,700 +Results of operations for oil and gas +producing activities before provision +for income taxes +23,811,500 +5,300,200 +10,210,200 +Provision for income taxes +8,262,600 +1,538,400 +2,834,900 +Results of operations for oil and gas +producing activities (excluding corporate +overhead and interest costs) +$ 15,548,900 +3,761,800 +7,375,300 +Production costs include those costs incurred to operate and maintain productive wells and related equipment, including such costs as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance and other production taxes. In addition, production costs include administrative expenses and depreciation applicable to support equipment associated with these activities. +Depreciation, depletion and amortization expense includes those costs associated with capitalized acquisition, exploration and development costs, but does not include the depreciation applicable to support equipment. +The provision for income taxes is computed using the Company's effective tax rate. +(Continued) +F-22 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +(17) Net Proved Oil and Gas Reserves (Unaudited) +The proved reserves of oil and gas of the Company have been estimated by an independent petroleum engineer, Wright & Company, Inc. at December 31, 2003, 2002 and 2001. These reserves have been prepared in compliance with the Securities and Exchange Commission rules based on year end prices. An analysis of the change in estimated quantities of oil and gas reserves, all of which are located within the United States, is shown below: +Oil (BBLS) +2003 +2002 +2001 +Proved developed and undeveloped reserves: +Beginning of year +2,073,000 +2,126,000 +2,166,000 +Revisions of previous estimates +533,000 +124,000 +(176,000 ) +Beginning of year as revised +2,606,000 +2,250,000 +1,990,000 +New discoveries and extensions: +Rocky Mountain Region +517,000 +130,000 +715,000 +Dispositions to partnerships +(112,000) +(80,000) +(384,000) +Acquisitions: +Rocky Mountain Region +307,000 +- +- +Production +(289,000 ) +(227,000 ) +(195,000 ) +End of year +3,029,000 +2,073,000 +2,126,000 +Proved developed reserves: +Beginning of year +1,849,000 +1,801,000 +1,527,000 +End of year +2,889,000 +1,849,000 +1,801,000 +Gas (MCF) +2003 +2002 +2001 +Proved developed and undeveloped reserves: +Beginning of year +128,851,000 +118,608,000 +118,640,000 +Revisions of previous estimates +4,394,000 +1,469,000 +(8,694,000 ) +Beginning of year as revised +133,245,000 +120,077,000 +109,946,000 +New discoveries and extensions: +Rocky Mountain Region +27,719,000 +19,607,000 +23,896,000 +Dispositions to partnerships +(4,410,000) +(4,792,000) +(9,263,000) +Acquisitions: +Michigan Basin +265,000 +4,000 +- +Rocky Mountain Region +32,169,000 +75,000 +2,000 +Appalachian Basin +722,000 +342,000 +112,000 +Production +(8,712,000 ) +(6,462,000 ) +( 6,085,000 ) +End of year +180,998,000 +128,851,000 +118,608,000 +Proved developed reserves: +Beginning of year +94,847,000 +88,477,000 +92,131,000 +End of year +134,936,000 +94,847,000 +88,477,000 +(Continued) +F-23 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +(18) Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves (Unaudited) +Summarized in the following table is information for the Company with respect to the standardized measure of discounted future net cash flows relating to proved oil and gas reserves. Future cash inflows are computed by applying year-end prices of oil and gas relating to the Company's proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the statutory rate in effect at the end of each year to the future pretax net cash flows, less the tax basis of the properties and gives effect to permanent differences, tax credits and allowances related to the properties. +As of December 31, +2003 +2002 +2001 +Future estimated revenues +$1,088,415,000 +$548,949,000 +$317,515,000 +Future estimated production costs +(250,735,000) +(143,878,000) +(98,538,000) +Future estimated development costs +(65,275,000) +(50,971,000) +(45,323,000) +Future estimated income tax expense +(265,707,000 ) +(105,876,000 ) +(50,360,000 ) +Future net cash flows +506,698,000 +248,224,000 +123,294,000 +10% annual discount for estimated +timing of cash flows +(289,408,000 ) +( 149,755,000 ) +( 76,855,000 ) +Standardized measure of discounted future +estimated net cash flows +$217,290,000 +$98,469,000 +$46,439,000 +The following table summarizes the principal sources of change in the standardized measure of discounted future estimated net cash flows: +Years Ended December 31, +2003 +2002 +2001 +Sales of oil and gas production, net of +production costs +$(36,810,000) +$(16,449,000) +$(19,876,000) +Net changes in prices and production costs +162,422,000 +143,574,000 +(140,487,000) +Extensions, discoveries and improved recovery, +less related cost +114,533,000 +39,347,000 +25,942,000 +Dispositions to partnerships +(12,936,000) +(6,940,000) +(28,935,000) +Acquisitions +139,078,000 +1,167,000 +189,000 +Development costs incurred during the period +30,630,000 +16,429,000 +35,412,000 +Revisions of previous quantity estimates +21,388,000 +3,318,000 +(23,818,000) +Changes in estimated income taxes +(159,831,000) +(55,516,000) +30,622,000 +Accretion of discount +(139,653,000 ) +(72,900,000 ) +62,751,000 +$118,821,000 +$ 52,030,000 +$(58,200,000) +It is necessary to emphasize that the data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein. +(Continued) +F-24 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +(19) Business Segments (Thousands) +PDC's operating activities can be divided into four major segments: drilling and development, natural gas marketing, oil and gas sales, and well operations. The Company drills natural gas wells for Company-sponsored drilling partnerships and retains an interest in each well. A wholly-owned subsidiary, Riley Natural Gas, engages in the marketing of natural gas to commercial and industrial end-users. The Company owns an interest in approximately 2,500 wells from which it derives oil and gas working interests. The Company charges Company-sponsored partnerships and other third parties competitive industry rates for well operations and gas gathering. Segment information for the years ended December 31, 2003, 2002 and 2001 is as follows: +2003 +2002 +2001 +REVENUES +Drilling and Development +$71,841 +57,149 +76,291 +Natural Gas Marketing +73,141 +46,366 +66,207 +Oil and Gas Sales +47,022 +22,857 +25,888 +Well Operations +7,348 +6,116 +5,604 +Unallocated amounts (1) +3,499 +2,854 +3,133 +Total +$202,851 +135,342 +177,123 +SEGMENT INCOME BEFORE INCOME TAXES +Drilling and Development +$10,564 +7,983 +10,291 +Natural Gas Marketing +689 +174 +458 +Oil and Gas Sales +23,812 +5,300 +10,112 +Well Operations +3,059 +2,788 +2,415 +Unallocated amounts (2) +General and Administrative expenses +(4,974) +(4,392) +(4,146) +Interest expense +(1,329) +(1,340) +(993) +Other (1) +3,103 +2,569 +2,946 +Total +$ 34,924 +13,082 +21,083 +SEGMENT ASSETS +Drilling and Development +$62,546 +31,279 +36,202 +Natural Gas Marketing +17,006 +16,641 +2,945 +Oil and Gas Sales +204,849 +145,591 +139,920 +Well Operations +11,602 +10,706 +11,975 +Unallocated amounts +Cash +800 +1,736 +422 +Other +9,919 +6,299 +8,388 +Total +$306,722 +212,252 +199,852 +EXPENDITURES FOR SEGMENT +LONG-LIVED ASSETS +Drilling and Development +$ 6,168 +1,800 +5,963 +Natural Gas Marketing +- +4 +- +Oil and Gas Sales +63,588 +16,670 +35,488 +Well Operations +2,944 +1,221 +839 +Unallocated amounts +342 +82 +371 +Total +$ 73,042 +19,777 +42,661 +(1) Includes interest on investments and partnership management fees in 2003, 2002 and 2001 and gain on sale +of assets in 2003, 2002 and 2001 which are not allocated in assessing segment performance. +(2) Items which are not allocated in assessing segment performance. +(Continued) +F-25 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +(20) Quarterly Financial Data (Unaudited ) +Summarized quarterly financial data for the years ended December 31, 2003 and 2002, are as follows: +2003 +Quarter +Year +First +Second +Third +Fourth +Revenues +$53,994,400 +$42,192,500 +$47,207,900 +$59,456,200 +$202,851,000 +Cost of operations +45,125,800 +33,836,200 +37,648,600 +45,013,400 +161,624,000 +Gross profit +8,868,600 +8,356,300 +9,559,300 +14,442,800 +41,227,000 +General and administrative expenses +1,177,700 +1,186,600 +1,377,300 +1,232,800 +4,974,400 +Interest expense +236,200 +259,800 +415,000 +418,100 +1,329,100 +Income before income taxes +7,454,700 +6,909,900 +7,767,000 +12,791,900 +34,923,500 +Income taxes +2,460,000 +2,280,300 +2,563,100 +4,802,400 +12,105,800 +Net income before cumulative +effect of change of change in +accounting principle +4,994,700 +4,629,600 +5,203,900 +7,989,500, +22,817,700 +Cumulative effect of change in +accounting principle (net of taxes) +(198,600) +- +- +- +(198,600) +Net income +$ 4,796,100 +$ 4,629,600 +$ 5,203,900 +$ 7,989,500 +$ 22,619,100 +Basic earnings per share +before accounting change +$ .32 +$ .29 +$ .33 +$.52 +$1.46 +Cumulative effect of change +in accounting principle +(.01) +.00 +.00 +.00 +(.01) +Basic earnings per share +$ .31 +$ .29 +$ .33 +$.52 +$1.45 +Diluted earnings per share before +accounting principle +$ .31 +$ .29 +$ .31 +$.49 +$1.40 +Cumulative effect of change in +accounting principle +(.01) +.00 +.00 +.00 +(.01) +Diluted earnings per share +$ .30 +$ .29 +$ .31 +$.49 +$1.39 +2002 +Quarter +Year +First +Second +Third +Fourth +Revenues +$36,085,900 +$33,468,900 +$28,148,600 +$37,638,500 +$135,341,900 +Cost of operations +30,644,300 +28,590,800 +25,557,500 +31,735,400 +116,528,000 +Gross profit +5,441,600 +4,878,100 +2,591,100 +5,903,100 +18,813,900 +General and administrative expenses +975,700 +1,027,400 +1,069,900 +1,318,900 +4,391,900 +Interest expense +239,300 +355,900 +399,800 +344,800 +1,339,800 +Income before income taxes +4,226,600 +3,494,800 +1,121,400 +4,239,400 +13,082,200 +Income taxes +1,297,600 +1,072,900 +232,400 +1,194,500 +3,797,400 +Net income +$2,929,000 +$ 2,421,900 +$ 889,000 +$ 3,044,900 +$ 9,284,800 +Basic earnings per share +$ .18 +$ .15 +$ .06 +$ .20 +$ .59 +Diluted earnings per share +$ .18 +$ .15 +$ .05 +$ .20 +$ .58 +Cost of operations include cost of oil and gas well drilling operations, cost of gas marketing activities, oil and gas production costs and depreciation, depletion and amortization. +F-26 +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS +AND RESERVES +Years Ended December 31, 2003, 2002 and 2001 +Column A +Column B +Column C +Column D +Column E +Additions, +Balance at +Charged to +Balance +Beginning +Costs and +at End +Description +of Period +Expenses +Deductions +of Period +Allowance for doubtful accounts deducted +from accounts and notes receivable in the +Balance sheet +2003 +$524,500 +$ - +$ 37,200 +$487,300 +2002 +$524,500 +$ - +$ - +$524,500 +2001 +$524,500 +$ - +$ - +$524,500 +F-27 \ No newline at end of file diff --git a/raw/filings/0000077877/2003/0000077877-04-000012/filing_metadata.csv b/raw/filings/0000077877/2003/0000077877-04-000012/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..30d71ffdb95a41cec7f371047dc1e101cdb98619 --- /dev/null +++ b/raw/filings/0000077877/2003/0000077877-04-000012/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 +0000077877,PDCE,"PDC ENERGY, INC.",10-K,2004-03-03,2003-12-31,2004-03-03T20:14:55.000Z,0000077877-04-000012,pdc10k2003.htm,PDC 10K,930005,0,0,https://www.sec.gov/Archives/edgar/data/77877/000007787704000012/pdc10k2003.htm,https://www.sec.gov/Archives/edgar/data/77877/000007787704000012/,2003,2003,1 diff --git a/raw/filings/0000077877/2003/0000077877-04-000012/item1.txt b/raw/filings/0000077877/2003/0000077877-04-000012/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..31224823d07107f5df031fe41a8fd764be1cd4d4 --- /dev/null +++ b/raw/filings/0000077877/2003/0000077877-04-000012/item1.txt @@ -0,0 +1,101 @@ +Item 1. Business +The Company is an independent energy company engaged primarily in the development, production and marketing of natural gas and oil. The Company has grown primarily through drilling and development activities, the acquisition of natural gas and oil producing wells and the expansion of its natural gas marketing activities. As of December 31, 2003, the Company operates over 2,500 wells located in the Appalachian basin, Michigan, and the Rocky Mountain Region, with gross proved reserves of 468 billion cubic feet equivalent of natural gas ("Bcfe", based on one barrel of oil equals 6 thousand cubic feet equivalent of natural gas ("Mcfe")) of which the Company's share is 199 Bcfe. The Company's share of production for the fourth quarter of 2003 averaged 34,000 Mcfe per day compared to 21,000 Mcfe per day during the fourth quarter of 2002. +The Company's operations are divided into three regions, the Appalachian Basin, Michigan, and the Rocky Mountain Region. The Company has conducted operations in Appalachian Basin since its inception in 1969, in Michigan Basin since 1997, and the Rocky Mountain Region since 1999. During 2003 approximately 19% of production was generated by Appalachian Basin wells, 18% by Michigan Basin wells and 63% by Rocky Mountain wells. As of the end of 2003, the Company's total proved reserves were located as follows: Appalachian Basin 21%, Michigan 13% and Rocky Mountain Region 66%. The majority of the Company's undeveloped reserves are in the Rocky Mountain Region and the planned drilling for 2004 will be focused in that area. +In all three regions the Company has historically targeted shallow, developmental natural gas reserves for development. In some areas of the Rocky Mountain Region, Michigan and the Appalachian Basin the wells also produce oil in conjunction with natural gas. +The Company owns Riley Natural Gas (RNG), a natural gas marketing company, which aggregates and resells natural gas developed by the Company and other producers. This allows the Company to diversify its operations beyond natural gas drilling and production. RNG has established relationships with many of the natural gas producers in the Appalachian Basin and has significant expertise in the natural gas end-user market. In addition, RNG has extensive experience in the use of hedging strategies, which the Company utilizes to manage the financial impact on the Company of changes in the price of natural gas and oil. +Since 1984, the Company has sponsored limited partnerships formed to engage in drilling operations. The Company typically purchases a 20% ownership interest in these drilling limited partnerships. In 2003, the Company, through four public drilling partnerships, raised $78.3 million making it the sponsor of the largest public oil and gas partnership program in the United States as it has been for the last several years. The drilling programs have provided the Company with access to the capital resources necessary to expand its drilling opportunities and to maintain the infrastructure necessary to support such activities. +Available Information +The Company's Internet address is www.petd.com. Electronic copies of the Company's annual report on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, and amendments to those reports are available free of charge by visiting the "Financial Information" section of www.petd.com. These reports are posted as soon as reasonably practicable after they are electronically filed with the Securities and Exchange Commission. Additionally, information including the Company's Code of Business Conduct and Ethics is also available at the site. +Industry Overview +Natural gas is the second largest energy source in the United States, after liquid petroleum. The estimated 22.1 Tcf of natural gas consumed in 2003 represented approximately 23% of the total energy used in the United States. Natural gas is consumed in the United States as follows: 36% by industrial end-users as feedstock for products such as plastic and fertilizer or as the energy source for producing products such as glass; 23% and 14% by residential and commercial end-users, respectively, for uses including heating, cooling and cooking; and 23% by utilities for the generation of electricity; and 4% for other users. (Source U.S. Energy Information Administration) +-2- +The Company believes that the market for natural gas will grow in the future. The demand for natural gas has increased due to four main factors: +Efficiency. Relative to other energy sources, natural gas losses during transportation from source to destination are slight, averaging only about 5% of the natural gas energy. +Environmentally favorable. Natural gas is the cleanest and most environmentally safe of the fossil fuels. +Safety. The delivery of natural gas is among the safest means of distributing energy to customers, as the natural gas transmission system is fixed and is located underground. +Price. The deregulation of the natural gas industry and a favorable regulatory environment have resulted in end-users' ability to purchase natural gas on a competitive basis from a greater variety of sources. +The Company believes that the foregoing factors, together with the increased availability of natural gas as a form of energy for residential, commercial and industrial uses, should increase the demand for natural gas as well as create new markets for natural gas. +Because local supplies of natural gas are inadequate to meet demand in certain sections of the country, the West Coast and the Northeast import natural gas from producing areas via interstate natural gas pipelines. The cost of transporting natural gas from the major producing areas to markets creates a price advantage for production located closer to the consuming regions. The natural gas industry in the Appalachian Basin and Michigan benefit from proximity to the northeastern United States. In contrast, much of the production in the Rocky Mountains is transported significant distances to end use markets. +During 1998 the Company began to establish a lease position in the Rocky Mountain producing region. The region is believed to hold substantial undeveloped natural gas resources. Recent and planned additions to pipeline capacity in the region have made the area more attractive for development. Gas from the region will generally sell for less than gas in the Appalachian and Michigan Basins, but costs of development are expected to be less. The Company currently has over 150 development locations in the Wattenberg field in the DJ Basin, and 22,500 acres available for development in the Piceance Basin, both basins are located in Colorado. +Business Strategy +The Company's objective is to expand its oil and natural gas reserves, production and revenues through a strategy that includes the following key elements: +Expand drilling operations. For its size, the Company has had one of the most active drilling programs in the country. The Company drilled 111 wells in 2003, compared to 70 wells in 2002. The Company believes that it will be able to drill a substantial number of new wells on its current undeveloped leased properties. As of December 31, 2003, the Company had leases or other development rights to 3,100 undeveloped acres in the Michigan Basin, 850 undeveloped acres in the Appalachian Basin and 181,400 undeveloped acres in the Rocky Mountain Region. As drilling activity increases, the Company benefits as its fixed costs may be spread over a larger number of wells. +Acquire producing properties. The Company's acquisition efforts are focused on properties that fit well within existing operations or in areas where the Company is establishing new operations. Acquisitions have historically offered economies in management and administration, and therefore the Company believes that it will be able to acquire more producing wells without incurring substantial increases in its administrative costs. +-3- +Pursue geographic expansion. The Company has proven its ability to drill and operate in geographically diverse domestic areas. In 1997, the Company expanded its operations from the Appalachian Basin, to Michigan and in late 1999 to the Rocky Mountains. In 2003 over 63% of the Company's production was generated in the Rocky Mountains. The Company plans to conduct the majority of its drilling activities in the Rocky Mountain region during 2004, but will continue to seek additional opportunities for expansion to areas where the Company's experience and expertise can be applied successfully. +Reduce risks inherent in oil and natural gas development and marketing. An integral part of the Company's strategy has been and will continue to be to concentrate on shallow development (rather than exploratory) drilling, and geographical diversification to reduce risk levels associated with natural gas and oil production. Development drilling is less risky than exploratory drilling and is likely to generate cash returns more quickly. The focus on shallow wells builds on the Company's knowledge and experience, and also provides greater investment diversification than an equal investment in a smaller number of deeper and/or more expensive wells. Geographical diversification can help to offset possible weakness in the natural gas market or disappointing drilling results in one area. The Company believes that successful natural gas marketing is essential to profitable operations in a deregulated gas market. To further this goal, the Company has the expertise of RNG, an experienced natural gas marketer. The Company also uses natural gas and oil hedges to reduce the effects of volatility of energy prices. The Company intends to continue to expand its marketing capabilities to keep pace with the changing natural gas industry. +Exploration and Development Activities +The Company's development activities focus on the identification and drilling of new productive wells and the acquisition of existing producing wells from other producers. +Prospect Generation +The Company's staff of professional geologists is responsible for identifying areas with potential for economic production of natural gas and oil. These geologists have decades of cumulative experience drilling natural gas and oil wells. They utilize results from logs and other tools to evaluate existing wells and to predict the location of attractive new gas reserves. To further this process, the Company has collected and continues to collect logs, core data, production information and other raw data available from state and private agencies, other companies and individuals actively drilling in the regions being evaluated. From this information the geologists develop models of the subsurface structures and formations that are used to predict areas with prospects for economic development. +On the basis of these models, the geologists instruct the Company's land department to obtain available natural gas leaseholds, farmouts and other development rights in these prospective areas. These rights are then obtained, if possible, by the Company's land department or contract landmen under the direction of the Company's land manager. In most cases, the Company pays a lease bonus and annual rental payments, converting, upon initiation of production, to a royalty on gross production revenue in return for obtaining the leases. In addition overriding royalty payments may be made to third parties in conjunction with the acquisition of drilling rights initially leased by others. As of December 31, 2003, the Company had leasehold rights to approximately 185,350 acres available for development. See--"Properties--Oil and Natural Gas Leases." +Drilling Activities +When prospects have been identified and leased, the Company develops these properties by drilling wells. In 2003, the Company drilled a total of 110 development wells all of which were successfully completed as producing wells. During the fourth quarter the Company drilled one exploratory well in Alabama which was dry and according to Successful Efforts Accounting was expensed as an exploratory dry hole. Such dry hole cost amounted to $332,000. Typically, the Company will act as driller-operator for these prospects, entering into contracts with partnerships, primarily Company-sponsored partnerships, and other entities that are interested in exploration or development of the prospects. The Company generally retains an interest in each well it drills. See "Financing of Drilling Activities." +-4- +Much of the work associated with drilling, completing and connecting wells, including drilling, fracturing, logging and pipeline construction, is performed by subcontractors specializing in those operations, as is common in the industry. A large part of the material and services used by the Company in the development process is acquired through competitive bidding by approved vendors. The Company also directly negotiates rates and costs for services and supplies when conditions indicate that such an approach is warranted. As the prices paid to the Company by its investor partners for the Company's services are frequently fixed before the wells are drilled or are determined solely on the well depth, the Company is subject to the risk that prices of goods or services used in the development process could increase, rendering its contracts with its investor partners less profitable or unprofitable. In addition, problems encountered in the process can substantially increase development costs, sometimes without recourse for the Company to recover its costs from its partners. To minimize these risks, the Company seeks to lock in its development costs in advance of drilling and, when possible, at the time of negotiation and execution of its investor partnership agreements. +Acquisitions of Producing Properties +In addition to drilling new wells, the Company continues to pursue opportunities to purchase existing wells from other producers and greater ownership interests in the wells it operates. Generally, outside interests purchased include a majority interest in the wells and well operations. +During the second quarter of 2003, the Company purchased 166 wells in the Denver Julesburg Basin in northeastern Colorado from Williams Production RMT Company for $28 million. The Company estimates the acquisition included approximately 22.6 billion cubic feet (Bcf) of proved developed producing (PDP) and 3.4 Bcf of proved developed non-producing reserves (PDNP), all of which is natural gas. +During the fourth quarter of 2003, the Company purchased from one of its joint venture partners in the Denver-Julesburg Basin in Weld County, Colorado approximately 3.1 billion cubic feet equivalent (Bcfe) of proved developed producing reserves from interests in 20.6 net wells (230 gross) and 1.8 Bcfe of proved developed non-producing reserves from interests in 17 net wells (183 gross). The purchase price was $5.2 million. +During the fourth quarter of 2003, the Company purchased 97 gross wells (73 net) wells in the Denver-Julesburg Basin located in northeast Colorado and northwestern Kansas for $6.0 million. This purchase adds approximately 4.5 billion cubic feet equivalent (Bcfe) of proved developed producing and proved developed non-producing reserves to the Company's oil and gas reserves along with 100,000 acres of oil and gas leases. +Certain well interests in its Company sponsored partnerships were also purchased in 2003, 2002 and 2001. +-5- +Production +The following table shows the Company's net production in Bbls of crude oil and in Mcf of natural gas and the costs and weighted average selling prices thereof, for the last five years. +Year Ended December 31, +2003 +2002 +2001 +2000 +1999 +Production(1): +Oil(MBbls) +289 +227 +195 +109 +8 +Natural Gas (MMcf) +8,712 +6,462 +6,085 +5,737 +3,451 +Equivalent MMcfs(2) +10,449 +7,824 +7,255 +6,391 +3,499 +Average sales price: +Oil (per Bbl) +$29.39 +$24.41 +$22.53 +$29.99 +$18.75 +Natural gas (per Mcf)(3) +$4.42 +$2.68 +$3.53 +$2.74 +$2.46 +Average production cost (lifting cost) +per equivalent Mcf(4) +$0.98 +$0.82 +$0.83 +$0.66 +$0.69 +---------- +(1) Production as shown in the table is net to the Company and is determined by multiplying the gross production volume of properties in which the Company has an interest by the percentage of the leasehold or other property interest owned by the Company. +(2) A ratio of energy content of natural gas and oil (six Mcf of natural gas equals one barrel of oil) was used to obtain a conversion factor to convert oil production into equivalent Mcfs of natural gas. +(3) The Company utilizes commodity-based derivative instruments as hedges to manage a portion of its exposure to price volatility of its natural gas sales. The effect of hedges on the average sales price of natural gas for the years ended December 31, 2003, 2002, 2001, 2000 and 1999 was $(0.09), $0.02, $(0.56), $(0.91), and $(0.01), respectively. +(4) Production costs represent oil and gas operating expenses which include severance and advalorem taxes as reflected in the financial statements of the Company. See Oil and Gas Production Costs in Management's Discussion and Analysis. +Well Operations +The Company currently operates approximately 1,492 wells in the Appalachian Basin, 204 wells in the Michigan Basin and 834 wells in the Rocky Mountain Region. The Company's ownership interest in these wells ranges from 0% to 100%, and, on average, the Company has an approximate 52% ownership interest in the wells it operates. +The Company is paid a monthly operating fee for each well it operates for outside owners including the limited partnerships sponsored by the Company. The fee is competitive with rates charged by other operators in the area. The fee covers monthly operating and accounting costs, insurance and other recurring costs. The Company may also receive additional compensation for special non-recurring activities, such as reworks and recompletions. +Transportation +Natural gas wells are connected by pipelines to natural gas markets. Over the years, the Company has developed extensive gathering systems in some of its areas of operations. The Company also continues to construct new trunklines as necessary to provide for the marketing of natural gas being developed from new areas and to enhance or maintain its existing systems. +The Company is paid a transportation fee for natural gas that is moved by other shippers through these pipeline systems. In many cases the Company has been able to receive higher natural gas prices as a result of its ability to move natural gas to more attractive markets through this pipeline system, to the benefit of both the Company and its investor partners. +-6- \ No newline at end of file diff --git a/raw/filings/0000077877/2003/0000077877-04-000012/item13.txt b/raw/filings/0000077877/2003/0000077877-04-000012/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..cf0528ea38ec3dcf60928f85bd38801eda2f3f4c --- /dev/null +++ b/raw/filings/0000077877/2003/0000077877-04-000012/item13.txt @@ -0,0 +1,2 @@ +Item 13. Certain Relationships and Related Transactions +The response to this item is set forth herein in Note 8 in the Notes to Consolidated Financial Statements and under "Election of Directors - Interest of Management in Certain Transactions," in the Company's definitive proxy statement for its 2004 annual meeting of stockholders filed or to be filed with the Commission on or before April 30, 2004. \ No newline at end of file diff --git a/raw/filings/0000077877/2003/0000077877-04-000012/item9a.txt b/raw/filings/0000077877/2003/0000077877-04-000012/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..4c9e1e83746d40b146e815fcf79b4147f6b0543d --- /dev/null +++ b/raw/filings/0000077877/2003/0000077877-04-000012/item9a.txt @@ -0,0 +1,3 @@ +Item 9A Controls and Procedures +Under the supervision and with the participation of the Company's management, including the Company's Chief Executive Officer and Chief Financial Officer, the Company has evaluated the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Exchange Act Rule 13a-14(c)) as of the end of the period covered by this annual report on Form 10-K, and, based on their evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these disclosure controls and procedures are effective in all material respects, including those to ensure that information required to be disclosed in reports filed or submitted under the Securities Exchange Act is recorded, processed, summarized, and reported, within the time periods specified in the Commission's rules and forms, and is accumulated and communicated to management, including the Company's Chief Executive Officer and Chief Financial Officer, as appropriate to allow for timely disclosure. There have been no significant changes in our internal controls or in other factors that could significantly affect these controls in the fourth quarter and subsequent to the date of their evaluation. +PART III \ No newline at end of file diff --git a/raw/filings/0000077877/2003/0000077877-04-000012/rp_note.txt b/raw/filings/0000077877/2003/0000077877-04-000012/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2003/0000077877-04-000012/rpt_disclosure.txt b/raw/filings/0000077877/2003/0000077877-04-000012/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..cf0528ea38ec3dcf60928f85bd38801eda2f3f4c --- /dev/null +++ b/raw/filings/0000077877/2003/0000077877-04-000012/rpt_disclosure.txt @@ -0,0 +1,2 @@ +Item 13. Certain Relationships and Related Transactions +The response to this item is set forth herein in Note 8 in the Notes to Consolidated Financial Statements and under "Election of Directors - Interest of Management in Certain Transactions," in the Company's definitive proxy statement for its 2004 annual meeting of stockholders filed or to be filed with the Commission on or before April 30, 2004. \ No newline at end of file diff --git a/raw/filings/0000077877/2004/0000077877-05-000019/filing.txt b/raw/filings/0000077877/2004/0000077877-05-000019/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..4cd2f40107f8289625575b76796b8fda38bd9277 --- /dev/null +++ b/raw/filings/0000077877/2004/0000077877-05-000019/filing.txt @@ -0,0 +1,6820 @@ +10-K +1 +pdc10k20041.htm +CONFORMED COPY +CONFORMED COPY +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 +Commission File Number 0-7246 +[ ] Transition +Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 +for the transaction period from to +PETROLEUM +DEVELOPMENT CORPORATION +(Exact name of +registrant as specified in its charter) +Nevada +95-2636730 +(State or other jurisdiction of +(I.R.S. Employer +incorporation or organization) +Identification No.) +103 East Main +Street, Bridgeport, West Virginia 26330 +(Address of +principal executive offices) (zip code) +Registrant's +telephone number, including area code (304) +842-3597 +SECURITIES +REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: NONE +SECURITIES +REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: +Petroleum +Development Corporation Common Stock, $.01 par value +(Title of class) +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 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 +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 definition in Rule 12b-2 of the Exchange Act). Yes X No +As of March 21, 2005, 16,589,824 shares of the +Registrant's Common Stock were issued and outstanding, and the aggregate market +value of such shares held by non-affiliates of the Registrant on June 30, 2004, +the last business day of the Registrant's most recently completed second +quarter was $318,343,540 (based on the last traded price of $27.42). +DOCUMENTS +INCORPORATED BY REFERENCE +Document +Form 10-K Part III +Proxy +Items 10, 11, 12, +and 13 +(except as +presented herein) +PART I +Item 1. Business +Petroleum +Development Corporation is an independent energy company engaged primarily in +the development, production and marketing of natural gas and oil. Since it +began oil and gas operations in 1969, the Company has grown primarily through +drilling and development activities, the acquisition of producing natural gas +and oil wells and the expansion of its natural gas marketing activities. As of +December 31, 2004, the Company operates approximately 2,700 wells located in +the Appalachian basin, Michigan, and the Rocky Mountain Region, with gross +proved reserves of 523 billion cubic feet equivalent of natural gas ("Bcfe", +based on one barrel of oil equals 6 thousand cubic feet equivalent of natural +gas ("Mcfe")) of which the Company's share is 217 Bcfe. The Company's share of +production for the fourth quarter of 2004 averaged 34,500 Mcfe per day. +Business Segments +The Company's +operations are divided into four segments for management and reporting purposes. +(See Consolidated Financial Statements, Note 19. Business Segments) +Drilling and Development +The Company drills +wells not only for itself, but also for other investor partners. When the +company drills wells for others it earns a profit above the cost of the wells. +The Drilling and Development segment records the payments received from others +as revenue and the related costs as expenses. +Since 1984, the +Company has sponsored limited partnerships formed to engage in drilling +operations. The Company typically purchases a 20% ownership interest in these +drilling limited partnerships. In 2004, the Company, through four public +drilling partnerships, raised $100 million making it the sponsor of the largest +public oil and gas partnership program in the United States as it has been for +the last several years. With the partnerships as a drilling partner the Company +has been able to expand its drilling opportunities, reduce its drilling risk +through greater diversification, and to share the costs of the infrastructure +necessary to support such activities. +Natural Gas Marketing +The Company's +wholly-owned subsidiary, Riley Natural Gas (RNG), purchases, aggregates and +resells natural gas developed by the Company and other producers. This allows +the Company to diversify its operations beyond natural gas drilling and +production. RNG has established relationships with many of the natural gas +producers in the Appalachian Basin and has significant expertise in the natural +gas end‑user market. In addition, RNG has extensive experience in the use +of hedging strategies, which the Company utilizes to help manage the financial +impact on the Company and its Partnerships of changes in the price of natural +gas and oil. RNG also manages the marketing of oil and gas for the Company's +wells outside the Appalachian Basin, but does not market gas or oil for +non-affiliated producers in those areas. +Oil and Gas Sales +Revenue from the +sale of oil and natural gas from the Company's interest in oil and gas wells is +reported in this segment. The Company has interests in approximately 2,700 +wells ranging from a few percent to 100 percent. During 2004 approximately 14% +of the Company's production was generated by Appalachian Basin wells, 14% by +Michigan Basin wells and 72% by Rocky Mountain wells. As of the end of 2004, +the Company's total proved reserves were located as follows: Appalachian Basin 19%, +Michigan 12% and Rocky Mountain Region 69%. The majority of the Company's +undeveloped reserves are in the Rocky Mountain Region and the planned drilling +for 2005 will be focused in that area. +Well Operations +The Company operates +almost all of the approximately 2,700 wells in which it owns an interest. When +it owns less than 100 percent of the working interest in a well, it charges the +other owners a competitive operating fee for operating the well. These +revenues and the associated costs are reflected in the Well Operations segment. +Areas of Operations +The Company's +operations are divided into three regions, the Appalachian Basin, Michigan, and +the Rocky Mountain Region. The Company has conducted operations in Appalachian +Basin since its inception in 1969, in Michigan since 1997, and in the Rocky +Mountain Region since 1999. +In all three regions +the Company has historically targeted shallow (less than 10,000 feet), +developmental natural gas reserves for development. In some areas of the Rocky +Mountain Region, Michigan and the Appalachian Basin the wells also produce oil +in conjunction with natural gas. Recently the Company has begun to drill to +progressively deeper targets in the Rocky Mountain Region. In particular it +has drilled several wells with depths of more than 12,000 feet. The Company's +management believes these deeper wells offer the possibility of significantly +greater reserves and production than shallow wells, although they are also more +expensive to drill. In addition the probability of encountering problems when +drilling a deep well is generally greater than when drilling a shallow well. +With increasing costs for and declining availability of proved developed drilling +locations, the Company's management believes the additional risk associated +with exploratory drilling is justified by the potential to generate additional +proved locations at a significantly lower cost than would be required to +purchase proved undeveloped locations. +Business Strategy +The Company's primary +objective is to increase shareholder value by expanding its oil and natural gas +reserves, production and revenues through a strategy that includes the +following key elements: +Drill and Develop +Drilling new wells, +particularly shallow, developmental natural gas wells, has been the mainstay of +the Company's drilling program for a number of years. The Company drilled 158 +wells in 2004, compared to 111 wells in 2003. In addition the Company seeks to maximize +the value of its existing wells through a program of well recompletions and +infill drilling in areas where attractive opportunities exist. The Company's +management believes that it will be able to drill a substantial number of new +wells on its current undeveloped leased properties. As of December 31, 2004, +the Company had leases or other development rights to +1,700 undeveloped acres in the Michigan Basin, 10,000 undeveloped acres in the northern +Appalachian Basin and 152,830 undeveloped acres in the Rocky Mountain Region. The Company also has about 40 Wattenberg Field wells +that it plans to recomplete in 2005, and the new wells it has drilled since +1999 in the field will be available for recompletions beginning in 2006. +To support future +development activities the Company began an exploratory drilling program in +2004 that it plans to continue in 2005. The goal of the exploration program is +to develop several significant new areas for the Company to include in its +future development drilling programs. +Acquire +The Company's +acquisition efforts are focused on producing properties that fit well within +existing operations or in areas where the Company is establishing new operations +and that have most of their value in producing wells, behind pipe reserves or +high quality proved undeveloped locations. Acquisitions have historically +offered economies in management and administration, and the Company's +management believes that it can acquire and manage more producing wells without +incurring substantial increases in its administrative costs. +Diversify and Focus +With operations in +the Rocky Mountains, Michigan and the Appalachian Basin, the Company has proven +its ability to grow through operations in geographically diverse areas. While +these areas provide geographic diversification, within each area the Company +has concentrated positions that lend themselves to effective development and +operation. The Company plans to conduct the majority of its drilling +activities in the Rocky Mountain region during 2005, but will continue to seek +additional opportunities for expansion in areas where the Company's experience +and expertise can be applied successfully. +Manage Risk +The Company seeks +opportunities to reduce the risks inherent in the oil and gas industry in a +variety of ways. For a number of years an integral part of the Company's +strategy has been to concentrate on development drilling and geographical +diversification to reduce risk levels associated with natural gas and oil drilling, +production and markets. Development drilling is less risky than exploratory +drilling and is likely to generate cash returns more quickly. Development +drilling will remain the foundation of our drilling activities in 2005. However +Company's management believes the increasing cost of high quality development +locations has made exploratory drilling more attractive. Exploratory wells +have the potential of identifying new development opportunities at a +significantly lower cost than the current cost of proven locations. While successful +exploratory efforts could add to the Company's future drilling opportunities at +favorable costs, under the successful efforts method of accounting, exploratory +dry holes are expensed at the time it is recognized that they are unproductive. +This could result in greater short term expenses and a reduction in the +near-term profitability of the Company. +To help offset the +relatively high business risk inherent in the oil and gas industry the company +maintains a conservative financial structure. The Company's management +believes that successful natural gas marketing is essential to profitable +operations in a deregulated gas market. To further this goal, the Company's +utilizes its marketing subsidiary, Riley Natural Gas, to manage the marketing +of the Company's oil and natural gas and its commodity hedges. This allows the +Company to maintain better control over third party risk in sales and hedging +activities. The Company uses natural gas and oil hedges to reduce the effects +of volatility of energy prices. +Available Information Posted on the Company's Website +The Company's +Internet address is www.petd.com. Electronic copies of the Company's annual report +on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, +and amendments to those reports are available free of charge by visiting the +"Financial Information" section of www.petd.com . These reports are posted as soon as reasonably +practicable after they are electronically filed with the Securities and +Exchange Commission. Additionally, information including the Company's press +releases, current drilling program sales, Bylaws, Committee Charters, Code of +Business Conduct and Ethics, Shareholder Communication Policy, Board Nomination +Procedures and the Whistleblower and Qualified Legal Compliance Committee +Hotline is also available at the site. +Industry Overview +Natural gas is the +second largest energy source in the United States, after liquid petroleum. The +estimated 21.9 Tcf of natural gas consumed in 2004 represented approximately 23% +of the total energy used in the United States. Natural gas is consumed in the +United States as follows: 35% by industrial end-users as feedstock for products +such as plastic and fertilizer or as the energy source for producing products +such as glass; 24% and 15% by residential and commercial end-users, +respectively, for uses including heating, cooling and cooking; and 25% by +utilities for the generation of electricity; and 1% for other users. (Source U.S. Energy Information Administration) +The Company's +management believes that the market for natural gas will continue to grow in +the future. Natural gas is the cleanest and most environmentally safe of the +fossil fuels. Relative to other energy sources, natural gas usage and losses +during transportation from source to destination are slight, averaging only +about 3% of the natural gas energy. The delivery of natural gas is among the +safest means of distributing energy to customers, as the natural gas +transmission system is fixed and is located underground. +The deregulation of +the natural gas industry and a favorable regulatory environment have resulted +in end-users' ability to purchase natural gas on a competitive basis from a +greater variety of sources. Increasing international demand for petroleum +combined with supply constraints drove oil prices to record high levels in +2004. Continuing increases in world energy demand appear likely in 2005 and +beyond. This makes natural gas more competitive in domestic markets as a +replacement for oil and increases the value of domestic oil and natural gas +reserves. +The Company's +management believes that the foregoing factors, together with the increased +availability of natural gas as a form of energy for residential, commercial and +industrial uses, should increase the demand for natural gas as well as create +new markets for natural gas even at prices that are high by historical +standards. +Because local +supplies of natural gas are inadequate to meet demand in sections of the +country, areas including the West Coast and the Northeast import natural gas +from producing areas via interstate natural gas pipelines. The cost of +transporting natural gas from the major producing areas to markets creates a +price advantage for production located closer to the consuming regions. Natural +gas producers in the Appalachian Basin and Michigan benefit from proximity to +the northeastern United States. +In contrast, much of +the production in the Rocky Mountains is transported significant distances to +end use markets. As a result the price received for gas in the Rocky Mountains +is generally less than the price received in areas closer to the primary +consuming areas. The Rocky Mountain region is believed to hold substantial +undeveloped natural gas resources. Recent and planned additions to pipeline +capacity in the region have made the area more attractive for development. +Although gas from the region will generally sell for less than gas in the +Appalachian and Michigan Basins, development costs may be less. +Operations +Exploration and Development Activities +The Company's +development activities focus on the identification and drilling of new +productive wells, the acquisition of existing producing wells from other +producers, and maximizing the value of the Company's current properties through +infill drilling, recompletions, and other production enhancements. +Prospect Generation +The Company's staff +of professional geologists is responsible for identifying areas with potential +for economic production of natural gas and oil. These geologists have decades +of cumulative experience evaluating prospects and drilling natural gas and oil +wells. They utilize results from logs, seismic data and other tools to evaluate +existing wells and to predict the location of economically attractive new gas +reserves. To further this process, the Company has collected and continues to +collect logs, core data, production information and other raw data available +from state and private agencies, other companies and individuals actively +drilling in the regions being evaluated. From this information the geologists +develop models of the subsurface structures and formations that are used to +predict areas with prospects for economic development. +On the basis of +these models, the geologists instruct the Company's land department to obtain +available natural gas leaseholds, farmouts and other development rights in +these prospective areas. These rights are then obtained, if possible, by the +Company's land department or contract landmen under the direction of the +Company's land manager. In most cases, the Company pays a lease bonus and +annual rental payments, converting, upon initiation of production, to a royalty +on gross production revenue in return for obtaining the leases. In addition +overriding royalty payments may be made to third parties in conjunction with +the acquisition of drilling rights initially leased by others. As of December +31, 2004, the Company had leasehold rights to approximately 164,530 acres +available for development. See--"Properties--Oil and Natural Gas Leases." +Drilling Activities +When prospects have +been identified and leased, the Company develops these properties by drilling +wells. In 2004, the Company drilled a total of 157 development wells of which 153 +were successfully completed as producing wells. Typically, the Company will act +as driller‑operator for these prospects, frequently selling interests in +the wells to partnerships, primarily Company‑sponsored partnerships, and +other entities that are interested in exploration or development of the prospects. +The Company retains an interest in each well it drills. +The Company also +drilled one exploratory well in 2004 and plans additional exploratory wells in +2005. As of the date of this report the exploratory well had been completed +and testing was underway but the well had not been classified as successful or +dry. Testing of the well was suspended in January due to lease restrictions on +the Federal lease. We expect to resume testing in the second quarter. If the +well is determined to be a dry hole, its cost will be expensed in the period +when the determination is made as required by the successful efforts method of +accounting. The cost of the well as of January 31, 2005 is $4,362,000. +Currently the Company plans to retain most if not all of the working interest +in the exploratory wells, since the Company partnerships focus on developmental +activities and are allowed only limited participation in exploratory drilling. +See "Financing of Company Drilling and Development Activities" And +"Drilling and Development Activities Conducted for Company Sponsored +Partnerships." +Much of the work +associated with drilling, completing and connecting wells, including drilling, +fracturing, logging and pipeline construction is performed under the Company's +direction by subcontractors specializing in those operations, as is common in +the industry. When judged advantageous, material and services used by the +Company in the development process are acquired through competitive bidding by +approved vendors. The Company also directly negotiates rates and costs for +services and supplies when conditions indicate that such an approach is +warranted. As the prices paid to the Company by its drilling partnerships for +the Company's services are frequently fixed before the wells are drilled or are +determined based primarily on the well depth, the Company is subject to the +risk that prices of goods or services used in the development process could +increase, rendering its contracts with its investor partners less profitable or +unprofitable. In addition, problems encountered in the process can +substantially increase development costs, sometimes without recourse for the +Company to recover its costs from its partners. To minimize these risks, the +Company seeks to lock in its development costs in advance of drilling when +possible. +Drilling Activity +The following table +summarizes the Company's development drilling activity for the last five years. +There is no correlation between the number of productive wells completed during +any period and the aggregate reserves attributable to those wells. The +Company's exploratory wells drilled in the past five years (not included in the +table data) consist of one well (1.0 net) drilled in 2004 and one dry hole (1.0 +net) drilled in 2003. The exploratory well drilled in 2004 was completed late +in the year. Testing was commenced in December and suspended in January due to +lease restrictions on the federal lease that restrict access for heavy +equipment including service units during certain periods of the year to protect +wildlife and the environment. The lease restrictions would not prevent the +operation of producing wells during this period. Testing is scheduled to +resume late in the second quarter. The well cannot be classified as dry or +productive until testing is complete. If it is classified as dry the cost will +be expensed in the period when the determination is made as required by the successful +efforts method of accounting. +Development Wells +Drilled +Total +Productive +Dry +Drilled +Net +Drilled +Net +Drilled +Net +2000 +97 +27.39 +97 +27.39 +- +- +2001 +141 +40.00 +135 +37.94 +6 +2.06 +2002 +70 +13.71 +70 +13.71 +- +- +2003 +110 +28.51 +110 +28.51 +- +- +2004 +157 +43.00 +153 +42.40 +4 +.60 +Total +575 +152.61 +565 +149.95 +10 +2.66 +Financing of Company Drilling and Development Activities +The Company conducts +development drilling activities for its own account and acts as operator for +other investors. When conducting activities for its own account the Company +uses cash flow from operations and capital provided from its long term credit +facility to fund its share of operations. The Company currently has activated +$60 million of a $100 million credit facility with J.P. Morgan Chase Bank, NA and +BNP Paribas, however it has more than adequate reserves to allow the full line +to be activated if necessary. As of the end of 2004 the Company had $21 +million outstanding of the facility. +Drilling and Development Activities Conducted for Company +Sponsored Partnerships +In addition to wells +and interests in wells that it drills for itself, the company also acts as +operator for other oil and gas investors. Historically these other investors +have included individuals, corporations, partnerships formed by non-affiliated +parties and other investors. Currently the Company's drilling partners consist +primarily of public partnerships sponsored by the Company. A part of the Company's +drilling investment is used to purchase an interest in each partnership. +In 1984, the Company +began sponsoring private drilling limited partnerships, and, in 1989, the +Company began to offer partnership interests in public drilling programs registered +with the SEC. The Company's public partnerships had $100 million in +subscriptions in 2004, $78.3 million in subscriptions in 2003, and $56.9 +million in subscriptions in 2002. The Company generally invests, as its equity +contribution to each drilling partnership, an additional sum approximating 22% +of the aggregate subscriptions received for that particular drilling +partnership and receives a 20% working interest in each partnership. As a +result, the Company is subject to substantial cash commitments at the closing +of each drilling partnership, during 2004 this amounted to $22.0 million.. The +funds received from these programs are restricted to use in future drilling +operations. While funds were received by the Company pursuant to drilling +contracts in the years indicated, the Company recognizes revenues from drilling +operations on the percentage of completion method as the wells are drilled, +rather than when funds are received. Substantially all of the Company's +drilling and development funds are now received from partnerships in which the +Company serves as managing general partner. However, because wells produce for +a number of years, the Company continues to serve as operator for a number of +unaffiliated parties. +The process begins +when the Company enters into a development agreement with an investor partner, +pursuant to which the Company agrees to assign some or all of its rights in the +property to be drilled to the partnership or other entity. The partnership or +other entity thereby becomes owner of a working interest in the property. +The Company's drilling +contracts with its investor partners have historically taken many different +forms. Currently the agreements can be classified as on a +"footage-based" rate, whereby the Company receives drilling and +completion payments based on the depth of the well. Basic drilling and +completion operations are performed on a footage‑based rate, with leases +being contributed at the Company's cost. The Company may also purchase a +working interest in the subject properties. In its financial reporting the +Company reports only its share of reserves, production, revenue and costs +associated with wells in which other investors participate. The level of +the Company's third party drilling and development activity is dependent upon +the amount of subscriptions in its public drilling partnerships and investments +from other partnerships or other joint venture partners. Accepting investments +from third party investors and Company sponsored partnerships enables the +Company to diversify its holdings, thereby reducing the risk of the Company's +investments. Additionally, the Company benefits through such arrangements by +its receipt of fees for its management services and/or through an increased +share in the revenues produced by the developed properties. The Company's +management believes that investments in drilling activities, whether through +Company‑sponsored partnerships or other sources, are influenced in part +by the favorable treatment that such investments enjoy under the federal income +tax laws. No assurance can be given that the Company will continue to have +access to funds generated through these financing vehicles. +Purchases of Producing Properties +In addition to +drilling new wells, the Company continues to pursue opportunities to purchase +existing wells from other producers as well as greater ownership interests in +the wells it operates. Generally, outside interests purchased include a +majority interest in the wells and the right to operate the wells. Although the +Company made several offers to purchase properties during 2004, other potential +purchasers outbid the Company, therefore none of its offers were successful. +Several purchases made during 2003 as described below did contribute to the +Company's increased production in 2004. +During the second +quarter of 2003, the Company purchased 166 wells in the Denver Julesburg-Basin +in northeastern Colorado from Williams Production RMT Company for $28 million. +The Company estimates the acquisition included approximately 22.6 billion cubic +feet (Bcf) of proved developed producing (PDP) and 3.4 Bcf of proved developed +non-producing reserves (PDNP) at the time of acquisition, all of which is +natural gas. +During the fourth +quarter of 2003, the Company purchased from one of its unaffiliated joint +venture partners in the Denver-Julesburg Basin in Weld County, Colorado +approximately 3.1 billion cubic feet equivalent (Bcfe) of proved developed +producing reserves from interests in 20.6 net wells (230 gross) and 1.8 Bcfe of +proved developed non-producing reserves from interests in 17 net wells (183 +gross). The purchase price was $5.2 million. +During the fourth +quarter of 2003, the Company purchased from an unaffiliated party 97 gross +wells (73 net) in the Denver-Julesburg Basin located in northeast Colorado and northwestern Kansas for $6.0 million. This purchase included approximately 4.5 +billion cubic feet equivalent (Bcfe) of proved developed producing and proved +developed non-producing reserves along with 100,000 acres of oil and gas +leases. +The Company also +purchased a number of small interests in its partnerships from investor +partners wishing to sell their interests in 2004, 2003 and 2002. +Production +The following table +shows the Company's net production in barrels (Bbl) of crude oil and in +thousand cubic feet (Mcf) of natural gas and the costs and weighted average +selling prices thereof, for the last five years. +Year Ended December 31, +2004 +2003 +2002 +2001 +2000 +Production(1): +Oil(MBbl) +381 +289 +227 +195 +109 +Natural Gas (MMcf) +10,372 +8,712 +6,462 +6,085 +5,737 +Equivalent Mmcf(2) +12,658 +10,449 +7,824 +7,255 +6,391 +Average sales price: +Oil (per Bbl)(3) +$35.13 +$29.39 +$24.41 +$22.53 +$29.99 +Natural gas (per Mcf)(3) +$5.26 +$4.42 +$2.68 +$3.53 +$2.74 +Average production cost (lifting cost) +Per equivalent Mcf(4) +$1.18 +$0.98 +$0.82 +$0.83 +$0.66 +---------- +(1) Production +as shown in the table is net to the Company and is determined by multiplying +the gross production volume of properties in which the Company has an interest +by the percentage of the leasehold or other property interest owned by the +Company. +(2) A +ratio of energy content of natural gas and oil (six Mcf of natural gas equals +one barrel of oil) was used to obtain a conversion factor to convert oil +production into equivalent Mcf of natural gas. +(3) The +Company utilizes commodity-based derivative instruments as hedges to manage a +portion of its exposure to price volatility of its natural gas and oil sales. +The effect of hedges on the average sales price of natural gas per Mcf for the +years ended December 31, 2004, 2003, 2002, 2001, and 2000 was $(0.09), $(0.09), +$0.02, $(0.56),and $(0.91) respectively. The effect of hedges on the average +sales price of oil per barrel for the year ended December 31, 2004 was +$(2.71). There was no oil hedged in earlier years. +(4) Production +costs represent oil and gas operating expenses which include severance and ad +valorem taxes as reflected in the financial statements of the Company. See Oil +and Gas Production Costs in Management's Discussion and Analysis. +Natural Gas Sales +Natural gas produced +by the Company's well interests is sold under contracts with terms ranging from +one month to three years. Virtually all of +the Company's contract pricing provisions are tied to a market index, with +certain adjustments based on, among other factors, whether a well delivers to a +gathering or transmission line, quality of natural gas and prevailing supply +and demand conditions, so that the price of the natural gas fluctuates to +remain competitive with other available natural gas supplies. As a result, the +Company's revenues from the sale of natural gas will suffer if market prices +decline and benefit if they increase. The Company's management believes that +the pricing provisions of its natural gas contracts are customary in the +industry. +The Company sells +its natural gas to industrial end-users, utilities, other gas marketers, and +other wholesale gas purchasers. Two customers accounted for 13.8% and 11.1% +respectively of the Company's revenues from oil and gas sales (7.8% and 6.3% of +total revenues) in 2004. Three customers accounted for 16.6%, 17.4% and 14.3%, +respectively of the Company's revenues from oil and gas sales (9.8%, 10.3% and +8.5% of total revenues) in 2003. Two customers accounted for 21.1% and 11.0%, +respectively of the Company's revenues from oil and gas sales (10.8% and 5.6% +of total revenues) in 2002. No other single purchaser of the Company's natural +gas accounted for 10% or more of the Company's total revenues during 2004, +2003, and 2002. +At December 31, +2004, natural gas produced by the Company sold at prices per Mcf ranging from +$0.90 to $12.22, depending upon well location, the date of the sales contract +and other factors. The weighted net average price of natural gas sold by the +Company during 2004 was $5.26 per Mcf. +In general, the +Company, together with its marketing subsidiary, RNG, has been and expects to +continue to be able to produce and sell natural gas from its wells without +significant curtailment by providing natural gas to purchasers at competitive +prices. Open access transportation through the country's interstate pipeline +system makes a broad range of markets accessible to the Company. Whenever +feasible the Company obtains access to multiple pipelines and markets from each +of its gathering systems seeking the best available market for its natural gas +at any point in time. +Oil Sales +Some of the +Company's wells in the Appalachian Basin and Michigan, and most of the +Company's wells in Wattenberg field in Colorado, produce oil in addition to +natural gas. At the end of 2004 oil was about 9% of the Company's total +equivalent reserves. +The Company is +currently able to sell all the oil that it can produce under existing sales +contracts with petroleum refiners and marketers. The Company does not refine +any of its oil production. The Company's crude oil production is sold to +purchasers at or near the Company's wells under short-term purchase contracts +at prices and in accordance with arrangements that are customary in the oil +industry. One purchaser accounted for 7.6%, 11.0% and 11.9% of the Company's +revenues from oil and gas sales (4.3%, 6.5% and 5.6% of total revenues) in 2004, +2003, and 2002. At December 31, 2004, oil produced by the Company sold at +prices ranging from $37.25 to $49.00 per barrel, +depending upon the location and quality of oil. In 2004, the weighted net +average price per barrel of oil sold by the Company was $35.13. +Oil production is +subject to many of the same operating hazards and environmental concerns as +natural gas production, but is also subject to the risk of oil spills. Federal +regulations require certain owners or operators of facilities that store or +otherwise handle oil, such as the Company, to procure and implement Spill Prevention, +Control and Counter-measures ("SPCC") plans relating to the possible discharge +of oil into surface waters. The Oil Pollution Act of 1990 ("OPA") +subjects owners of facilities to strict joint and several liability for all +containment and cleanup costs and certain other damages arising from oil +spills. Noncompliance with OPA may result in varying civil and criminal penalties +and liabilities. Operations of the Company are also subject to the Federal +Clean Water Act and analogous state laws relating to the control of water +pollution, which laws provide varying civil and criminal penalties and +liabilities for release of petroleum or its derivatives into surface waters or +into the ground. +Natural Gas Marketing +The Company's +natural gas marketing activities involve the purchase of natural gas from other +producers and the sale of that natural gas along with natural gas produced by +the Company. The Company's management believes that in a deregulated market, +successful natural gas marketing is an essential component of profitable +operations. A variety of factors affect the market for natural gas, including +the availability of other domestic production, natural gas imports, the +availability and price of alternative fuels, the proximity and capacity of +natural gas pipelines, general fluctuations in the supply and demand for +natural gas and the effects of state and federal regulations on natural gas +production and sales. The natural gas industry also competes with other +industries in supplying the energy and fuel requirements of industrial, +commercial and individual customers. +RNG, a wholly owned +subsidiary, is a natural gas marketing company that specializes in the +purchase, aggregation and sale of natural gas production in the Company's +operating areas. RNG markets natural gas produced by the Company and also +purchases natural gas from other producers and resells to utilities, end users +or other marketers. The employees of RNG have extensive knowledge of natural +gas markets in the Company's areas of operations. Such knowledge assists the +Company in maximizing its prices as it markets natural gas from +Company-operated wells. The gas is marketed to natural gas utilities, pipelines +and industrial and commercial customers, either directly through the Company's +gathering system, or utilizing transportation services provided by regulated +interstate pipeline companies. +Hedging Activities +The Company utilizes +commodity-based derivative instruments as hedges to manage a portion of the +exposure to price volatility stemming from its oil and natural gas sales and +marketing activities. These instruments consist of NYMEX-traded natural gas +futures and option contracts for Appalachian, Michigan and eastern Colorado production, and CIG (Colorado Interstate Gas Index)-based contracts for other Colorado production and NYMEX traded oil futures and option contracts for Colorado oil production. +The contracts hedge committed and anticipated natural gas purchases and sales +and anticipated oil sales, generally forecasted to occur within the next two +year period. Company policy prohibits the use of natural gas or oil futures or +options for speculative purposes and permits utilization of hedges only if +there is an underlying physical position. +The Company through +RNG has extensive experience with the use of financial hedges to reduce the +risk and impact of natural gas price changes. These hedges are used by RNG to +coordinate fixed and variable priced purchases and sales, and by the Company to +"lock in" fixed prices from time to time for the Company's share of +production, and to establish "floors" and "ceilings" or +"collars" on the possible range of the price realized for the sale of +natural gas and oil. In order for contracts to serve as effective hedges, the +derivatives must be highly effective in offsetting changes in cash flows of +hedged items. There must be sufficient correlation to the underlying hedged +transaction. While hedging can help provide price protection if spot prices +drop, hedges can also limit upside potential. +For unhedged natural +gas sales not subject to fixed price contracts, the Company is subject to price +fluctuations for natural gas sold in the spot market and under market index +contracts. The Company continues to evaluate the potential for reducing these +risks by entering into hedge transactions. In addition, the Company may also +close out any portion of hedges that may exist from time to time which may +result in a gain or loss on that hedge transaction. Generally the Company +hedges only a portion of its anticipated production, so some or all of the +production is subject to the full fluctuation of market pricing. +Well Operations +The +Company currently operates approximately 1,476 wells in the Appalachian Basin, +204 wells in the Michigan Basin and 991 wells in the Rocky Mountain Region. The +Company's ownership interest in these wells ranges from 0% to 100%, and, on +average, the Company has an approximate 51% ownership interest in the wells it +operates. +The Company is paid +a monthly operating fee for each well it operates for outside owners including +the limited partnerships sponsored by the Company. The fee is competitive with +rates charged by other operators in the area. The fee covers monthly operating +and accounting costs, insurance and other recurring costs. The Company may also +receive additional compensation for special non-recurring activities, such as +reworks and recompletions. +Transportation +Natural gas wells +are connected by pipelines to natural gas markets. Over the years, the Company +has developed gathering systems in some of its areas of operations. The Company +also continues to construct new trunk lines as necessary to provide for the +marketing of natural gas being developed from new areas and to enhance or +maintain its existing systems. +The Company is paid +a transportation fee for natural gas that is moved by other shippers through +these pipeline systems. In many cases the Company has been able to receive +higher natural gas prices as a result of its ability to move natural gas to +more attractive markets through this pipeline system, to the benefit of both +the Company and its investor partners. +Governmental Regulation +The Company's +business and the natural gas industry in general are heavily regulated. The +availability of a ready market for natural gas production depends on several +factors beyond the Company's control. These factors include regulation of +natural gas production, federal and state regulations governing environmental +quality and pollution control, the amount of natural gas available for sale, +the availability of adequate pipeline and other transportation and processing +facilities and the marketing of competitive fuels. State and federal +regulations generally are intended to protect consumers from unfair treatment, +control and reduce the risk to the public and workers from the drilling +completion, production and transportation of oil and natural gas, prevent waste +of natural gas, protect rights to produce natural gas between owners in a +common reservoir and control contamination of the environment. Pipelines are +subject to the jurisdiction of various federal, state and local agencies. In +the western part of the United States the federal and state governments own a +large percentage of the land and the rights to develop oil and natural gas. +Recently the Company has increased its positions in these types of leases. +Generally government leases are subject to additional regulations and controls +not commonly seen on private leases. The Company takes the steps necessary to +comply with applicable regulations both on its own behalf and as part of the +services it provides to its investor partnerships. The Company's management +believes that it is in substantial compliance with such statutes, rules, +regulations and governmental orders, although there can be no assurance that +this is or will remain the case. The following discussion of the regulation of +the United States natural gas industry is not intended to constitute a complete +discussion of the various statutes, rules, regulations and environmental orders +to which the Company's operations may be subject. +Regulation of Oil and Natural Gas Exploration and +Production +The Company's oil +and natural gas operations are subject to various types of regulation at the +federal, state and local levels. Prior to commencing drilling activities for a +well, the Company must procure permits and/or approvals for the various stages +of the drilling process from the applicable state and local agencies in the +state in which the area to be drilled is located. Such permits and approvals +include those for the drilling of wells, and such regulation includes +maintaining bonding requirements in order to drill or operate wells and +regulating the location of wells, the method of drilling and casing wells, the +surface use and restoration of properties on which wells are drilled, the +plugging and abandoning of wells and the disposal of fluids used in connection with +operations. The Company's operations are also subject to various conservation +laws and regulations. These include the regulation of the size of drilling and +spacing units or proration units and the density of wells which may be drilled +and the unitization or pooling of properties. In this regard, some states allow +the forced pooling or integration of tracts to facilitate exploration while +other states rely primarily or exclusively on voluntary pooling of lands and +leases. In areas where pooling is voluntary, it may be more difficult to form +units, and therefore, more difficult to develop a project if the operator owns +less than 100% of the leasehold. In addition, state conservation laws may +establish maximum rates of production from oil and natural gas wells, generally +prohibiting the venting or flaring of natural gas and imposing certain +requirements regarding the ratability of production. Where wells are to be +drilled on state or federal leases additional regulations and conditions may +apply. The effect of these regulations may limit the amount of oil and natural +gas the Company can produce from its wells and may limit the number of wells or +the locations at which the Company can drill. The regulatory burden on the oil +and natural gas industry increases the Company's costs of doing business and, +consequently, affects its profitability. In as much as such laws and +regulations are frequently expanded, amended and reinterpreted, the Company is +unable to predict the future cost or impact of complying with such regulations. +Regulation of Sales and Transportation of Natural Gas +Historically, the +transportation and sale for resale of natural gas in interstate commerce were +regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act +of 1978 (the "NGPA") and the regulations promulgated thereunder by +the Federal Energy Regulatory Commission (FERC). Maximum selling prices of +certain categories of natural gas sold in "first sales," whether sold +in interstate or intrastate commerce, were regulated pursuant to the NGPA. The +Natural Gas Wellhead Decontrol Act (the "Decontrol Act") removed, as +of January 1, 1993, all remaining federal price controls from natural gas sold +in "first sales" on or after that date. FERC's jurisdiction over +natural gas transportation was unaffected by the Decontrol Act. While sales by +producers of natural gas and all sales of crude oil, condensate and natural gas +liquids can currently be made at market prices, Congress could reenact price +controls in the future. +The Company's sales +of natural gas are affected by the availability, terms and cost of +transportation. The price and terms for access to pipeline transportation are +subject to extensive regulation. In the past, FERC has undertaken various +initiatives to increase competition within the natural gas industry. As a +result of initiatives like FERC Order No.636, issued in April 1992, the +interstate natural gas transportation and marketing system was substantially +restructured to remove various barriers and practices that historically limited +non‑pipeline natural gas sellers, including producers, from effectively +competing with interstate pipelines for sales to local distribution companies +and large industrial and commercial customers. The most significant provisions +of Order No.636 require that interstate pipelines provide transportation +separate or "unbundled" from their sales service, and require that +pipelines provide firm and interruptible transportation service on an open +access basis that is equal for all natural gas suppliers. In many instances, +the result of Order No.636 and related initiatives have been to substantially +reduce or eliminate the interstate pipelines' traditional role as wholesalers +of natural gas in favor of providing only storage and transportation services. +Another effect of regulatory restructuring is the greater transportation access +available on interstate pipelines. In some cases, producers and marketers have +benefited from this availability. However, competition among suppliers has +greatly increased and traditional long‑term producer-pipeline contracts +are rare. Furthermore, gathering facilities of interstate pipelines are no +longer regulated by FERC, thus allowing gatherers to charge higher gathering +rates. +Additional proposals +and proceedings that might affect the natural gas industry occur frequently in +the Congress, FERC, state commissions, state legislatures, 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 FERC and Congress will continue. The Company cannot determine to +what extent future operations and earnings of the Company will be affected by +new legislation, new regulations, or changes in existing regulation, at +federal, state or local levels. +Environmental Regulations +The Company's +operations are subject to numerous laws and regulations governing the discharge +of materials into the environment or otherwise relating to environmental +protection. Public interest in the protection of the environment has increased +dramatically in recent years. The trend of more expansive and stricter +environmental legislation and regulations could continue. To the extent laws +are enacted or other governmental action is taken that restricts drilling or +imposes environmental protection requirements that result in increased costs +and reduced access to the natural gas industry in general, the business and +prospects of the Company could be adversely affected. +The Company +generates wastes that may be subject to the Federal Resource Conservation and +Recovery Act ("RCRA") and comparable state statutes. The U.S. +Environmental Protection Agency ("EPA") and various state agencies +have limited the approved methods of disposal for certain hazardous and +nonhazardous wastes. Furthermore, certain wastes generated by the Company's +operations that are currently exempt from treatment as "hazardous +wastes" may in the future be designated as "hazardous wastes," +and therefore be subject to more rigorous and costly operating and disposal +requirements. +The Company +currently owns or leases numerous properties that for many years have been used +for the exploration and production of oil and natural gas. Although the Company's +management believes that it has utilized good operating and waste disposal +practices, prior owners and operators of these properties may not have utilized +similar practices, and hydrocarbons or other wastes may have been disposed of +or released on or under the properties owned or leased by the Company or on or +under locations where such wastes have been taken for disposal. These +properties and the wastes disposed thereon may be subject to the Comprehensive +Environmental Response, Compensation and Liability Act ("CERCLA"), +RCRA and analogous state laws as well as state laws governing the management of +oil and natural gas wastes. Under such laws, the Company 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) or to perform remedial plugging operations to +prevent future contamination. +CERCLA and similar +state laws impose liability, without regard to fault or the legality of the +original conduct, on certain classes of persons that are considered to have +contributed to the release of a "hazardous substance" into the +environment. These persons include the owner or operator of the disposal site +or sites where the release occurred and companies that disposed of or arranged +for the disposal of the hazardous substances found at the site. Persons who are +or were responsible for release of 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, and 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. +The Company's +operations may be subject to the Clean Air Act ("CAA") and comparable +state and local requirements. Amendments to the CAA were adopted in 1990 and +contain provisions that may result in the gradual imposition of certain +pollution control requirements with respect to air emissions from the +operations of the Company. The EPA and states have been developing regulations +to implement these requirements. The Company may be required to incur certain +capital expenditures in the next several years for air pollution control +equipment in connection with maintaining or obtaining operating permits and +approvals addressing other air emission-related issues. +The Company's +expenses relating to preserving the environment during 2004 were not +significant in relation to operating costs and the Company expects no material +change in 2005. Environmental regulations have had no materially adverse effect +on the Company's operations to date, but no assurance can be given that +environmental regulations will not, in the future, result in a curtailment of +production or otherwise have a materially adverse effect on the Company's +business, financial condition or results of operations. +Operating Hazards and Insurance +The Company's +exploration and production operations include a variety of operating risks, +including the risk of fire, explosions, blowouts, cratering, pipe failure, +casing collapse, abnormally pressured formations, and environmental hazards +such as gas leaks, ruptures and discharges of toxic gas, the occurrence of any +of which could result in substantial losses to the Company due to injury and +loss of life, severe damage to and destruction of property, natural resources +and equipment, pollution and other environmental damage, clean‑up +responsibilities, regulatory investigation and penalties and suspension of +operations. The Company's pipeline, gathering and distribution operations are +subject to the many hazards inherent in the natural gas industry. These hazards +include damage to wells, pipelines and other related equipment, and surrounding +properties caused by hurricanes, floods, fires and other acts of God, +inadvertent damage from construction equipment, leakage of natural gas and +other hydrocarbons, fires and explosions and other hazards that could also +result in personal injury and loss of life, pollution and suspension of +operations. +Any significant +problems related to its facilities could adversely affect the Company's ability +to conduct its operations. In accordance with customary industry practice, the +Company maintains insurance against some, but not all, potential risks; +however, there can be no assurance that such insurance will be adequate to +cover any losses or exposure for liability. The occurrence of a significant +event not fully insured against could materially adversely affect the Company's +operations and financial condition. The Company cannot predict whether +insurance will continue to be available at premium levels that justify its +purchase or whether insurance will be available at all. +Competition +The Company's management believes that its exploration, +drilling and production capabilities and the experience of its management and +professional staff generally enable it to compete effectively. The Company +encounters competition from numerous other oil and natural gas companies, +drilling and income programs and partnerships in all areas of its operations, +including drilling and marketing natural gas and obtaining desirable natural +gas leases. Many of these competitors possess larger staffs and greater +financial resources than the Company, which may enable them to identify and +acquire desirable producing properties and drilling prospects more +economically. The Company's ability to explore for oil and natural gas +prospects and to acquire additional properties in the future depends upon its +ability to conduct its operations, to evaluate and select suitable properties +and to consummate transactions in this highly competitive environment. The +Company competes with a number of other companies that offer interests in +drilling partnerships with a wide range of investment objectives and program +structures. Competition for investment capital for both public and private +drilling programs is intense. The Company also faces intense competition in the +marketing of natural gas from competitors including other producers as well as +marketing companies. Also, international developments and the possible improved +economics of domestic natural gas exploration may influence other companies to +increase their domestic oil and natural gas exploration. Furthermore, +competition among companies for favorable prospects can be expected to +continue, and it is anticipated that the cost of acquiring properties may +increase in the future. During 2004 the industry experienced increased demand +for drilling services and supplies. This is resulting in increasing costs, and +in some cases the demand for supplies and services exceeds the available +supplies. This can result in higher well costs and delays in the execution of +planned drilling operations. Factors affecting competition in the oil and natural +gas industry include price, location, availability, quality and volumes +produced. The Company's management believes that it can compete effectively in +the oil and natural gas industry on each of the foregoing factors. +Nevertheless, the Company's business, financial condition or results of +operations could be materially adversely affected by competition. +Employees +As of December 31, +2004, the Company had 120 employees, including 17 in finance and data +processing, 8 in administration, 12 in exploration and development, 78 in +production and 5 in natural gas marketing. The Company's engineers, supervisors +and well tenders are responsible for the day-to-day operation of wells and +pipeline systems. In addition, the Company retains subcontractors to perform +drilling, fracturing, logging, and pipeline construction functions at drilling +sites. The Company's employees act as supervisors of the subcontractors. +The Company's +employees are not covered by a collective bargaining agreement. The Company +considers relations with its employees to be excellent. +Risks Related to the Oil and Natural Gas +Industry and the Company +Oil and natural +gas prices fluctuate unpredictably and a decline in oil and natural gas prices +can significantly affect the Company's financial results and impede its growth. +The +Company's revenue, profitability and cash flow depend in large part upon the +prices and demand for oil and natural gas. The markets for these commodities +are very volatile and even relatively modest drops in prices can significantly +affect the Company's financial results and impede its growth. Changes in oil +and natural gas prices have a significant impact on the value of the Company's +reserves and on its cash flow. Prices for oil and natural gas may fluctuate +widely in response to relatively minor changes in the supply of and demand for +oil and natural gas, market uncertainty and a variety of additional factors +that are beyond the Company's control, including national and international +economic and political factors and federal and state legislation. +Lower oil and natural gas prices may not +only decrease the Company's revenues , but also may reduce the amount of oil +and natural gas that the Company can produce economically. This may result in +the Company having to make substantial downward adjustments to its estimated +proved reserves. If this occurs or if the Company's estimates of development +costs increase, production data factors change or the Company's exploration +results deteriorate, successful efforts accounting rules may require us to +write down, as a non-cash charge to earnings, the carrying value of our oil and +natural gas properties for impairments. The +Company assesses impairment of capitalized costs of proved oil and gas +properties by comparing net capitalized costs to estimated undiscounted future +net cash flows on a field-by-field basis using expected prices. Prices utilized +in each year's calculation for measurement purposes and expected costs are held +constant throughout the estimated life of the properties. If net capitalized +costs exceed undiscounted future net cash flows, the measurement of impairment +is based on estimated fair value which would consider future discounted cash +flows. The Company may incur impairment charges in the future, which +could have a material adverse effect on its results of operations. +The Company's +estimated oil and gas reserves are based on many assumptions that may turn out +to be inaccurate. Any material inaccuracies in these reserve estimates or +underlying assumptions will materially affect the quantities and present value +of the Company's reserves. +No +one can measure underground accumulations of oil and natural gas in an exact +way. Oil and natural gas reserve engineering requires subjective estimates of +underground accumulations of oil and natural gas and assumptions concerning +future oil and natural gas prices, production levels, and operating and +development costs. As a result, estimated quantities of proved reserves and +projections of future production rates and the timing of development +expenditures may be inaccurate. The Company's estimates of oil and gas reserves +are prepared by Wright & Company (Wright), independent petroleum engineers, +using pricing, production, cost, tax and other information provided by the +Company. Over time, Wright may make material changes to reserve estimates +taking into account the results of actual drilling, testing, and production. Also, +Wright makes certain assumptions regarding future oil and natural gas prices, +production levels, and operating and development costs that may prove +incorrect. Any significant variance from these assumptions to actual figures +could greatly affect the estimates of reserves, the economically recoverable +quantities of oil and natural gas attributable to any particular group of +properties, the classifications of reserves based on risk of recovery, and +estimates of the future net cash flows. Some of our reserve estimates are made +without the benefit of a lengthy production history, which renders these +reserve estimates less reliable than estimates based on a lengthy production +history. Numerous changes over time to the assumptions on which the reserve +estimates are based, as described above, often result in the actual quantities +of oil and gas recovered being different from earlier reserve estimates. +The +present value of future net cash flows from the proved reserves is not +necessarily the same as the current market value of the estimated oil and +natural gas reserves (the Securities and Exchange Commission requires the use +of year end prices). The estimated discounted future net cash flows from proved +reserves are based on prices and costs in effect on the day of estimate. +However, actual future net cash flows from our oil and natural gas properties +also will be affected by factors such as actual prices we receive for oil and +natural gas, the amount and timing of actual production, supply of and demand +for oil and natural gas, and changes in governmental regulations or taxation. +The +timing of both our production and our incurrence of expenses in connection with +the development and production of oil and natural gas properties will affect +the timing of actual future net cash flows from proved reserves, and thus their +actual present value. In addition, the 10% discount factor we use when +calculating discounted future net cash flows may not be the most appropriate +discount factor based on interest rates in effect from time to time and risks +associated with us or the oil and natural gas industry in general. +Unless oil and +natural gas reserves are replaced as they are produced, the Company's reserves +and production will decline, which would adversely affect the Company's +business, financial condition and results of operations. +Producing +oil and natural gas reservoirs generally are characterized by declining +production rates that vary depending upon reservoir characteristics and other +factors. The rate of decline will change if production from existing wells +declines in a different manner than we have estimated and can change due to +other circumstances.Thus, the Company's future oil and natural gas reserves and +production and, therefore, its cash flow and income are highly dependent on +efficiently developing and exploiting the Company's current reserves and +economically finding or acquiring additional recoverable reserves. The Company +may not be able to develop, discover or acquire additional reserves to replace +our current and future production at acceptable costs. +Prospects +drilled by the Company may not yield natural gas or oil in commercially viable +quantities. +A +prospect is a property on which the Company's geologists have identified what +they believe, based on available information, to be indications of natural gas +or oil bearing rocks. However, the use of available data and other technologies +and the study of producing fields in the same area will not enable the +geologists to know conclusively prior to drilling and testing whether natural +gas or oil will be present or, if present, whether natural gas or oil will be +present in sufficient quantities to repay drilling or completion costs and generate +a profit. If a well is determined to be dry or uneconomic, which can occur even +though it contains some oil or gas reserves, it is classified as a dry hole and +must be plugged and abandoned in accordance with applicable regulations. This +generally results in the loss of the entire cost of drilling and completion to +that point, the cost of plugging, and lease costs associated with the +prospect. Even wells that are completed and placed into production may not +produce sufficient oil and gas to be profitable. If the Company drills a dry +hole or non-profitable well on current and future prospects, the profitability +of its operations will decline and the value of the Company will be reduced. In +sum, the cost of drilling, completing and operating any well is often uncertain +and new wells may not be productive. +The Company may +not be able to identify enough attractive prospects on a timely basis to meet +its own development needs and those of the partnerships it forms for investors, +which could limit the Company's development opportunities and/or force it to +reduce the partnership activity. +Our +geologists have identified a number of potential drilling locations on our +existing acreage. These drilling locations must be replaced as they are drilled +for the Company to continue to grow its reserves and production, and for it to +be able to continue its partnership drilling activities. The Company's ability +to identify and acquire new drilling locations depends on a number of +uncertainties, including the availability of capital, regulatory approvals, oil +and natural gas prices, competition, costs, drilling results, and the ability +of the Company's geologists to successfully identify potentially successful new +areas to develop. Because of these uncertainties, The Company's profitability +and growth opportunities may be limited by the timely availability of new +drilling locations, and it could be forced to terminate or curtail its +partnership activities because of a lack of suitable prospects for the +partnerships. +Drilling for +and producing oil and natural gas are high risk activities with many +uncertainties that could adversely affect the Company's business, financial +condition and results of operations. +Drilling +activities are subject to many risks, including the risk that wells will not +discover commercially productive reservoirs. Drilling for oil and natural gas +can be unprofitable, not only from dry holes, but from productive wells that do +not produce sufficient revenues to return a profit. In addition, drilling and +producing operations may be curtailed, delayed or canceled as a result of other +factors, including unusual or unexpected geological formations, pressures, +fires, blowouts, loss of drilling fluid circulation, title problems, facility +or equipment malfunctions, unexpected operational events, shortages or delivery +delays of equipment and services, compliance with environmental and other +governmental requirements, and adverse weather conditions. +Any of these risks can cause substantial +losses, including personal injury or loss of life, damage to or destruction of +property, natural resources and equipment, pollution, environmental +contamination or loss of wells and regulatory penalties. The Company maintains +insurance against various losses and liabilities arising from operations; +however, insurance against all operational risks is not available. +Additionally, the Company management may elect not to obtain insurance if the +cost of available insurance is excessive relative to the perceived risks +presented. Thus, losses could occur for uninsurable or uninsured risks or in +amounts in excess of existing insurance coverage. The occurrence of an event +that is not fully covered by insurance could have a material adverse impact on +the Company's business activities, financial condition and results of +operations. +Increased +drilling activity, particularly in the Rocky Mountain Region, may create a +shortage of drilling rigs, service providers, or materials forcing the Company +to curtail its drilling operations for itself and its partnerships thereby +reducing revenue and profits from new oil and gas wells and from the Company's +drilling and completion activities. +With high levels of oil and gas prices +many oil and gas companies have increased their levels of drilling and +completing new wells and reworking old wells. At the same time there is a +limited supply of drilling rigs, completion equipment and qualified personnel +to provide the services necessary to drill, complete and rework new wells. In +particular, the Rocky Mountain Region has seen a great increase in activity +over the past few years. If the demand for these goods and services continues +to increase shortages may develop, which could result in increased prices for +these goods and services or the Company's inability to complete all of the drilling +it has planned. This could result in decreased profitability for the Company +and the temporary or permanent loss of part or all of its partnership drilling +activity. +The +Company's drilling and development segment receives virtually all of its +revenue from the publicly registered partnerships it sponsors, and a reduction +or loss of that business could reduce or eliminate the revenue and profits +associated with those activities. +The Company's drilling activities are +dependent upon the capital raised by the Company as sponsor of SEC registered +limited partnerships. The Company sells oil and natural gas partnerships +through a network of non-affiliated NASD broker dealers. The largest of those +broker dealers sold about 11% of the partnership units in 2004. Investors in +the partnerships are interested in the tax deductions generated by the +intangible drilling costs and the cash flow generated by the partnerships. If +the tax laws were changed to reduce or eliminate the tax advantages, if the +cash flow from the partnerships were to decline due to weak wells or lower +energy prices, or if the brokers decide to stop offering our partnerships for +some other reason, the sales of the partnership units would decline, reducing +or eliminating the revenue and profits associated with the drilling and completion +business segment. +Under the +Successful Efforts accounting method used by the Company unsuccessful +exploratory wells must be expensed in the period when they are determined to be +non-productive which results in a reduction of net income and could have a +negative impact on the Company's stock price. +The +Company plans to increase its exploratory drilling in 2005 in order to identify +additional opportunities for future development. However the cost of +unsuccessful exploratory wells must be charged to expense in the period when +they are determined to be unsuccessful under the successful efforts method of +accounting used by the Company. In addition lease costs for acreage condemned +by the unsuccessful well must also be expensed. In contrast unsuccessful development +wells are capitalized as a part of the investment in the field where they are +located. Because exploratory wells generally are more likely to be +unsuccessful than development wells the Company anticipates that some or all of +its exploratory wells may not be productive. The costs of such unsuccessful +wells could result in a significant reduction in the Company's profitability in +periods when they are required to be expensed, which could have an adverse +effect on the Company's stock price. In addition unsuccessful wells will not +add to the Company's reserves or production. +Rising +finding and development costs may impair our profitability. +In order to continue to grow and maintain +its profitability, the Company must annually add new reserves exceeding its +yearly production at a finding and development cost that yields an acceptable +operating margin and depreciation, depletion and amortization rate. Without +cost effective exploration, development or acquisition activities, production, +reserves and profitability will decline over time. Given the relative maturity +of most gas basins in North America the cost of finding new reserves through +exploration and development operations has been increasing. The acquisition +market for natural gas properties has become extremely competitive among +producers for additional production and expanded drilling opportunities in North America. Acquisition values climbed toward historic highs during 2004 on a per unit +basis, particularly in the Rocky Mountain region, and the Company believes +these values may continue to increase in 2005. This increase in finding and +development costs is resulting in higher depreciation, depletion and +amortization rates. If the upward trend in finding and development costs +continues, the Company will be exposed to an increased likelihood of a +writedown in carrying value of its natural gas and oil properties in response +to falling prices, which would impair its profitability. +The Company's +development and exploration operations require substantial capital and it may +be unable to obtain needed capital or financing on satisfactory terms, which +could lead to a loss of properties and a decline in our natural gas and oil +reserves and production. +The +oil and natural gas industry is capital intensive. The Company makes and +expects to continue to make substantial capital expenditures in its business +and operations for the exploration for and development, production and +acquisition of oil and natural gas reserves. To date, the Company has financed capital +expenditures primarily with cash generated by operations and proceeds from bank +borrowings. Currently the Company intends to finance its capital expenditures +with cash flows from operations and its existing financing arrangements. Cash +flows from operations and access to capital are subject to a number of +variables, including the Company's proved reserves, the level of oil and +natural gas the Company is able to produce from existing wells, the prices at +which oil and natural gas are sold, and the Company's ability to acquire, +locate and produce new reserves. +If +the Company's revenues or the borrowing base under its revolving credit +facility decrease as a result of lower oil and natural gas prices, operating +difficulties, declines in reserves or for any other reason, it may have limited +ability to obtain the capital necessary to sustain its operations at planned +levels. +If +additional capital is needed, the Company may not be able to obtain debt or +equity financing on favorable terms, or at all. If cash generated by operations +or available under our revolving credit facility is not sufficient to meet our +capital requirements, the failure to obtain additional financing could result +in a curtailment of our operations relating to exploration and development of +our prospects, which in turn could lead to a possible loss of properties and a +decline in our natural gas and oil reserves. +The Company's +credit facility and other debt financing have substantial restrictions and +financial covenants and the Company may have difficulty obtaining additional +credit, which could adversely affect our operations. +The +Company will depend on its revolving credit facility for future capital needs. +The revolving credit facility restricts our ability to obtain additional +financing, make investments, lease equipment, sell assets and engage in +business combinations. We also are required to comply with certain financial +covenants and ratios. Our ability to comply with these restrictions and +covenants in the future is uncertain and will be affected by the levels of cash +flows from our operations and events or circumstances beyond our control. Our +failure to comply with any of the restrictions and covenants under the +revolving credit facility or other debt financing could result in a default +under those facilities, which could cause all of our existing indebtedness to +be immediately due and payable. +The +revolving credit facility limits the amounts we can borrow to a borrowing base +amount, determined by the lenders in their sole discretion, based upon +projected revenues from the oil and natural gas properties securing our loan. +The lenders can unilaterally adjust the borrowing base and the borrowings +permitted to be outstanding under the revolving credit facility. Outstanding +borrowings in excess of the borrowing base must be repaid immediately, or we +must pledge other oil and natural gas properties as additional collateral. We +do not currently have any substantial unpledged properties, and we may not have +the financial resources in the future to make any mandatory principal +prepayments required under the revolving credit facility. +A substantial +part of the Company's producing properties are located in the Rocky Mountains, +making it vulnerable to risks associated with operating in one major geographic +area. +The +Company's operations are becoming increasingly focused on the Rocky Mountain +region, which means its producing properties and new drilling opportunities are +geographically concentrated in that area. As a result, the Company, the success +of its operations, and its profitability may be disproportionately exposed to +the impact of delays or interruptions of production from existing or planned +new wells by significant governmental regulation, transportation capacity +constraints, curtailment of production, interruption of transportation, or +fluctuations in prices of oil and natural gas produced from the wells in the +region. +Seasonal +weather conditions and lease stipulations adversely affect the Company's +ability to conduct drilling activities in some of the areas where we operate. +Oil +and natural gas operations in the Rocky Mountains are adversely affected by +seasonal weather conditions and lease stipulations designed to protect various +wildlife. In certain areas, including parts of the Sand Wash and Piceance Basins, drilling and other oil and natural gas activities are restricted or +prohibited by lease stipulations, or prevented by weather conditions, for up to +6 months out of the year. This limits operations in those areas and can intensify +competition during those months for drilling rigs, oil field equipment, +services, supplies and qualified personnel, which may lead to periodic +shortages. These constraints and the resulting shortages or high costs could +delay operations and materially increase operating and capital costs and +therefore adversely affect profitability. +Properties that +the Company buys may not produce as projected and the Company may be unable to +determine reserve potential, identify liabilities associated with the properties +or obtain protection from sellers against them. +One +of the Company's growth strategies is to acquire producing oil and natural gas +reserves in its areas of operations and in new areas to help establish a base +of operations for further development. However, reviews of potential +acquisitions are inherently incomplete because it generally is not feasible to +review in depth every individual property. Ordinarily, the Company focuses +review efforts on the higher value properties and will sample the remainder. +However, even a detailed review of records and properties may not necessarily +reveal existing or potential problems, nor will it permit a buyer to become +sufficiently familiar with the properties to assess fully their deficiencies +and potential. Inspections may not always be performed on every well, and +environmental problems, such as ground water contamination, are not necessarily +observable or detectable even when an inspection is undertaken. Even when +problems are identified, the Company may choose to assume certain environmental +and other risks and liabilities in connection with acquired properties. +We have limited +control over activities on properties we do not operate, which could reduce our +production and revenues. +The +Company operates most of the wells in which it owns an interest. However it +also participates in some cases through joint operating agreements under which +it owns partial interests in oil and natural gas properties. If the Company +does not operate the properties in which it owns an interest, it does not have +control over normal operating procedures, expenditures or future development of +underlying properties. The failure of an operator to adequately perform +operations, or an operator's breach of the applicable agreements, could reduce +production and revenues. The success and timing of drilling and development +activities on properties operated by others therefore depends upon a number of +factors outside of the Company's control, including the operator's timing and +amount of capital expenditures, expertise and financial resources, inclusion of +other participants in drilling wells, and use of technology. +Market +conditions or operational impediments hinder access to oil and natural gas +markets or delay production. +Market +conditions or the unavailability of satisfactory oil and natural gas +transportation arrangements may hinder access to oil and natural gas markets or +delay production. The availability of a ready market for oil and natural gas +production depends on a number of factors, including the demand for and supply +of oil and natural gas and the proximity of reserves to pipelines and terminal +facilities. The Company's ability to market its production depends in +substantial part on the availability and capacity of gathering systems, pipelines +and processing facilities owned and operated by third parties. Failure to +obtain such services on acceptable terms could materially harm the Company's +business. We may be required to shut in wells for a lack of a market or because +of inadequacy or unavailability of natural gas pipeline, gathering system +capacity or processing facilities. If that were to occur, the Company would be +unable to realize revenue from those wells until production arrangements were +made to deliver the production to market. +Our hedging +activities could result in financial losses or could reduce our income. +To +achieve a more predictable cash flow, to reduce exposure to adverse +fluctuations in the prices of oil and natural gas and to allow our gas +marketing company to offer pricing options to gas sellers and purchasers, the +Company uses hedging arrangements for a portion of its oil and natural gas +production from its own wells, and for gas purchases and sales by its marketing +subsidiary. Hedging arrangements expose the Company to the risk of financial +loss in some circumstances, including when production, purchases or sales are +different than expected, the counter-party to the hedging contract defaults on +its contract obligations, or when there is a change in the expected differential +between the underlying price in the hedging agreement and actual prices +received. In addition, hedging arrangements may limit the benefit from +changes in the prices for oil and natural gas and may require the use of +Company resources to meet cash margin requirements. +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 the Company's overall credit +risk in that these entities may be similarly affected by changes in economic +and other conditions. In addition, the Company's oil and natural gas hedging +arrangements as well as the hedging arrangements of its marketing subsidiary +expose the Company to credit risk in the event of nonperformance by +counterparties. +The Company +depends on a limited number of key personnel who would be difficult to replace. +The Company depends on the performance of +our executive officers and other key employees. The loss of any member of +senior management or other key employees could negatively impact the Company's +ability to execute its strategy. The Company does not maintain key person life +insurance policies on any of its employees. +Competition in +the oil and natural gas industry is intense, which may adversely affect the +Company's ability to succeed. +The +oil and natural gas industry is intensely competitive, and the Company competes +with other companies that have greater resources. Many of these companies not +only explore for and produce oil and natural gas, but also carry on refining +operations and market petroleum and other products on a regional, national or +worldwide basis. These companies may be able to pay more for productive oil and +natural gas properties and exploratory prospects or define, evaluate, bid for +and purchase a greater number of properties and prospects than our financial or +human resources permit. In addition, these companies may have a greater ability +to continue exploration activities during periods of low oil and natural gas +market prices. Larger competitors may be able to absorb the burden of present +and future federal, state, local and other laws and regulations more easily +than the Company can, which would adversely affect the Company's competitive +position. The Company's ability to acquire additional properties and to +discover reserves in the future will be dependent upon its ability to evaluate +and select suitable properties and to consummate transactions in a highly +competitive environment. In addition, because of the many companies in our +industry have greater financial and human resources, the Company may be at a disadvantage +in bidding for exploratory prospects and producing oil and natural gas +properties. These factors could adversely affect the success of the Company's +operations and its profitability. +The Company is +subject to complex federal, state, local and other laws and regulations that +could adversely affect the cost, manner or feasibility of doing business. +The +Company's exploration, development, production and marketing operations are +regulated extensively at the federal, state and local levels. Environmental and +other governmental laws and regulations have increased the costs to plan, +design, drill, install, operate and abandon oil and natural gas wells. Under +these laws and regulations, the Company could also be liable for personal +injuries, property damage and other damages. Failure to comply with these laws +and regulations may result in the suspension or termination of operations and +subject the Company to administrative, civil and criminal penalties. Moreover, +public interest in environmental protection has increased in recent years, and +environmental organizations have opposed, with some success, certain drilling +projects. +Part of the regulatory environment +includes, in some cases, federal requirements for obtaining environmental +assessments, environmental impact studies and/or plans of development before +commencing exploration and production activities. In addition, the Company's +activities are subject to the regulation by oil and natural gas-producing +states of conservation practices and protection of correlative rights. These +regulations affect operations and limit the quantity of oil and natural gas +that can be produced and sold. A major risk inherent in our drilling plans is +the need to obtain drilling permits from state and local authorities. Delays in +obtaining regulatory approvals, drilling permits, 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 the Company's +ability to explore on or develop its properties. Additionally, the oil and +natural gas regulatory environment could change in ways that might +substantially increase the financial and managerial costs to comply with the +requirements of these laws and regulations and, consequently, adversely affect +profitability. Furthermore, the Company may be put at a competitive +disadvantage to larger companies in the industry who can spread these +additional costs over a greater number of wells and larger operating staff. See +"Business - Governmental Regulation - Regulation of Oil and Natural Gas +Exploration and Production" and "Business - Governmental Regulation - +Environmental Regulations" for a description of the laws and regulations that +affect us. +Item 2. Properties +Summary of Productive Wells +The table below shows the number of the Company's +productive gross and net wells at December 31, 2004. +Productive +Wells +Gas +Oil +Location +Gross +Net +Gross +Net +Colorado +964 +530.42 +- +- +Kansas +26 +18.00 +- +- +Michigan +197 +109.96 +7 +2.66 +North Dakota +- +- +1 +.20 +Pennsylvania +530 +168.71 +- +- +Tennessee +1 +0.71 +35 +13.62 +West Virginia +906 +516.76 +4 +1.72 +Total +2,624 +1,344.56 +47 +18.20 +Reserves +All of the Company's +oil and natural gas reserves are located in the United States. The Company's +approximate net proved reserves were estimated by Wright & Company Inc., +independent petroleum engineers ("Wright & Company"), to be +197,549,000 Mcf of natural gas and 3,316,000 Bbls of oil at December 31, 2004, 180,998,000 +Mcf of natural gas and 3,029,000 Bbls of oil at December 31, 2003, and 128,851,000 +Mcf of natural gas and 2,073,000 Bbls of oil at December 31, 2002. +The Company's +approximate net proved developed reserves were estimated, by Wright & +Company, to be 146,152,000 Mcf of natural gas and 3,190,000 Bbl of oil at +December 31, 2004, 134,936,000 Mcf of natural gas and 2,889,000 Bbls of oil at +December 31, 2003, and 94,847,000 Mcf of natural gas and 1,849,000 Bbls of oil +at December 31, 2002. +The Company's oil +and natural gas reserves by region are as follows as of December 31, 2004: +Oil +(Mbbl) +Gas +(Mmcf) +Natural Gas +Equivalent +(Mmcfe) +% +Proved +Developed Reserves +Appalachian +Basin +48 +41,384 +41,672 +25.21% +Michigan Basin +52 +24,895 +25,207 +15.25% +Rocky Mountain +Region +3,090 +79,873 +98,413 +59.54% +Total Proved +Developed Reserves +3,190 +146,152 +165,292 +100.00% +Proved +Undeveloped Reserves +Appalachian +Basin +0 +0 +0 +0.00% +Michigan Basin +0 +630 +630 +1.21% +Rocky Mountain +Region +126 +50,767 +51,523 +98.79% +Total Proved +Undeveloped +126 +51,397 +52,153 +100.00% +Total +Proved Reserves +Appalachian +Basin +48 +41,384 +41,672 +19.16% +Michigan Basin +52 +25,525 +25,837 +11.88% +Rocky Mountain +Region +3,216 +130,640 +149,936 +68.96% +Total Proved +Reserves +3,316 +197,549 +217,445 +100.00% +No major discovery +or other favorable or adverse event that would cause a significant change in +estimated reserves is believed by the Company to have occurred since December +31, 2004. Reserves cannot be measured exactly, as reserve estimates involve +subjective judgment. The estimates must be reviewed periodically and adjusted +to reflect additional information gained from reservoir performance, new +geological and geophysical data and economic changes. +The standardized +measure of discounted future estimated net cash flows attributable to the +Company's proved oil and gas reserves, giving effect to future estimated income +tax expenses, was estimated by Wright & Company to be $234.2 million as of +December 31, 2004, $217.3 million as of December 31, 2003, and $98.5 million as +of December 31, 2002. These amounts are based on December 31 prices in the respective +years. The values expressed are estimates only, and may not reflect realizable +values or fair market values of the natural gas and oil ultimately extracted +and recovered. The standardized measure of discounted future net cash flows may +not accurately reflect proceeds of production to be received in the future from +the sale of natural gas and oil currently owned and does not necessarily +reflect the actual costs that would be incurred to acquire equivalent natural +gas and oil reserves. +Net Proved Natural Gas and Oil Reserves +The proved reserves +of natural gas and oil of the Company as estimated by Wright & Company at +December 31, 2004 are set forth below. These reserves have been prepared in +compliance with the rules of the Securities and Exchange Commission (the +"SEC") based on December 31, 2004 prices. An analysis of the change +in estimated quantities of natural gas and oil reserves from January 1, 2004 to +December 31, 2004, all of which are located within the United States, is shown below: +Natural Gas (Mcf) +Oil (Bbl) +Proved developed and undeveloped reserves: +Beginning of year +180,998,000 +3,029,000 +Revisions of previous estimates +(10,635,000) +305,000 +Beginning of year as revised +170,363,000 +3,334,000 +New discoveries and extensions +Rocky Mountain region +40,716,000 +358,000 +Dispositions to partnerships +(4,240,000) +(12,000) +Acquisitions +Michigan Basin +96,000 +- +Rocky Mountain region +242,000 +17,000 +Appalachian basin +744,000 +- +Production +(10,372,000 ) +(381,000) +End of year +197,549,000 +3,316,000 +Proved developed reserves: +Beginning of year +134,936,000 +2,889,000 +End of year +146,152,000 +3,190,000 +Standardized Measure of Discounted Future Net Cash Flows +and Changes Therein Relating to Proved Natural Gas and +Oil +Reserves +Summarized in the +following table is information for the Company with respect to the standardized +measure of discounted future net cash flows relating to proved natural gas and +oil reserves. Future cash inflows are computed by applying year-end prices of +natural gas and oil relating to the Company's proved reserves to year-end +quantities of those reserves. Future production, development, site restoration +and abandonment costs are derived based on current costs, assuming continuation +of existing economic conditions. Future income tax expenses are computed by +applying the statutory rate in effect at December 31, 2004 to the future pretax +net cash flows, less the tax basis of the properties, and gives effect to +permanent differences, tax credits and allowances related to the properties. +As of +December 31, +2004 +Future estimated revenues +$1,298,394,000 +Future estimated production costs +(319,065,000) +Future estimated development costs +(95,498,000) +Future estimated income tax expense +(332,497,000 ) +Future net cash flows +551,334,000 +10% annual discount for estimated timing of cash flows +(317,099,000 ) +Standardized measure of discounted +future estimated net cash flows +$ 234,235,000 +The following table +summarizes the principal sources of change in the standardized measure of +discounted future estimated net cash flows from January 1, 2004 through +December 31, 2004: +Sales of oil and natural gas production, net of +production costs +$(52,974,000) +Net changes in prices and production costs +36,656,000 +Extensions, discoveries and improved recovery, less +related costs +135,816,000 +Dispositions to partnerships +(16,782,000) +Acquisitions +6,451,000 +Development costs incurred during the period +36,870,000 +Revisions of previous quantity estimates +(34,611,000) +Changes in estimated income taxes +(66,790,000) +Accretion of discount +(27,691,000 ) +$16,945,000 +It is necessary to emphasize +that the data presented should not be viewed as representing the expected cash +flow from, or current value of, existing proved reserves, as the computations +are based on a large number of estimates and arbitrary assumptions. Reserve +quantities cannot be measured with precision, and their estimation requires +many judgmental determinations and frequent revisions. The required projection +of production and related expenditures over time requires further estimates +with respect to pipeline availability, rates of demand and governmental +control. Actual future prices and costs are likely to be substantially +different from the current prices and costs utilized in the computation of +reported amounts. Any analysis or evaluation of the reported amounts should +give specific recognition to the computational methods and the limitations +inherent therein. +Substantially all of +the Company's natural gas and oil reserves have been mortgaged or pledged as +security for the Company's credit agreement. See Note 3 of Notes to +Consolidated Financial Statements. +Oil and Natural Gas Leases +The following table +sets forth, as of December 31, 2004, the acres available for development of oil +and natural gas available to the Company, listed alphabetically by state. +Colorado +105,200 +Kansas +21,250 +Michigan +1,700 +New York +10,000 +Wyoming +26,380 +Total +164,530 +Title to Properties +The Company's +management believes that it holds good and indefeasible title to its +properties, in accordance with standards generally accepted in the natural gas +industry, subject to such exceptions stated in the opinion of counsel employed +in the various areas in which the Company conducts its exploration activities. Those +exceptions, in the Company's judgment, do not detract substantially from the +use of such property. As is customary in the natural gas industry, only a +perfunctory title examination is conducted at the time the properties believed +to be suitable for drilling operations are acquired by the Company. Prior to +the commencement of drilling operations, an extensive title examination is +conducted and curative work is performed with respect to defects which the +Company deems to be significant. A title examination has been performed with +respect to substantially all of the Company's producing properties. No single +property owned by the Company represents a material portion of the Company's +holdings. +The properties owned +by the Company are subject to royalty, overriding royalty and other outstanding +interests customary in the industry. The properties are also subject to burdens +such as liens incident to operating agreements, current taxes, development +obligations under natural gas and oil leases, farm-out arrangements and other +encumbrances, easements and restrictions. The Company does not believe that any +of these burdens will materially interfere with the use of the properties. +Facilities +The Company owns and +occupies three buildings in Bridgeport, West Virginia, two of which serve as +the Company's headquarters and one that serves as a field operating site. The +Company also owns a field operating building in Weld County, Colorado and one +in Gilmer County, West Virginia. The Company leases field operating offices in +Colorado, Michigan and Pennsylvania under operating leases. +Item 3. Legal Proceedings +From time to time +the Company is a party to various legal proceedings in the ordinary course of +business. The Company is not currently a party to any litigation that it +believes would have a materially adverse affect on the Company's business, +financial condition, results of operations, or liquidity. +Item 4. Submission of Matters to a Vote of +Security Holders +No matters were +submitted to a vote of security holders during the fourth quarter of the fiscal +year covered by this report. +PART II +Item 5. Market for the Company's Common Stock and +Related Stockholders Matters +The common stock of +the Company is traded in the Nasdaq National Market under the symbol PETD. The +following table sets forth, for the periods indicated, the high and low bid +quotations per share of the Company's common stock in the over-the-counter +market, as reported by Nasdaq. These quotations represent inter-dealer prices +without retail markups, markdowns, commissions or other adjustments and may not +represent actual transactions. +High +Low +2004 +First Quarter +$ 33.93 +$ 16.70 +Second Quarter +32.63 +21.01 +Third Quarter +44.80 +24.50 +Fourth Quarter +49.26 +32.06 +2003 +First Quarter +$ 6.30 +$ 5.30 +Second Quarter +9.70 +6.16 +Third Quarter +12.33 +8.63 +Fourth Quarter +25.05 +12.09 +As of March 21, 2005, +there were approximately 922 record holders of the Company's common stock. +The Company has not +paid any dividends on its common stock and currently intends to retain earnings +for use in its business. Therefore, it does not expect to declare cash +dividends in the foreseeable future. Further, the Company's Credit Agreement +restricts the payment of dividends. +Item 6. Selected +Condensed Financial Data (1) +Year Ended +December 31, +2004 +2003 +2002 +2001 +2000 +Revenues +Oil and gas well +drilling operations +$119,210,500 +$71,841,500 +$57,149,100 +$76,291,200 +$43,194,700 +Oil and gas +sales +161,179,100 +120,162,700 +69,223,000 +92,095,300 +90,419,700 +Well +operations income +8,384,500 +7,347,700 +6,116,200 +5,604,200 +5,061,600 +Other income +1,945,700 +3,499,100 +2,853,600 +3,132,400 +2,540,500 +Total +$290,719,800 +$202,851,000 +$135,341,900 +$177,123,100 +$141,216,500 +Costs and +Expenses (excluding +interest and +depreciation, +depletion +and amortization) +$217,284,200 +$152,445,000 +$108,816,600 +$144,468,600 +$118,813,300 +Interest Expense +$ 874,300 +$ 1,329,100 +$ 1,339,800 +$ 993,400 +$1,186,000 +Depreciation, depletion +and +Amortization +$17,958,200 +$14,153,400 +$12,103,300 +$10,578,300 +$6,943,500 +Net Income +$34,060,600 +$22,619,100 +$ 9,284,800 +$14,967,800 +$10,681,000 +Basic +earnings per common +Share +$2.10 +$1.45 +$.59 +$.92 +$.66 +Diluted earnings per +share +$2.05 +$1.39 +$.58 +$.90 +$.65 +Average Common +and Common +equivalent Shares +Outstanding +during +the Year +16,647,174 +16,297,793 +16,143,414 +16,639,634 +16,437,488 +December 31, +2004 +2003 +2002 +2001 +2000 +Total Assets +$341,393,,000 +$306,722,000 +$212,251,600 +$199,852,100 +$187,684,500 +Working Capital +$(536,300 ) +$ 6,230,700 +$ 1,770,500 +$ 3,419,600 +$ +780,700 +Long-Term +Debt, excluding +current maturities +$21,000,000 +$ 53,000,000 +$ 25,000,000 +$ 28,000,000 +$ 17,350,000 +Stockholders' +Equity +$ 164,672,900 +$123,604,600 +$101,122,200 +$ 96,772,800 +$ 82,256,900 +(1) +See +Consolidated Financial Statements elsewhere herein. +Item 7. Management's +Discussion and Analysis of Financial Condition and Results of Operations +Safe Harbor Statement Under the Private Securities Litigation Reform +Act of 1995 +Statements, other +than historical facts, contained in this Annual Report on Form 10-K, including +statements of estimated oil and gas production and reserves, drilling plans, +future cash flows, anticipated capital expenditures and Management's +strategies, plans and objectives, are "forward looking statements" +within the meaning of Section 27A of the Securities Act of 1933, as amended, +and Section 21E of the Securities Exchange Act of 1934, as amended. Although +the Company's management believes that its forward looking statements are based +on reasonable assumptions, it cautions that such statements are subject to a +wide range of risks and uncertainties incidental to the exploration for, +acquisition, development and marketing of oil and gas, and it can give no +assurance that its estimates and expectations will be realized. Important +factors that could cause actual results to differ materially from the forward +looking statements include, but are not limited to, changes in production +volumes, worldwide demand, and commodity prices for petroleum natural +resources; the timing and extent of the Company's success in discovering, acquiring, +developing and producing oil and gas reserves; the Company's ability to acquire +leases and drilling rigs at reasonable prices; the Company's ability to raise +funds through its Partnership Drilling Programs; risks incident to the +drilling and operation of oil and gas wells; future production and development +costs; the effect of existing and future laws, governmental regulations and the +political and economic climate of the United States; the effect of hedging +activities; and conditions in the capital markets. Other risk factors are +discussed elsewhere in this Form 10-K. +Results of Operations +Management Overview +The Company had record revenues and +income for 2004. High oil and natural gas prices in combination with record +Company production were the largest contributors to both income and cash flow. +The high energy prices increased the Company's revenues both for sales of +Company-owned production and for gas purchased and sold by Riley Natural Gas, +our natural gas marketing subsidiary. Management also believes that high energy +prices made the Company's partnership investment programs more attractive to +investors resulting in a significant increase in the sale of program interests. +This resulted in an increase of drilling activity, revenues, and gross profit +for the drilling and development segment. The new wells drilled for the +partnerships also led to an increase in revenues for operating wells for the +partnerships and others. +The higher level of partnership +investments also increased the costs associated with the drilling and +development and well operations activities since more goods, services and other +costs were required to drill and produce the greater number of wells. Similarly +higher oil and natural gas prices also increased the cost of purchasing gas for +resale by Riley Natural Gas. +Increased profitability and cash flow +from operations allowed the Company to reduce its long term debt and to +continue to invest in capital projects. The majority of capital investment was +for oil and gas drilling and development activities. The Company also +constructed an office building in Colorado for the Company's field operations +in the area. +Year Ended December 31, 2004 Compared with December 31, +2003 +Revenues +Total revenues for +the year ended December 31, 2004 were $290.7 million compared to $202.9 million +for the year ended December 31, 2003, an increase of approximately $87.8 million, or 43.3 percent. The increase was a result +of increased drilling revenues, gas sales from natural gas marketing activities, +oil and gas sales and well operations and pipeline income. +Oil and Gas Well Drilling Revenue +Drilling revenues +for the year ended December 31, 2004 were $119.2 million compared to $71.8 +million for the year ended December 31, 2003, an increase of approximately $47.4 +million or 66.0 percent. Such increase was due to the increased drilling funds +raised through the Company's Public Drilling Programs. The four drilling +programs of 2004 raised $100 million compared to $78.3 million in 2003. We +believe higher oil and natural gas prices and the resulting improved +performance of our prior programs are the reasons for the increase in our +drilling program sales. +Natural Gas Marketing Activities +Natural gas sales +from the marketing activities of Riley Natural Gas (RNG), the Company's +marketing subsidiary for the year ended December 31, 2004 were $93.2 million +compared to $73.1 million for the year ended December 31, 2003, an increase of +approximately $20.1 million or 27.5 percent. The increase was the result of +significantly higher average natural gas sales prices and higher volumes sold. +Oil and Gas Sales +Oil and gas sales +from the Company's producing properties for the year ended December 31, 2004 +were $67.9 million compared to $47.0 million for the year ended December 31, +2003, an increase of $20.9 million or 44.5 percent. The increase was due to +significantly higher volumes sold at substantially higher average sales prices +of oil and natural gas. The volume of natural gas sold for the year ended +December 31, 2004 was 10.4 million Mcf at an average price of $5.26 compared to +8.7 million Mcf at an average sales price of $4.42 per Mcf for the year ended +December 31, 2003. Oil sales for the year ended December 31, 2004 were 381,000 +barrels at an average sales price of $35.13 per barrel compared to 289,000 +barrels at an average sales price of $29.39 per barrel for the year ended +December 31, 2003. +Since no +acquisitions were made in 2004, the increase in production resulted primarily +from the new wells drilled by the Company in 2004, recompletions of Wattenberg +Field wells, and completion of behind pipe zones in the Appalachian Basin. Also +the three acquisitions made in 2003 contributed to the increase to the extent +they were not owned for the full year of 2003, but were in 2004. +Oil and Gas Production +The Company's oil +and gas production by area of operations along with average sales price is +presented below: +Year Ended December 31, 2004 +Year Ended December 31, 2003 +Natural +Natural Gas +Natural +Natural Gas +Oil +Gas +Equivalents +Oil +Gas +Equivalents +(Bbl) +(Mcf) +(Mcfe) +(Bbl) +(Mcf) +(Mcfe) +Appalachian Basin +4,893 +1,812,407 +1,841,765 +3,992 +1,921,200 +1,945,152 +Michigan Basin +5,786 +1,728,435 +1,763,151 +6,627 +1,832,737 +1,872,499 +Rocky Mountains +370,482 +6,831,032 +9,053,924 +278,874 +4,958,245 +6,631,489 +Total +381,161 +10,371,874 +12,658,840 +289,493 +8,712,182 +10,449,140 +Average Price +$35.13 +$5.26 +$5.37 +$29.39 +$4.42 +$4.50 +Financial results depend upon many +factors, particularly the price of natural gas and our ability to market our +production effectively. In recent years natural gas and oil prices have been +among the most volatile of all commodity prices. These price variations can +have a material impact on our financial results. Natural gas prices in Colorado continue to trail prices which we receive for our Appalachian and Michigan gas which are based upon NYMEX. The Company's management believes the lower +prices in the Rocky Mountain Region, including Colorado, resulted from +increasing local supplies that exceeded the local demand and pipeline capacity +available to move gas from the region. In 2003 a pipeline expansion project was +completed, leading to improved natural gas prices in the region which reduced +the local surplus. There is currently a substantial amount of drilling activity +in the Rockies, and if future additions to the pipeline system are not made in +a timely fashion it is possible that pipeline constraints could create a local +oversupply situation in the future which could mean lower natural gas prices. +Like most other producers in the area we rely on major interstate pipeline +companies to construct these facilities, so their timing and construction is +not within our control. +Oil and Gas Hedging Activities +Because of +uncertainty surrounding natural gas prices we have used various hedging +instruments to manage some of the impact of fluctuations in prices. Through October +of 2006 we have in place a series of floors and ceilings on part of our natural +gas production. Under the arrangements, if the applicable index rises above the +ceiling price, we pay the counterparty, however if the index drops below the +floor the counterparty pays us. During the three months ended December 31, 2004 +the Company averaged natural gas volumes sold of 872,000 Mcf per month and oil +sales of 31,000 barrels per month. The current positions in effect on the +Company's share of production by area are shown in the following table. +Floors +Ceilings +Month Set +Month +Monthly Quantity +Mmbtu +Contract +Price +Monthly Quantity +Mmbtu +Contract +Price +NYMEX Based Hedges - (Appalachian and Michigan Basins) +5/04 +Jan 2005 - Mar 2005 +180,000 +$5.67 +90,000 +$7.00 +2/04 +Apr 2005 - Oct 2005 +122,000 +$4.28 +61,000 +$5.00 +3/05 +Apr 2005 - Oct 2005 +39,000 +$5.75 +19,500 +$8.37 +1/05 +Nov 2005 - Mar 2006 +156,000 +$5.00 +78,000 +$8.50 +3/05 +Apr 2006 -Oct 2006 +78,000 +$5.50 +39,000 +$7.40 +Colorado Interstate Gas (CIG) Based Hedges (Piceance Basin) +5/04 +Jan 2005 - Mar 2005 +60,000 +$5.04 +30,000 +$6.00 +2/04 +Apr 2005- Oct 2005 +33,000 +$3.10 +16,000 +$4.43 +3/05 +Apr 2005 - Oct 2005 +38,000 +$4.75 +19,000 +$8.12 +1/05 +Nov 2005 - Mar 2006 +60,000 +$4.50 +30,000 +$7.15 +3/05 +Apr 2006 - Oct 2006 +42,000 +$4.50 +21,000 +$7.25 +Colorado Interstate Gas (CIG) Based Hedges (Wattenberg) +7/04 +Jan 2005 - Mar 2005 +80,000 +$5.00 +40,000 +$6.20 +NYMEX Based Hedges (NECO) +7/04 +Jan 2005 - Mar 2005 +150,000 +$5.32 +- +- +2/04 +Apr 2005 - Oct 2005 +150,000 +$4.26 +75,000 +$5.00 +1/05 +Nov 2005 - Mar 2006 +150,000 +$5.00 +75,000 +$8.45 +Oil - NYMEX Based (Wattenberg) +Bbls +Bbls +8/04 +Jan 2005 - Dec 2005 +15,000 +$32.30 +7,500 +$40.00 +Well Operations, Pipeline & Other Income +Well operations and +pipeline income for the year ended December 31, 2004 was $8.4 million compared +to $7.3 million for the year ended December 31, 2003, an increase of +approximately $1.1 million or 15.1 percent. The +increase was due to an increase in the number of wells and pipeline systems +operated by the Company for our public drilling programs as well as for third +parties. Other income for the year ended December 31, 2004 was $1.9 million +compared to $3.5 million for the year ended December 31, 2003, a decrease of +$1.6 million or 45.7 percent. Other income in 2003 included $1.0 of life +insurance proceeds. In 2004 the Company, for competitive reasons, lowered the +management fee it charges to its drilling partnerships to 1-1/2% of +subscriptions, from 2-1/2% of subscriptions. +Costs and Expenses +Costs and expenses +for the year ended December 31, 2004 were $236.1 million compared to $167.9 +million for the year ended December 31, 2003, an increase of approximately $68.2 +million or 40.6 percent. The increase was primarily the result of increased +cost of oil and gas well drilling operations, gas purchased for gas marketing +activities, oil and gas production costs and depreciation, depletion and +amortization. +Oil and Gas Well Drilling Costs +Oil and gas well +drilling operations costs for the year ended December 31, 2004 were $102.8 +million compared to $61.3 million for the year ended December 31, 2003, an +increase of approximately $41.5 million or 67.7 percent. The increase was due +to the higher levels of drilling activity from our public drilling programs +referred to above. In addition, the gross margin on the drilling activities for +the year ended December 31, 2004 was 13.7% compared with 14.7% for the year +ended December 31, 2003, a decrease in gross margin of approximately 1%. Such +decrease was due to significantly increasing well drilling and completion +costs, particularly the costs of fracturing and rising steel costs for casing +and other well equipment. For the first two partnerships in 2005, the Company +raised its turnkey rates charged to its Public Drilling Partnerships to reverse +this declining trend. +Cost of Gas Marketing Activities +The cost of gas +marketing activities for the year ended December 31, 2004 were $91.9 million +compared to $72.4 million for the year ended December 31, 2003, an increase of $19.5 +million or 26.9 percent. The increase was due to the significantly higher +average prices of natural gas purchased and higher volumes purchased for +resale. Income before income taxes for the Company's natural gas marketing +subsidiary improved from $689,000 for the year ended December 31, 2003 to $1,324,000 +for the year ended December 31, 2004. Based on the nature of the Company's gas +marketing activities, hedging did not have a significant impact on the +Company's net margins from marketing activities during either period. +Oil and Gas Production Costs +Oil and gas +production costs from the Company's producing properties for the year ended +December 31, 2004 were $18.0 million compared to $13.7 million for the year +ended December 31, 2003, an increase of approximately $4.3 million or 31.4% +percent. Such increase was due to the increased production costs and severance +and property taxes on the increased volumes and higher sales prices of natural +gas and oil sold, along with the increased number of wells and pipelines +operated by the Company. Lifting cost per Mcfe increased from $.98 per Mcfe to $1.18 per Mcfe due to increased severance and property +taxes on the significantly increased oil and gas sales prices along with +additional well workovers and production enhancements work performed. +General and Administrative Costs +General and +administrative expenses for the year ended December 31, 2004 decreased to $4.5 million +compared with $4.9 million for the year ended December 31, 2003 a decrease of +approximately $469,000 or 9.4 percent. The +decrease was primarily due to lower executive compensation costs partially offset +by approximately $477,000 of costs of complying with the various provisions of +Sarbanes-Oxley, in particular with Section 404 (Internal Controls). +Depreciation, Depletion, and Amortization +Depreciation, +depletion, and amortization costs for the year ended December 31, 2004 +increased to $18.0 million from approximately $14.2 million for the year ended +December 31, 2003, an increase of approximately $3.8 million +or 26.8 percent. Such increase was due to +the significantly increased production and investment in oil and gas properties +by the Company as referred to above. +Interest Expense +Interest costs for +the year ended December 31, 2004 were $874,000 compared to $1.3 million for the +year ended December 31, 2003, a decrease of $426,000 or 32.8 percent. Such +decrease is due to lower average outstanding balance of our credit facility +offset in part by rising interest rates. The Company utilizes its daily cash +balances to reduce its line of credit to lower its cost of interest. The +average outstanding debt balances for the year ended December 31, 2004 was $11.3 +million compared to $24.1 million for the year ended December 31, 2003. +Provision for Income Taxes +The effective income +tax rate for the Company's provision for income taxes increased from 34.7% for +the year ended December 31, 2003 to 37.62% for +the year ended December 31, 2004 primarily as a result of significantly +increased earnings of the Company during 2004, lower percentage depletion for +tax purposes, the benefit in 2003 of officers life insurance proceeds, and +non-conventional fuel source tax credit. +Net income and +Earnings Per Share +Net income for the +year ended December 31, 2004 was $34.1 million compared to a net income of +$22.6 million for the year ended December 31, 2003, an increase of +approximately $11.5 million or 50.9 percent. +Diluted earnings per +share for the year ended December 31, 2004 was $2.05 per share compared to +$1.39 per share for the year ended December 31, 2003, an increase of $.66 per +share or 47.5 percent. +Year Ended December 31, 2003 Compared with December 31, +2002 +Revenues +Total revenues for +the year ended December 31, 2003 were $202.9 million compared to $135.3 million +for the year ended December 31, 2002, an increase of approximately $67.6 +million, or 50.0 percent. Such increase was a result of increased drilling +revenues, gas sales from gas marketing activities, oil and gas sales and well +operations and pipeline income. +Drilling Revenue +Drilling revenues +for the year ended December 31, 2003 were $71.8 million compared to $57.1 +million for the year ended December 31, 2002, an increase of approximately +$14.7 million or 25.7 percent. Such increase was due to the increased drilling +funds raised through the Company's Public Drilling Programs. The four drilling +programs of 2003 raised $78.3 million compared to $56.9 million in 2002. We +believe this increase is fueled by the increase in oil and natural gas prices +which has improved the performance of our prior programs which in turn has +helped to increase our drilling program sales. +Natural Gas Marketing Activities +Natural gas sales +from the marketing activities of Riley Natural Gas (RNG), the Company's +marketing subsidiary for the year ended December 31, 2003 were $73.1 million +compared to $46.4 million for the year ended December 31, 2002, an increase of +approximately $26.7 million or 57.5 percent. Such increase was due to natural +gas sold at significantly higher average sales prices offset in part by +slightly lower volumes sold. +Oil and Gas Sales +Oil and gas sales +from the Company's producing properties for the year ended December 31, 2003 +were $47.0 million compared to $22.9 million for the year ended December 31, +2002, an increase of $24.1 million or 105.2 percent. The increase was due to +significantly increased volumes sold at substantially higher average sales +prices of oil and natural gas. The volume of natural gas sold for the year +ended December 31, 2003 was 8.7 million Mcf at an average sales price of $4.42 +per Mcf compared to 6.5 million Mcf at an average sales price of $2.68 per Mcf +for the year ended December 31, 2002. Oil sales were 289,000 barrels at an +average sales price of $29.39 per barrel for the year ended December 31, 2003 +compared to 227,000 barrels at an average sales price of $24.41 per barrel for +the year ended December 31, 2002. The increase in natural gas volumes was the result +of the Company's increased investment in oil and gas properties, primarily the +Williams property acquisition in the second quarter, recompletions of existing +wells, two fourth quarter acquisitions of oil and gas properties in Colorado +and Kansas and to a lesser extent the investment in oil and gas properties we +own with our public drilling program partnerships. The table below outlines our +increased production in Mcf equivalents of our 2003 recompletions and +acquisitions by quarter. +Mcfe +1 st Quarter +2 nd Quarter +3 rd Quarter +4 th Quarter +Total +Recompletions +40,000 +161,000 +223,000 +285,000 +709,000 +Williams Acquisition +- +453,000 +573,000 +519,000 +1,545,000 +4 th Quarter Acquisitions +- +- +- +196,000 +196,000 +40,000 +614,000 +796,000 +1,000,000 +2,450,000 +Oil and Gas Production +The Company's oil +and gas production by area of operations along with average sales price is +presented below: +Year Ended December 31, 2003 +Year Ended December 31, 2002 +Natural +Natural +Gas +Natural +Natural +Gas +Oil +Gas +Equivalents +Oil +Gas +Equivalents +(Bbl) +(Mcf) +(Mcfe) +(Bbl) +(Mcf) +(Mcfe) +Appalachian Basin +3,992 +1,921,200 +1,945,152 +5,814 +2,095,903 +2,130,787 +Michigan Basin +6,627 +1,832,737 +1,872,499 +8,443 +2,146,101 +2,196,759 +Rocky Mountains +278,874 +4,958,245 +6,631,489 +212,779 +2,220,033 +3,496,707 +Total +289,493 +8,712,182 +10,449,140 +227,036 +6,462,037 +7,824,253 +Average Price +$29.39 +$4.42 +$4.50 +$24.41 +$2.68 +$2.92 +Financial results depend upon many factors, particularly +the price of natural gas and our ability to market our production on +economically attractive terms. Price volatility in the natural gas and oil +markets has remained prevalent in the last few years and can have a material +impact on our financial results. Natural gas prices declined dramatically at +the end of 2001 and during the entire first quarter of 2002. However, in the +second quarter of 2002, the Company saw a significant strengthening of natural +gas prices in its Appalachian and Michigan producing areas. Natural gas prices +in Colorado remained low for most of 2002. In the fourth quarter of 2002 and +continuing in 2003, Colorado prices began to increase, although they continue +to trail prices in other areas. The Company believes the lower prices in the +Rocky Mountain Region, including Colorado, resulted from increasing local +supplies that exceeded the local demand and pipeline capacity available to move +gas from the region. On May 1st of 2003, the Kern River pipeline expansion was +completed and placed into service. The Kern River Pipeline Company has +announced that the additional facilities added about 900 million cubic feet per +day of capacity for deliveries to Arizona, Nevada and southern California. This +represents almost 30% of the prior pipeline capacity from the region to the +West Coast and other markets outside the region. The Company believes that the +completion and start-up of the pipeline eliminated or reduced the local supply +surplus, leading to improved natural gas prices in the region. Since the +startup of the new Kern River pipeline the Colorado Interstate Gas price index +has improved to a range of from 83% to over 90% of the NYMEX price, levels +consistent with historical price relationships before the recent local +demand/pipeline capacity problem. The Company has commodity price hedging +contracts for oil and natural gas production from January 2004 through October +2005 to protect against possible short-term price weaknesses. +Oil and Gas Hedging Activities +Because of +uncertainty surrounding natural gas prices we have used various hedging +instruments to manage some of the impact of fluctuations in prices. Through +October of 2005 we have in place a series of floors and ceilings on part of our +natural gas production. Under the arrangements, if the applicable index rises +above the ceiling price, we pay the counterparty, however if the index drops +below the floor the counterparty pays us. During the three months ended +December 31, 2003 the Company averaged natural gas volumes sold of 857,000 Mcf +per month and oil sales of 31,400 barrels per month. The current positions in +effect on the Company's share of production are shown in the following table. +Floors +Ceilings +Month +Monthly Quantity +Mmbtu +Contract +Price +Monthly Quantity +Mmbtu +Contract +Price +NYMEX Based Hedges - (Appalachian and Michigan Basins) +Jan 2004 +114,000 +$4.45 +57,000 +$5.40 +Feb 2004 +114,000 +$4.30 +57,000 +$5.25 +Mar 2004 +114,000 +$4.20 +57,000 +$5.00 +Apr 2004 - Oct 2004 +81,000 +$4.00 +81,000 +$5.65 +Apr 2004 - Oct 2004* +122,000 +$5.00 +- +- +Apr 2005 - Oct 2005* +122,000 +$4.28 +61,000 +$5.00 +Colorado Interstate Gas (CIG) Based Hedges (Piceance Basin) +Jan 2004 - Mar 2004 +20,000 +$3.50 +20,000 +$5.25 +Apr 2004 - Oct 2004 +25,000 +$3.20 +25,000 +$4.70 +Apr 2004 - Oct 2004* +25,000 +$4.17 +- +- +Apr 2005- Oct 2005* +33,000 +$3.10 +16,000 +$4.43 +NYMEX Based Hedges (Williams acquisition) +Jan 2004 - Dec 2004 +150,000 +$4.50 +- +- +Apr 2005 - Oct 2005* +150,000 +$4.26 +75,000 +$5.00 +Oil hedges (Wattenberg Field) +Month +Monthly Quantity +Bbl +Contract +Price +Mar 2004 - Dec 2004* +10,000 +$31.60 +*Entered into during 2004 +Well Operations, Pipeline & Other Income +Well operations and +pipeline income for the year ended December 31, 2003 was $7.3 million compared +to $6.1 million for the year ended December 31, 2002, an increase of +approximately $1.2 million or 19.7 percent. Such increase was due to an +increase in the number of wells and pipeline systems operated by the Company +for our Drilling Fund Partnerships as well as joint ventures. Other income for +the year ended December 31, 2003 was $3.5 million compared to $2.9 million for +the year ended December 31, 2002. Such increase was due to receiving the +proceeds of $1.0 million in life insurance offset in part by a reduction in +sales of miscellaneous items. +Costs and Expenses +Costs and expenses +for the year ended December 31, 2003 were $167.9 million compared to $122.3 +million for the year ended December 31, 2002, an increase of approximately +$45.6 million or 37.3 percent. Such increase was primarily the result of +increased cost of oil and gas well drilling operations, gas purchased for gas +marketing activities, oil and gas production costs and depreciation, depletion +and amortization. +Oil and Gas Well Drilling Costs +Oil and gas well +drilling operations costs for the year ended December 31, 2003 were $61.3 +million compared to $49.2 million for the year ended December 31, 2002, an +increase of approximately $12.1 million or 24.6 percent. Such increase was due +to the higher levels of drilling activity from our Public Drilling Programs +referred to above. +Cost of Gas Marketing Activities +The cost of gas +marketing activities for the year ended December 31, 2003 were $72.4 million +compared to $46.2 million for the year ended December 31, 2002, an increase of +$26.2 million or 56.7 percent. The increase was due to the significantly higher +average prices of natural gas purchased and offset in part by slightly lower +volumes purchased for resale. Income before income taxes for the Company's +natural gas marketing subsidiary improved from $174,000 for the year ended +December 31, 2002 to $689,000 for the year ended December 31, 2003. Based on +the nature of the Company's gas marketing activities, hedging did not have a +significant impact on the Company's net margins from marketing activities +during either period. +Oil and Gas Production Costs +Oil and gas +production costs from the Company's producing properties for the year ended +December 31, 2003 were $13.7 million compared to $9.1 million for the year ended +December 31, 2002, an increase of approximately $4.6 million or 50.5% percent. +Such increase was due to the increased production costs and severance and +property taxes on the increased volumes and higher sales prices of natural gas +and oil sold, along with the increased number of wells and pipelines operated +by the Company. Lifting cost per Mcfe increased from $.82 per Mcfe to $.98 per +Mcfe which is almost entirely attributed to the increase in severance and +property taxes on the significantly increased oil and gas sales prices. +General and Administrative Costs +General and +administrative expenses for the year ended December 31, 2003 increased to $4.9 +million compared with $4.4 million for the year ended December 31, 2002 an +increase of approximately $500,000 or 11.4%, such increase was due to the +increased administrative activity associated with a growing Company. +Depreciation, Depletion, and Amortization +Depreciation, +depletion, and amortization costs for the year ended December 31, 2003 +increased to $14.2 million from approximately $12.1 million for the year ended +December 31, 2002, an increase of approximately $2.1 million or 17.4%. Such +increase was due to the significantly increased production and investment in +oil and gas properties by the Company as referred to above. +Interest Expense +Interest costs for +the year ended December 31, 2003 and 2002 were $1.3 million. The lower average +effective interest rates in 2003 more than offset the higher average borrowing +levels the Company experienced during 2003, primarily a result of the oil and +gas property acquisitions mentioned above. +Provision for Income Taxes +The effective income +tax rate for the Company's provision for income taxes increased from 29% to +34.7% primarily as a result of the expired non-conventional source fuel tax +credit and the effect of the federal rate change to 35% because of +significantly increased earnings of the Company during 2003. +Change in Accounting Principle +The Company adopted +SFAS No. 143 "Accounting for Asset Retirement Obligations" on +January 1, 2003 and booked the cumulative effect on prior years of $198,600 +(net of taxes of $121,700). +Net income and +Earnings Per Share +Net income for the +year ended December 31, 2003 was $22.6 million compared to a net income of $9.3 +million for the year ended December 31, 2002, an increase of approximately +$13.3 million or 143% percent. +Diluted earnings per +share for the year ended December 31, 2003 was $1.39 per share compared to $.58 +per share for the year ended December 31, 2002, an increase of $.81 per share +or 139.7 percent. +Liquidity and Capital Resources +The Company funds its operations through a combination of +cash flow from operations including profits from drilling partnerships and use +of the Company's credit facility. Operational cash flow is generated by sales +of natural gas and oil from the Company's well interests, natural gas +marketing, profits from well drilling and operating activities for the +Company's public drilling programs and others, and natural gas gathering and +transportation. Cash payments from Company-sponsored partnerships are used to +drill and complete wells for the partnerships, with operating cash flow +accruing to the Company to the extent payments exceed drilling costs. The +Company utilizes its revolving credit arrangement to meet the cash flow +requirements of its operating and investment activities. +Natural +Gas Pricing and Pipeline Capacity +Natural gas and oil prices have been volatile in the past, +and are expected to show continued volatility in the future. Currently, the +NYMEX futures reflect a market expectation of gas prices at Henry Hub close to +or above record prices per million Btu's (Mmbtu) in 2005. Natural gas prices +look strong for 2005 even though natural gas storage levels are above normal +levels following a period when storage levels had been at a five-year low. Domestic +and international demand for energy has been increasing in the past several +years, particularly in China and some other developing countries. At the same +time it does not currently seem that new supplies have kept up with the growing +demand. The Company's management believes this situation creates the +possibility of both periods of low prices and continued high prices. +Natural gas prices +were at historically high levels throughout 2003 and 2004 in our Appalachian +and Michigan producing areas. Natural gas prices in Colorado were low for most +of 2002. In the fourth quarter of 2002 and continuing through 2003 and 2004, Colorado prices began to increase, although they continue to trail prices in other areas. +The Company's management believes the lower prices in the Rocky Mountain +Region, including Colorado, resulted from increasing local supplies that +exceeded the local demand and pipeline capacity available to move gas from the +region. On May 1st of 2003, the Kern River pipeline expansion was completed and +placed into service. The Kern River Pipeline Company announced that the +additional facilities added about 900 million cubic feet per day of capacity +for deliveries to Arizona, Nevada and southern California. This represents +almost 30% of the prior pipeline capacity from the region to the West Coast and +other markets outside the region. We believe that the completion and start-up +of the pipeline eliminated or reduced the local supply surplus, leading to +improved natural gas prices in the region. Since the startup of the new Kern River pipeline the Colorado Interstate Gas price index has improved to a range of from +77% to over 90% of the NYMEX price, levels consistent with historical price +relationships before the local demand/pipeline capacity problem described +above. +Oil Pricing +Oil prices have strengthened since the +middle of 2003. While oil prices are influenced by supply and demand, global +geopolitics may be the single most important determinant. Since the percentage +of the Company's production reflected by oil sales has increased to +approximately 20% during the year ended December 31, 2004, variations in oil +prices will have a greater impact on the Company than in the past. See previous +pages in this Management's Discussion and Analysis for a complete schedule of +current hedging positions. +Oil and Gas Hedging Activities +Because of the uncertainty surrounding natural gas and oil +prices we have used various hedging instruments to manage some of the impact of +fluctuations in prices. Through October of 2006 we have in place a series of +floors and ceilings on part of our natural gas and oil production. Under the +arrangements, if the applicable index rises above the ceiling price, we pay the +counterparty, however if the index drops below the floor the counterparty pays +us. See previous pages in this Management's Discussion and Analysis for a +schedule of hedging positions. +The Company hedges prices for its partners' share of +production as well as its own production. Actual wellhead prices will vary +based on local contract conditions, gathering and other costs and factors. +Public Drilling Programs +The Company closed +four public drilling partnerships during 2004. The total amount received +during 2004 was $100 million compared to $78.3 million for 2003. As the year +progressed interest in our programs continued to increase. The last three +drilling partnerships of 2004 closed at their maximum allowable subscriptions, +each earlier than the scheduled close. The Company proceeded with drilling for +each of these partnerships as rigs, leases and other resources were available. +Because the Company was unable to complete all of the drilling and completion activities +for the partnerships formed in 2004 during the year, the Company has a drilling +carryover to 2005 of $42.5 million compared with +$50.5 million at the end of 2003. The response to the Company's first program +of 2005 was even more positive than the response to the 2004 program. It was +opened on January 3, 2005 and was scheduled to close on April 30, 2005, but was +fully committed with $40 million in subscriptions within a few days of the +opening. Additional programs are scheduled to close in April and September of +2005, with total possible subscriptions of $115 million for the year. The +Company invests, as its equity contribution to each drilling partnership, a sum +equal to approximately 22% of the aggregate subscriptions received for that +particular drilling partnership. As a result, the Company is subject to +substantial cash commitments at the closing of each drilling partnership. No +assurance can be made that the Company will continue to receive this level of +funding from these or future programs. +The Company posts daily the amount of +subscriptions that have been sold in the current partnership at its website, www.petd.com +under the heading of "Drilling Program". +Substantially all of +the Company's drilling programs contain a repurchase provision allowing +Investors to request that the Company repurchase their partnership units. This +repurchase provision is in effect any time beginning with the third anniversary +of the first cash distribution. The provision provides that the Company is +obligated to purchase an aggregate of 10% of the initial subscriptions per +calendar year (at a minimum price of four times the most recent 12 months' cash +distributions), only if investors request the Company to repurchase such units and +subject to the Company's financial ability to do so. The maximum annual 10% +repurchase obligation, if requested by the investors, is currently +approximately $6.6 million. The Company has adequate liquidity to meet this +obligation. During 2004 the Company spent $408,300 under this provision. +Drilling +Activity +During +2004 the Company drilled along with its public drilling fund partnerships a +total of 137 wells with only four developmental dry holes. The Company drilled 97 +successful wells in its Wattenberg field in the Denver-Julesburg Basin and 36 successful wells in the Piceance Basin in western Colorado, all of the wells that +the Company drills in these two areas are in conjunction with its public +drilling fund partnerships. The Company plans to conduct the remainder of its +2004 partnership drilling activity in these two areas. +In +the fourth quarter of 2004, the Company began drilling on a planned 20 well +program on its northeast Colorado properties (NECO). The wells are being +drilled on locations created by the regulatory approval of the reduction in +well spacing from 80 to 40 acres on the properties the Company acquired in Yuma County in 2003. All twenty of the wells have been successful and are now in +production. +The +Company drilled one exploratory well in 2004 and plans additional exploratory +wells in 2005. As of the date of this report, the exploratory well had been +completed and testing was underway but the well had not been classified as +successful or dry. Testing of the well was suspended in January due to lease +restrictions on the Federal lease. We expect to resume testing in the second +quarter. If the well is determined to be a dry hole, its costs will be expensed +in the period when the determination is made as required by the successful +efforts method of accounting. The cost of the well as of January 31, 2005 is $4,362,000. +Currently the Company plans to retain most if not all of the working interest +in the exploratory wells, since the Company partnerships focus on developmental +activities and are allowed only limited participation in exploratory drilling. +Purchase of Oil +and Gas Properties +Although the Company +made several offers to purchase producing oil and gas properties from other +companies during 2004, it was not successful in purchasing any of those +properties. The Company did purchase a number of small interests in its +partnerships from investors wishing to liquidate their holdings under the +repurchase provision of the partnerships. +Costs incurred by the Company in oil and gas acquisitions, +exploration and development for the year ended December 31, 2004 are presented +below: +Property acquisition cost: +Proved undeveloped properties +$4,583,000 +Producing properties +720,000 +Development costs +36,870,400 +$42,173,400 +Common Stock +Repurchase +In March 2004, the +Compensation Committee of the Board of Directors approved a repurchase of +48,650 shares of common stock from one of the Company's officers. The +repurchase price of the common stock was the closing price on the date of the +repurchase of $26.61 per share and totaled $1,294,600 which approximated the +tax savings to be realized by the Company as a result of the exercise of said +officer's non-qualified stock options in 2004. During the fourth quarter of +2003, the Company received $1,000,000 in life insurance proceeds which was recorded +as other income from the death of the Company's Chief Financial Officer who had +a stock repurchase agreement. In May 2004, the Company repurchased 50,487 +shares of common stock from the estate of the Company's former officer in +accordance with the terms of this agreement. The repurchase price of the stock +was $27.73 per share (the 90-day average prior to the repurchase per +contract). The repurchase totaled $1,400,000 of which $1,000,000 was funded by +the life insurance proceeds. The Company also repurchased 1,703 shares from an +employee upon retirement from the Company in June, 2004. Such treasury stock +was subsequently cancelled. +At +a meeting held on Friday, March 18, 2005 the Board of Directors of Petroleum +Development Corporation approved a stock repurchase plan to allow the Company +to repurchase up to 2% of the Company's common stock in 2005. The Company +intends at a minimum to purchase adequate shares to insure no dilution from +employee stock compensation plans and may also make open market purchases from +time to time. +Long-Term +Debt +The Company has a +credit facility with J. P. Morgan Chase Bank NA and BNP Paribas of $100 million +subject to and secured by adequate levels of oil and gas reserves. The current +total borrowing base is $80.0 million of which the Company has activated $60 +million of the facility. The Company is required to pay a commitment fee of +1/4 percent on the unused portion of the activated credit facility. Interest +accrues at prime, with LIBOR (London Interbank Market Rate) alternatives +available at the discretion of the Company. No principal payments are required +until the credit agreement expires on July 3, 2008. +As of December 31, +2004 the outstanding balance was $21,000,000 . Any amounts outstanding under +the credit facility are secured by substantially all properties of the +Company. The credit agreement requires, among other things, the existence of +satisfactory levels of natural gas reserves, maintenance of certain working +capital and tangible net worth ratios along with a restriction on the payment +of dividends. As of December 31, 2004 the Company was in compliance with all +financial covenants in the credit agreement. At December 31, 2004, the +outstanding balance was subject to a prime rate of 5.25%. +Contractual +Obligations +Contractual obligations +and due dates are as follows: +Payments due by +period +Contractual Obligations +Total +Less than +1 +year +1-3 +years +3-5 +years +More than +5 +years +Long-Term Debt +$21,000,000 +- +- +$21,000,000 +- +Operating Leases +895,700 +$307,900 +$363,300 +172,500 +$52,000 +Asset Retirement Obligation +783,500 +50,000 +50,000 +50,000 +633,500 +Drilling Rig Commitment +1,604,250 +1,604,250 +- +- +- +Other Liabilities +3,967,500 +40,000 +1,287,000 +250,000 +2,390,500 +Total +$28,250,950 +$2,002,150 +$1,700,300 +$21,472,500 +$3,076,000 +Long-term debt in the above table does not include interest +as interest rates are variable and principal balances fluctuate significantly +from period to period. The Company continues to pursue capital investment +opportunities in producing natural gas properties as well as its plan to +participate in its sponsored natural gas drilling partnerships, while pursuing +opportunities for operating improvements and costs efficiencies. Management +believes that the Company has adequate capital to meet its operating +requirements. +Commitments +and Contingencies +As Managing General Partner of 10 private +partnership and 62 public partnerships (See Item 1. Business - Drilling and +Development) the Company has liability for any potential casualty losses in +excess of the partnership assets and insurance. The Company's management +believes its and its subcontractors casualty insurance coverage is adequate to +meet this potential liability. +Critical +Accounting Policies and Estimates +We have identified the following policies as critical +to our business operations and the understanding of our results of operations. +This listing is not a comprehensive list of all of our accounting policies. In +many cases, the accounting treatment of a particular transaction is +specifically dictated by accounting principles generally accepted in the United States, with no need for management's judgment in their application. There are also +areas in which management's judgment in selecting any available alternative +would not produce a materially different result. However, certain of our +accounting policies are particularly important to the portrayal of our +financial position and results of operations and may require the application of +significant judgment by our management; as a result, they are subject to an +inherent degree of uncertainty. In applying those policies, our management uses +its judgment to determine the appropriate assumptions to be used in the +determination of certain estimates. Those estimates are based on our historical +experience, our observance of trends in the industry, and information available +from other outside sources, as appropriate. For a more detailed discussion on +the application of these and other accounting policies, see "Note 1 - Summary +of significant account policies" in our financial statements and related notes. +Our critical accounting policies and estimates are as follows: +Revenue Recognition +The Company's drilling +segment recognizes revenue from our drilling contracts with our publicly +registered drilling programs using the percentage of completion method. These +contracts are footage rate based and completed within nine to twelve months +after the commencement of drilling. The Company provides geological, +engineering, and drilling supervision on the drilling and completion process +and uses subcontractors to perform drilling and completion services. The +percentage of completion method measures the percentage of contract costs +incurred to date to the estimated total contract costs for each contract. The +Company utilizes this method because reasonably dependable estimates of the +total estimated costs can be made. Because the revenue recognized depends on +estimates of the final contract costs, which are assessed continually during +the term of the contract, recognized revenues are subject to revisions as the +contract progresses. Anticipated losses, if any, on uncompleted contracts would +be recorded at the time that our estimated costs exceeded the contract revenue. +The Company has not experienced any contract losses in 2004, 2003 or 2002. +Natural gas marketing is recorded on the +gross accounting method. Riley Natural Gas ("Riley"), our marketing +subsidiary, purchases gas from many small producers and bundles the gas +together to sell in larger amounts to purchasers of natural gas for a price +advantage. Riley has latitude in establishing price and discretion in supplier +and purchaser selection. Natural gas marketing revenues and expenses reflect +the full cost and revenue of those transactions because Riley takes title to +the gas it purchases from the various producers and bears the risks and enjoys +the benefits of that ownership. +Sales of natural gas are recognized when natural +gas has been delivered to a custody transfer point, persuasive evidence of a +sales arrangement exists, the rights and responsibility of ownership pass to +the purchaser upon delivery, collection of revenue from the sale is reasonably +assured and the sales price is fixed or determinable. Natural gas is sold by +the Company under contracts with terms ranging from one month to three years. +Virtually all of the Company's contracts pricing provisions are tied to a +market index, with certain adjustments based on, among other factors, whether a +well delivers to a gathering or transmission line, quality of natural gas and +prevailing supply and demand conditions, so that the price of the natural gas +fluctuates to remain competitive with other available natural gas supplies. As +a result, the Company's revenues from the sale of natural gas will suffer if +market prices decline and benefit if they increase. The Company believes that +the pricing provisions of its natural gas contracts are customary in the industry. +The Company currently uses the "Net-Back" +method of accounting for transportation arrangements of our natural gas sales. +The Company sells gas at the wellhead and collects a price and recognizes +revenues based on the wellhead sales price since transportation costs +downstream of the wellhead are incurred by our customers and reflected in the +wellhead price. +Sales of oil are recognized when +persuasive evidence of a sales arrangement exists, the oil is verified as +produced and is delivered in a stock tank, collection of revenue from the sale +is reasonably assured and the sales price is determinable. The Company is +currently able to sell all the oil that it can produce under existing sales +contracts with petroleum refiners and marketers. The Company does not refine +any of its oil production. The Company's crude oil production is sold to +purchasers at or near the Company's wells under short-term purchase contracts +at prices and in accordance with arrangements that are customary in the oil +industry. +Well operations and pipeline income is +recognized when persuasive evidence of an arrangement exists, services have +been rendered, collection of revenues is reasonably assured and the sales price +is fixed or determinable. The Company is paid a monthly operating fee for each +well it operates for outside owners including the limited partnerships +sponsored by the Company. The fee is competitive with rates charged by other +operators in the area. The fee covers monthly operating and accounting costs, +insurance and other recurring costs. The Company may also receive additional +compensation for special non-recurring activities, such as reworks and +recompletions. +Valuation +of Accounts Receivable +Management reviews accounts receivable to +determine which are doubtful of collection. In making the determination of the +appropriate allowance for doubtful accounts, management considers the Company's +history of write-offs, relationships and overall credit worthiness of its +customers, and well production data for receivables related to well operations. +Accounting for Derivatives Contracts at Fair Value +The Company uses +derivative instruments to manage its commodity and financial market risks. +Accounting requirements for derivatives and hedging activities are complex; interpretation +of these requirements by standard-setting bodies is ongoing. +Derivatives are +reported on the Consolidated Balance Sheets at fair value. Changes in fair +value of derivatives that are not designated as accounting hedges are recorded +in earnings. +The measurement of +fair value is based on actively quoted market prices, if available. Otherwise, +the Company seeks indicative price information from external sources, including +broker quotes and industry publications. If pricing information from external +sources is not available, measurement involves judgment and estimates. These +estimates are based on valuation methodologies considered appropriate by the +Company's management. +For individual +contracts, the use of different assumptions could have a material effect on the +contract's estimated fair value. In addition, for hedges of forecasted +transactions, the Company must estimate the expected future cash flows of the +forecasted transactions, as well as evaluate the probability of the occurrence +and timing of such transactions. Changes in conditions or the occurrence of +unforeseen events could affect the timing of recognition in earnings for +changes in fair value of certain hedging derivatives. +Use of Estimates in Long-Lived Asset Impairment Testing +Impairment testing +for long-lived assets and intangible assets with definite lives is required +when circumstances indicate those assets may be impaired. In performing the +impairment test, the Company would estimate the future cash flows associated +with individual assets or groups of assets. Impairment must be recognized when +the undiscounted estimated future cash flows are less than the related asset's +carrying amount. In those circumstances, the asset must be written down to its +fair value, which, in the absence of market price information, may be estimated +as the present value of its expected future net cash flows, using an +appropriate discount rate. Although cash flow estimates used by the Company are +based on the relevant information available at the time the estimates are made, +estimates of future cash flows are, by nature, highly uncertain and may vary +significantly from actual results. +Oil and Gas Properties +Exploration +and development costs are accounted for by the successful efforts method. +The Company +assesses impairment of capitalized costs of proved oil and gas properties by +comparing net capitalized costs to estimated undiscounted future net cash flows +on a field-by-field basis using expected prices. Prices utilized in each year's +calculation for measurement purposes and expected costs are held constant +throughout the estimated life of the properties. If net capitalized costs +exceed undiscounted future net cash flows, the measurement of impairment is +based on estimated fair value which would consider future discounted cash +flows. +Property acquisition +costs are capitalized when incurred. Geological and geophysical costs and +delay rentals are expensed as incurred. The costs of drilling exploratory +wells are capitalized pending determination of whether the wells have +discovered economically producible reserves. If reserves are not discovered, +such costs are expensed as dry holes. Development costs, including equipment +and intangible drilling costs related to both producing wells and developmental +dry holes, are capitalized. +Unproved properties +or leases are written-off to expense when it is determined that they will +expire or be abandoned. +Costs of proved +properties, including leasehold acquisition, exploration and development costs +and equipment, are depreciated or depleted by the unit-of-production method +based on estimated proved developed oil and gas reserves. +Upon sale or +retirement of complete fields of depreciable or depletable property, the book +value thereof, less proceeds or salvage value, is credited or charged to +income. Upon sale of a partial unit of property, the proceeds are credited to +accumulated depreciation and depletion. +Deferred Tax +Asset Valuation Allowance +Deferred tax assets are recognized for +deductible temporary differences, net operating loss carry-forwards, and credit +carry-forwards if it is more likely than not that the tax benefits will be +realized. To the extent a deferred tax asset cannot be recognized under the +preceding criteria, a valuation allowance has been established. +The judgments used in applying the above +policies are based on management's evaluation of the relevant facts and +circumstances as of the date of the financial statements. Actual results may +differ from those estimates. . +New Accounting Standards +In June 2001, the +Financial Accounting Standard Board (FASB) issued FASB No. 143, +"Accounting for Asset Retirement Obligations" that requires entities +to record the fair value of a liability for an asset retirement obligation in +the period in which it is incurred and a corresponding increase in the carrying +amount of the related long-lived asset. This statement is effective for fiscal +years beginning after June 15, 2002. The Company adopted SFAS No. 143 on +January 1, 2003 and recorded a net asset of $271,800 and a related liability of +$592,100 (using a 6% discount rate) and a cumulative effect on change in +accounting principle on prior years of $198,600 (net of taxes of $121,700). +The FASB issued FIN +46, "Consolidation of Variable Interest Entities", in January 2003 and amended +the interpretation in December 2003. A variable interest entity (VIE) is an +entity in which its voting equity investors lack the characteristics of having +a controlling financial interest or where the existing capital at risk is +insufficient to permit the entity to finance its activities without receiving +additional financial support from other parties. FIN 46 requires the +consolidation of entities which are determined to be VIEs when the reporting +company determines itself to be the primary beneficiary (the entity that will +absorb a majority of the VIE's expected losses, receive a majority of the VIE's +residual returns, or both). The amended interpretation was effective for the +first interim or annual reporting period ending after March 15, 2004, with the +exception of special purpose entities for which the statement was effective for +periods ending after December 15, 2003. We have completed a review of our +partnership investments and have determined that those entities do not qualify +as VIEs. +On December 16, +2004, the Financial Accounting Standards Board (FASB) issued FASB Statement No. +123R (revised 2004), "Share-Based Payment" which is a revision of FASB +Statement No. 123, "Accounting for Stock-Based Compensation". Statement 123R +supercedes APB opinion No. 25, "Accounting for Stock Issued to Employees", and +amends FASB Statement No. 95, "Statement of Cash Flows". Generally, the +approach in Statement 123R is similar to the approach described in Statement +123. However, Statement 123R requires all share-based payments to employees, +including grants of employee stock options, to be recognized in the income +statement based on their fair values. Pro-forma disclosure is no longer an +alternative. The provisions of this statement becomes effective for our third +quarter 2005. Management has not determined the impact that this statement +will have on our consolidated financial statements. +Item 7A. Quantitative and Qualitative Disclosure About +Market Risk . +Market-Sensitive Instruments and Risk Management +The Company's +primary market risk exposures are interest rate risk and commodity price risk. +These exposures are discussed in detail below: +Interest Rate Risk +The Company's +exposure to market risk for changes in interest rates relates primarily to the +Company's interest-bearing cash and cash equivalents and long-term debt. +Interest-bearing cash and cash equivalents includes money market funds, +certificates of deposit and checking and savings accounts with various banks. The +amount of interest-bearing cash and cash equivalents as of December 31, 2004 is +$99,753,700 with an average interest rate of 1.14%. As of December 31, 2004, +the Company had long-term debt of $21,000,000 subject to a prime rate of 5.25%. +Commodity Price Risk +The Company utilizes commodity-based +derivative instruments as hedges to manage a portion of its exposure to price +risk from its oil and natural gas sales and marketing activities. These +instruments consist of NYMEX-traded natural gas futures contracts and option +contracts for Appalachian and Michigan production and CIG-based contracts +traded by JP Morgan for Colorado production. These hedging arrangements have +the effect of locking in for specified periods (at predetermined prices or +ranges of prices) the prices the Company will receive for the volume to which +the hedge relates and, in the case of RNG, the cost of gas supplies purchased +for marketing activities. As a result, while these hedging arrangements are +structured to reduce the Company's exposure to changes in price associated with +the hedged commodity, they also limit the benefit the Company might otherwise +have received from price changes associated with the hedged commodity. The +Company's policy prohibits the use of natural gas future and option contracts +for speculative purposes. +The +following tables summarize the open futures and options contracts for Riley +Natural Gas and +PDC as of +December 31, 2004 and 2003. +Riley Natural Gas +Open Futures Contracts +Commodity +Type +Quantity +Weighted +Total +Fair +Gas-Mmbtu +Average +Contract +Market +Oil-Barrels +Price +Amount +Value +Total +Contracts as of December 31, 2004 +Natural Gas +Sale +3,260,000 +$5.60 +$18,249,250 +($1,982,964) +Natural Gas +Purchase +1,130,000 +$6.77 +$7,644,540 +($486,490) +Natural Gas +Floor +530,000 +$5.30 +$134,242 +Natural Gas +Ceiling +265,000 +$7.00 +($85,541) +Contracts +maturing in 12 months following December 31, 2004 +Natural Gas +Sale +2,230,000 +$5.84 +$13,014,810 +($841,102) +Natural Gas +Purchase +860,000 +$6.94 +$5,965,490 +($591,340) +Natural Gas +Floor +530,000 +$5.30 +$134,242 +Natural Gas +Ceiling +265,000 +$7.00 +($85,541) +Prior Year +Total Contracts as of December 31, 2003 +Natural Gas +Sale +2,660,000 +$4.58 +$12,174,130 +($1,943,680) +Natural Gas +Purchase +820,000 +$5.17 +$4,243,420 +$451,020 +The maximum +term over which RNG is hedging exposure to the variability of cash flows for +commodity +price risk is +27 months. +Petroleum Development Corporation +Open Futures Contracts +Commodity +Type +Quantity +Weighted +Total +Fair +Gas-Mmbtu +Average +Contract +Market +Oil-Barrels +Price +Amount +Value +Total +Contracts as of December 31, 2004 +Natural Gas +Purchase +46,776 +$6.63 +$310,339 +($17,806) +Natural Gas +Floor +3,562,020 +$4.56 +$337,842 +Natural Gas +Ceiling +1,556,010 +$5.39 +($1,526,868) +Crude Oil +Floor +166,536 +$32.30 +$141,880 +Crude Oil +Ceiling +83,268 +$40.00 +($450,405) +Contracts +maturing in 12 months following December 31, 2004 +Natural Gas +Sale +Natural Gas +Purchase +46,776 +$6.63 +$310,339 +($17,806) +Natural Gas +Floor +3,562,020 +$4.56 +$337,842 +Natural Gas +Ceiling +1,556,010 +$5.39 +($1,526,868) +Crude Oil +Floor +166,536 +$32.30 +$141,880 +Crude Oil +Ceiling +83,268 +$40.00 +($450,405) +Prior Year +Total Contracts as of December 31, 2003 +Natural Gas +Sale +54,572 +$5.40 +$294,689 +($40,871) +Natural Gas +Purchase +46,776 +$4.77 +$223,122 +$31,051 +Natural Gas +Floor +3,023,800 +$4.25 +$185,486 +Natural Gas +Ceiling +1,060,300 +$5.31 +($172,377) +The maximum +term over which PDC is hedging exposure to the variability of cash flows for +commodity +price risk is +12 months. +The average NYMEX closing price for natural +gas for the years 2004, 2003, and 2002 was $6.14, $5.39 Mmbtu, and $3.22 Mmbtu. +The average NYMEX closing price for oil for the years 2004, 2003, 2002 was $41.44, +$30.98 bbl, and $26.98 bbl. Future near-term gas prices will be affected by +various supply and demand factors such as weather, government and environmental +regulation and new drilling activities within the industry. +Disclosure of Limitations +As the information +above incorporates only those exposures that exist at December 31, 2004, it +does not consider those exposures or positions which could arise after that +date. As a result, the Company's ultimate realized gain or loss with respect to +interest rate and commodity price fluctuations will depend on the exposures +that arise during the period, the Company's hedging strategies at the time, and +interest rates and commodity prices at the time. +Item 8. Financial Statements and Supplementary +Data: +The response to this +Item is set forth herein in a separate section of this Report, beginning on Page +F-1. +Item +9. Changes in and Disagreements with Accountants on Accounting and +Financial Disclosure. +None. +Item 9A. Controls and Procedures +(a) +Disclosure Controls and Procedures +The Chief Executive Officer and Chief +Financial Officer conducted an evaluation of the effectiveness of the design +and operation of the Company's disclosure controls and procedures (as defined +in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended +(the Exchange Act)) as of the end of the period covered by this report. Based +on that evaluation, the Chief Executive Officer and Chief Financial Officer +concluded that the Company's disclosure controls and procedures were effective +as of the end of the period covered by this report. +(b) Management's Report on Internal +Control over Financial Reporting +The management of Petroleum Development +Corporation is responsible for establishing and maintaining adequate internal +control over financial reporting (as such term is defined in Exchange Act Rule +13a-15(f)). Petroleum Development Corporation's internal control system is +designed to provide reasonable assurance to the Company's management and Board +of Directors regarding the reliability of financial reporting and the +preparation of financial statements for external purposes in accordance with +generally accepted accounting principles. All internal control systems, +no matter how well designed, have inherent limitations. Accordingly, even +effective controls can provide only reasonable assurance with respect to +financial statement preparation and presentation. +Petroleum Development Corporation's +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 (COSO) in Internal +Control-Integrated Framework . Based on this assessment, management +concluded that the Company maintained effective internal control over financial +reporting as of December 31, 2004. +Management's assessment of the +effectiveness of internal control over financial reporting as of December 31, +2004 has been audited by KPMG LLP, the independent registered public accounting +firm that also audited the Company's consolidated financial statements. +KPMG LLP's attestation report on management's assessment of the Company's +internal control over financial reporting appears below. +(c) Changes in Internal Control over +Financial Reporting +There were no significant changes in +internal control over financial reporting (as defined in Rule 13a-15(f) under +the Exchange Act) that occurred during the fourth quarter of 2004 that have +materially affected, or are reasonably likely to materially affect, the +Company's internal control over financial reporting. +Report of +Independent Registered Public Accounting Firm +The Board of Directors and Stockholders +Petroleum Development Corporation: +We have audited management's assessment, included in the +accompanying Management's Report on Internal Control over Financial Reporting (Item +9A(b)), that Petroleum Development Corporation (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 (COSO). +Petroleum Development Corporation'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 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, management's assessment that Petroleum +Development Corporation 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 +(COSO). Also, in our opinion, Petroleum Development Corporation 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 (COSO). +We also have audited, in accordance with the standards +of the Public Company Accounting Oversight Board (United States), the +consolidated balance sheets of Petroleum Development Corporation and subsidiaries +as of December 31, 2004 and 2003, and the related consolidated statements of +income, stockholders' equity and comprehensive income (loss) and cash flows for +each of the years in the three-year period ended December 31, 2004, and our +report dated March 30, 2005 expressed an unqualified opinion on those +consolidated financial statements. +KPMG LLP +Pittsburgh, Pennsylvania +March 30, 2005 +PART III +Item +10. Directors and Executive Officers of the Company +Directors and Executive Officers of the Company +The executive officers and directors of the +Company, their principal occupations for the past five years and additional +information are set forth below: +Name +Age +Positions and Offices Held +Held Current +Position Since +Steven R. Williams +53 +Chairman and Chief Executive Officer, +and Director +January 2004 +March 1983 +Thomas E. Riley +52 +President +Director +December 2004 +November 2003 +Darwin L. Stump +49 +Chief Financial Officer and Treasurer +November 2003 +Eric R. Stearns +47 +Executive Vice President Exploration and Development +November 2003 +Gregory A. Morgan +46 +Secretary +September 2004 +Vincent F. D'Annunzio +52 +Director +February 1989 +Jeffrey C. Swoveland +49 +Director +March 1991 +Donald B. Nestor +56 +Director +March 2000 +Kimberly Luff Wakim +46 +Director +January 2003 +David C. Parke +38 +Director +November 2003 +Steven R. Williams was elected Chairman and Chief +Executive Officer in January 2004. Mr. Williams served as President From March +1983 until December 2004 and has been a Director of PDC since March 1983. +Thomas E. Riley was elected Director in January 2004 by +the Board of Directors and assumed the position of President in December 2004. +Previously Mr. Riley was appointed Executive Vice President of Production, +Natural Gas Marketing and Business Development in November 2003. Prior thereto, +Mr. Riley served as Vice President Gas Marketing and Acquisitions of PDC since +April 1996. Prior to joining PDC, Mr. Riley was president of Riley Natural Gas +Company, a natural gas marketing company which PDC acquired in April 1996. +Darwin L. Stump was appointed Chief Financial Officer and +Treasurer in November 2003. Mr. Stump has been an officer of the Company since +April 1995 and held the position of Corporate Controller since 1980. Mr. Stump, +a CPA, was a senior accountant with Main Hurdman, Certified Public Accountants +prior to joining PDC. +Eric R. Stearns was appointed Executive Vice President of +Exploration and Development in November 2003. Prior thereto, Mr. Stearns was +Vice President of Exploration and Development since April 1995. Mr. Stearns +joined PDC as a geologist in 1985 after working for Hywell, Incorporated and +for Petroleum Consultants. +Gregory A. Morgan has been a member of the law firm of +Young, Morgan & Cann, Clarksburg, West Virginia since 1986. Mr. Morgan is +not active in the day-to-day business of PDC, but his law firm provides legal +services to PDC. +Vincent F. D'Annunzio has served as president of Beverage +Distributors, Inc. located in Clarksburg, West Virginia since 1985. +Jeffrey C. Swoveland has served as Chief Financial +Officer of Body Media since September, 2000. Prior thereto, Mr. Swoveland was +Vice President-Finance and Treasurer of Equitable Resources Inc since 1994. +Donald B. Nestor, is a Certified Public Accountant and a +Partner in the CPA firm of Toothman Rice, P.L.L.C. and is in charge of the +firm's Buckhannon, West Virginia office. Mr. Nestor has served in that +capacity since 1975. +Kimberly Luff Wakim, an Attorney and Certified Public +Accountant, is a Partner with the law firm Thorp, Reed & Armstrong LLP. +Ms. Wakim joined Thorp Reed & Armstrong LLP in 1990. +David C. Parke was elected Director by the Board of +Directors in November 2003. In 2003, Mr. +Parke joined Mufson/Howe/Hunter & Company LLC, an investment banking firm +as a founder and Director. From 1992-2003, Mr. Parke was with the corporate +finance department of Investec, Inc. and its predecessor Pennsylvania Merchant +Group Ltd., investment banking companies. Prior to joining Pennsylvania +Merchant Group, Mr. Parke served in the corporate finance departments of Wheat +First Butcher & Singer, now part of Wachovia Securities, and Legg Mason, +Inc. +The Company's By-Laws +provide that the directors of the Company shall be divided into three classes +and that, at each annual meeting of stockholders of the Company, successors to +the class of directors whose term expires at the annual meeting will be elected +for a three-year term. The classes are staggered so that the term of one class +expires each year. Mr. Swoveland and Mr. Parke are members of the class whose +term expires in 2005. Mr. Williams, Mr. Nestor and Ms. Wakim are members of +the class whose term expires in 2006. Mr. D'Annunzio and Mr. Riley are members +of the class whose term expires in 2007. There is no family relationship +between any director or executive officer and any other director or executive +officer of the Company. There are no arrangements or understandings between any +director or officer and any other person pursuant to which such person was +selected as an officer. +On January 24, 2003, the +Company adopted a Code of Business Conduct and Ethics Policy meeting the +specified standards applicable to the Chief Executive Officer and Chief +Financial Officer. The policy also covers all the corporate officers. The +policy is posted on the Company's website at www.petd.com. The Company will provide a copy of the +Code to any person, without charge, upon request to the Company's Secretary at +the Company's principal executive offices or by telephone at 800-624-3821. +The Audit Committee +of the Board of Directors is comprised entirely of independent directors as +defined by the NASDAQ rule 4200(a)(15). Donald B. Nestor, CPA, a partner in +the certified public accounting firm of Toothman Rice PLLC, chairs the +committee. Mr. Nestor and the other audit committee members, qualify as audit +committee financial experts and are independent of management. +The Nominating and +Governance and Compensation Committees are also comprised entirely of +independent directors of the Company. Vincent F. D'Annunzio chairs the +Nominating and Governance Committee, and Jeffrey C. Swoveland chairs the +Compensation Committee. +Shareholders wishing +to communicate with the Board of Directors or a committee may do so by writing +to the attention of the Board or Committee at the corporate headquarters or by +emailing the Board at board@petd.com, with "Board" or appropriate +committee in the subject line. +Item 11 Executive Compensation +There is +incorporated by reference herein in response to this Item the material under +the heading "Election of Directors - Remuneration of Directors and +Officers", "Election of Directors - Stock Options" and +"Election of Directors - Interest of Management in Certain +Transactions" in the Company's definitive proxy statement for its 2005 +annual meeting of stockholders filed or to be filed with the Commission on or +before April 30, 2005. +Item 12. Security Ownership of Certain Beneficial +Owners, Management and Related Stockholder Matters +There is +incorporated by reference herein in response to this Item, the material under +the heading "Election of Directors", in the Company's definitive +proxy statement for its 2005 annual meeting of stockholders filed or to be +filed with the Commission on or before April 30, 2005. +The Company has the +following common stock options outstanding under the stock option plans +approved by the stockholders: +Equity +Compensation Plan Information +December 31, 2004 +Plan Category +Number of securities to +be issued upon exercise +of outstanding options, +warrants and rights +(a) +Weighted-average +exercise price of +outstanding options, +warrants and rights +(b) +Number of securities +remaining available for +future issuance under +equity compensation +plans (excluding +securities reflected in +column (a)) +(c) +Equity compensation plans +approved by security holders +76,880 +$11.64 +733,120 +Equity compensation plans not +approved by security holders +- +- +- +Total +76,880 +$11.64 +733,120 +Item 13. Certain Relationships and Related +Transactions +The response to this +item is set forth herein in Note 8 in the Notes to Consolidated Financial +Statements and under "Election of Directors - Interest of Management in +Certain Transactions," in the Company's definitive proxy statement for its +2005 annual meeting of stockholders filed or to be filed with the Commission on +or before April 30, 2005, which we incorporate by reference. +Item 14. Principal Accounting Fees and Services +The information under the caption "Fees Billed by +Independent Public Accountants for Services in 2004 and 2003" in the +Company's definitive Proxy Statement in connection with the 2005 annual +stockholders' meeting is incorporated by reference. +Item 15. Exhibits, Financial Statement Schedules and +Reports on Form 8-K +(a) (1) Financial +Statements: +See +Index to Financial Statements and Schedules on page F-1. +(2) Financial +Statement Schedules: +See +Index to Financial Statements and Schedules on page F-1. +Schedules +and Financial Statements Omitted +All other financial +statement schedules are omitted because they are not required, inapplicable, or +the information is included in the Financial Statements or Notes thereto. +(3) Exhibits: +See +Exhibits Index on page E-1. +CONFORMED COPY +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. +PETROLEUM +DEVELOPMENT CORPORATION +By /s/ +Steven R. Williams +Steven R. +Williams, Chairman +March 31, 2005 +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/ Steven R. Williams +Steven R. Williams +Chairman, Chief Executive Officer and Director +March 31, 2005 +/s/ Darwin L. Stump +Darwin L. Stump +Chief Financial Officer and Treasurer +(principal financial and accounting officer) +March 31, 2005 +/s/ Thomas E. Riley +Thomas E. Riley +President and Director +March 31, 2005 +/s/ Donald B. Nestor +Donald B. Nestor +Director, Chairman of Audit Committee +March 31, 2005 +/s/ Vincent F. D'Annunzio +Vincent F. D'Annunzio +Director +March 31, 2005 +/s/ Jeffrey C. Swoveland +Jeffrey C. Swoveland +Director +March 31, 2005 +/s/ Kimberly Luff Wakim +Kimberly Luff Wakim +Director +March 31, 2005 +/s/ David C. Parke +David C. Parke +Director +March 31, 2005 +Exhibits Index +(a) Exhibits +Exhibit Name +Exhibit +Number +Location +Articles of Incorporation +3.1 +Incorporated by reference to Exhibit 3.1 to Form S-2 +SEC File No. 333-36369 filed on September 25, 1997 +By Laws +3.2 +Incorporated by reference to Exhibit 3.2 to Form 8-K +SEC File No. 0-07246 filed on September 8, 2003 +Credit Agreement, dated as of July 3, 2002, as extended +as of April 30, 2004 by and between Petroleum Development Corporation and the +lenders, Bank One N.A. and BNP Paribas +10.1 +Incorporated by reference to Exhibit 10.1 to Form 10-K +for year ended December 31, 2002, SEC File No. 0-07246 filed on March 7, 2003 +Employment Agreement with Steven R. Williams, Chief +Executive Officer and Chairman, dated as of March 7, 2003 +10.2 +Incorporated by reference in Exhibit 10.2 to Form 10-K filed +on March 7, 2003 +Employment Agreement with Darwin L. Stump, Chief +Financial Officer, dated as of January 5, 2004 +10.3 +Incorporated by reference to Exhibit 99.4 Form 8-K +dated January 5, 2004 +Employment Agreement with Thomas E. Riley, President, +dated as of January 5, 2004 +10.4 +Incorporated by reference to Exhibit 99.6 Form 8-K +dated January 5, 2004 +Employment Agreement with Eric R. Stearns, Executive +Vice President, dated as of January 5, 2004 +10.5 +Incorporated by reference to Exhibit 99.5 Form 8-K +dated January 5, 2004 +2004 Long-Term Equity Compensation Plan +10.6 +Incorporated by reference to Exhibit 99.1 to Form S-8, +SEC File No. 333-118215, filed on August 13, 2004 +Non-Employee Director Deferred Compensation Plan +10.7 +Incorporated by reference Exhibit 99.1 to Form S-8, SEC +File No. 333-118222, filed on August 13, 2004 +1999 Incentive Stock Option and Non-Qualified Stock +10.8 +Incorporated by reference to Exhibit 99.1 to form S-8, +SEC File No. 333-111825, filed on January 9, 2004 +1997 Employee Incentive Stock Option Plan +10.9 +Incorporated by reference to Exhibit 99.1 to Form S-8, +SEC File No. 333-111824, filed on January 9, 2004 +Tom Carpenter Employment Agreement Stock Option Plan +10.10 +Incorporated by reference to Exhibit 99.1 to Form S-8, +SEC File No. 333-111823, filed on January 9, 2004 +Code of Business Conduct and Ethics +14 +Incorporated by reference to Exhibit 3.1 to +Form 10-K for the year ended December 31, 2002, SEC +File No. 0-07246 filed on March 7, 2003 +Subsidiaries +21 +Riley Natural Gas Company, a West Virginia Corporation +21 +PDC Securities Incorporated, a West Virginia +Corporation +Consent of Independent Registered Public Accounting +Firm +23.1 +Filed herewith. +Consent of Independent Petroleum Engineers +23.2 +Filed herewith. +Rule 13a-14(a)/15d-14(a) Certification by Chief +Executive Officer +31.1 +Filed herewith. +Rule 13a-14(a)/15d-14(a) Certification by Chief +Financial Officer +31.2 +Filed herewith. +Title 18 U.S.C. Section 1350 (Section 906 of +Sarbanes-Oxley Act of 2002) Certifications by Chief Executive Officer and +Chief Financial Officer +32.1 +Filed herewith. +(b) +Reports +on Form 8-K during quarter ended December 31, 2004. +Form 8-K current +report dated December 16, 2004, under item 1.01 Entry into a Material +Definitive Agreement, the +Compensation Committee of Petroleum Development Corporation has established +2004 grants for the executive officers of the company (the Participants). The +grants are being awarded pursuant to the terms of the Petroleum Development +Corporation 2004 Long-Term Equity Compensation Plan that was approved by the +shareholders of the company at the June 11, 2004 Annual Meeting. +Form 8-K/A current report dated +December 15, 2004, under Item 5.02. Any +resignation, appointment, retirement, removal or termination of a director or +executive officer or any director's refusal to stand for reelection. The +Company issued a news release announcing that Thomas E. Riley has been selected +as President of the Company filling the position currently held by Steven R. +Williams. Mr. Williams will remain CEO and Chairman of PDC. +Form 8-K current report dated December 15, +2004, under Item 5 Other Events, the Company issued a news release announcing +that Thomas E. Riley has been selected as President of the Company filling the +position currently held by Steven R. Williams. Mr. Williams will remain CEO and +Chairman of PDC. +Form 8-K current report dated November 5, 2004, under Item 2.02 Results +of Operations and Financial Condition, the Company issued a news release +announcing financial and operating results for the third quarter 2004. +Form 8-K current report dated October 29, +2004, under Item 8.01. Other +Events, the Company issued a news release announcing upcoming earnings release +and invites you to join its third quarter earnings web cast. +PETROLEUM +DEVELOPMENT CORPORATION AND SUBSIDIARIES +Index to Financial +Statements and Financial Statement Schedule +1. +Financial Statements: +Report of Independent +Registered Public Accounting Firm +F-2 +Consolidated Balance +Sheets - December 31, 2004 and 2003 +F-3 & 4 +Consolidated Statements +of Income - +Years Ended +December 31, 2004, 2003 and 2002 +F-5 +Consolidated Statements +of Stockholders' Equity and Comprehensive Income (Loss) +Years Ended +December 31, 2004, 2003 and 2002 +F-6 +Consolidated Statements +of Cash Flows - +Years Ended +December 31, 2004, 2003 and 2002 +F-7 +Notes to Consolidated +Financial Statements +F-8 -F-27 +2. +Financial Statement Schedule: +Schedule II - Valuation and Qualifying Accounts and +Reserves +F-28 +Report of +Independent Registered Public Accounting Firm +The Board of Directors and Stockholders +Petroleum Development Corporation: +We have audited the accompanying consolidated balance +sheets of Petroleum Development Corporation and subsidiaries as of December 31, +2004 and 2003, and the related consolidated statements of income, stockholders' +equity and comprehensive income (loss), and cash flows for each of the years in +the three-year period ended December 31, 2004. In connection with our audits of +the consolidated financial statements, we also have audited financial statement +schedule II. These consolidated financial statements and financial statement +schedule are the responsibility of the Company's management. Our responsibility +is to express an opinion on these consolidated financial statements and +financial statement schedule 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, the consolidated financial statements +referred to above present fairly, in all material respects, the financial position +of Petroleum Development Corporation and subsidiaries as of December 31, 2004 +and 2003, and the results of their operations and their cash flows for each of +the years in the three-year period ended December 31, 2004, in conformity with +U. S. generally accounting principles. Also in our opinion, the related +financial statement schedule, when considered in relation to the basic +consolidated financial statements taken as a whole, presents fairly, in all +material respects, the information set forth therein. +As discussed in note 1 to the consolidated financial +statements, the Company adopted the provisions of Statement of Financial +Accounting Standards No. 143, Accounting for Asset Retirement Obligations, in +2003. +We also have audited, in accordance with the standards of +Public Company Accounting Oversight Board (United States), the effectiveness of +Petroleum Development Corporation's 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 (COSO) and our report dated March 30, 2005, expressed an unqualified +opinion on management's assessment of, and effective operation of, internal +control over financial reporting. +KPMG LLP +Pittsburgh, Pennsylvania +March 30, 2005 +PETROLEUM +DEVELOPMENT CORPORATION AND SUBSIDIARIES +Consolidated Balance +Sheets +December 31, 2004 +and 2003 +Assets +2004 +2003 +Current assets: +Cash and cash equivalents +$77,070,400 +$ 78,512,900 +Restricted cash +664,900 +1,866,400 +Notes and accounts receivable +33,902,800 +23,067,000 +Inventories +1,657,300 +2,014,300 +Other current assets +7,334,200 +5,907,000 +Total current assets +120,629,600 +111,367,600 +Properties and equipment: +Oil and gas properties (successful +efforts accounting method) +291,436,700 +251,558,900 +Pipelines +9,515,000 +9,097,000 +Transportation and other equipment +4,453,700 +3,460,900 +Land and buildings +2,942,800 +1,747,500 +308,348,200 +265,864,300 +Less accumulated depreciation, +depletion and amortization +88,341,300 +71,182,100 +220,006,900 +194,682,200 +Other assets +756,500 +672,200 +Total Assets +$341,393,000 +$306,722,000 +(Continued) +PETROLEUM +DEVELOPMENT CORPORATION AND SUBSIDIARIES +Consolidated Balance +Sheets +December 31, 2004 +and 2003 +2004 +2003 +Liabilities and Stockholders' Equity +Current liabilities: +Accounts payable +$42,438,400 +$ 29,453,000 +Production tax liability +17,510,500 +9,069,400 +Other accrued expenses +5,807,900 +7,744,800 +Advances for future drilling contracts +42,497,300 +50,458,800 +Funds held for future distribution +12,911,800 +8,410,900 +Total +current liabilities +121,165,900 +105,136,900 +Long-term debt +21,000,000 +53,000,000 +Other liabilities +3,927,500 +2,449,100 +Deferred income taxes +29,843,200 +21,800,200 +Asset retirement obligation +783,500 +731,200 +Commitments and contingencies (Note 9) +Stockholders' equity: +Common stock, par value $.01 per share; +authorized 50,000,000 shares; issued and +outstanding 16,589,324 and 15,628,433 shares +165,800 +156,200 +Additional paid-in capital +37,684,300 +28,592,900 +Retained earnings +130,109,800 +96,049,200 +Unamortized stock award +(882,000) +(14,800) +Accumulated other comprehensive loss, net of tax +(2,405,000) +(1,178,900 ) +Total +stockholders' equity +164,672,900 +123,604,600 +Total Liabilities and Stockholders' Equity +$341,393,000 +$306,722,000 +See accompanying notes to consolidated financial +statements. +PETROLEUM +DEVELOPMENT CORPORATION AND SUBSIDIARIES +Consolidated +Statements of Income +Years Ended December +31, 2004, 2003 and 2002 +2004 +2003 +2002 +Revenues: +Oil +and gas well drilling operations +$119,210,500 +71,841,500 +57,149,100 +Gas +sales from marketing activities +93,231,400 +73,141,100 +46,365,900 +Oil +and gas sales +67,947,700 +47,021,600 +22,857,100 +Well +operations and pipeline income +8,384,500 +7,347,700 +6,116,200 +Other +income +1,945,700 +3,499,100 +2,853,600 +290,719,800 +202,851,000 +135,341,900 +Costs +and expenses: +Cost +of oil and gas well drilling operations +102,830,700 +61,277,800 +49,166,200 +Cost +of gas marketing activities +91,898,100 +72,443,600 +46,184,300 +Oil +and gas production and well operations costs +18,049,800 +13,749,200 +9,074,200 +General +and administrative expenses +4,505,600 +4,974,400 +4,391,900 +Depreciation, +depletion and amortization +17,958,200 +14,153,400 +12,103,300 +Interest +874,300 +1,329,100 +1,339,800 +236,116,700 +167,927,500 +122,259,700 +Income +before income taxes and cumulative effect of +change +in accounting principle +54,603,100 +34,923,500 +13,082,200 +Income taxes +20,542,500 +12,105,800 +3,797,400 +Net +income before cumulative effect of change in +accounting +principle +34,060,600 +22,817,700 +9,284,800 +Cumulative effect +of change in accounting principle +(net +of taxes of $121,700) +- +(198,600 ) +- +Net income +$34,060,600 +22,619,100 +9,284,800 +Basic earnings per +common share before accounting change +$2.10 +1.46 +.59 +Cumulative effect of change in +accounting principle +- +(0.01) +- +Basic earnings per +common share +$ 2.10 +1.45 +.59 +Diluted earnings +per share before accounting change +$2.05 +1.40 +.58 +Cumulative effect +of change in accounting principle +- +(0.01) +- +Diluted earnings +per common and common equivalent share +$ 2.05 +1.39 +.58 +See +accompanying notes to consolidated financial statements. +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Consolidated +Statements of Stockholders' Equity and Comprehensive Income (Loss) +Years Ended December +31, 2004, 2003 and 2002 +Common +stock issued +Number +Of +Shares +Amount +Additional +Paid-in- +capital +Retained +Earnings +Unamortized +Stock Award +Accumulated +Other Comprehensive +Income (loss) +Total +Balance, +December 31, 2001 +16,245,752 +$ +162,400 +32,951,700 +64,145,300 +(29,200) +(457,400) +96,772,800 +Issuance +of common stock: +Exercise +of employee stock options +70,000 +700 +78,100 +- +- +78,800 +Amortization +of stock award +- +- +5,500 +- +5,500 +Repurchase +and cancellation of treasury stock +(580,985) +(5,800) +(3,689,300) +(3,695,100) +Net +income +- +- +- +9,284,800 +- +- +9,284,800 +Comprehensive +income: +Reclassification adjustment for settlement of contracts +Included in net income (net of tax of $9,100) +- +- +- +- +- +14,800 +Changes in fair value of outstanding hedging positions +and +interest rate swap (net of tax of $820,900) +- +- +- +- +- +(1,339,400 ) +Other comprehensive loss +(1,324,600) +(1,324,600 ) +Comprehensive +income +_________ +___________ +_________ +___________ +___________ +________ +7,960,200 +Balance, +December 31, 2002 +15,734,767 +157,300 +29,340,500 +73,430,100 +(23,700) +(1,782,000) +101,122,200 +Amortization +of stock award +- +- +8,900 +- +8,900 +Repurchase +and cancellation of treasury stock, net +(106,334) +(1,100) +(747,600) +(748,700) +Net +income +- +- +- +22,619,100 +- +- +22,619,100 +Comprehensive +income: +Reclassification adjustment for settlement of contracts +Included in net income (net of tax of $583,900) +- +- +- +- +- +917,200 +Changes in fair value of outstanding hedging positions +and +interest rate swap (net of tax of $200,000) +- +- +- +- +- +(314,100 ) +Other comprehensive income +603,100 +603,100 +Comprehensive +income +_________ +___________ +_________ +___________ +___________ +________ +23,222,200 +Balance, +December 31, 2003 +15,628,433 +156,200 +28,592,900 +96,049,200 +(14,800) +(1,178,900) +123,604,600 +Issuance +of common stock +Exercise +of employee stock options +1,100,000 +11,000 +4,981,700 +- +- +- +4,992,700 +Stock +Award +23,380 +200 +870,700 +- +(870,900) +- +Amortization +of stock award +- +- +- +3,700 +- +3,700 +Repurchase +and cancellation of treasury stock, net +(162,489) +(1,600) +(4,155,800) +- +- +- +(4,157,400) +Income +tax benefit from the exercise of stock options +- +- +7,394,800 +- +- +- +7,394,800 +Net +income +- +- +- +34,060,600 +- +- +34,060,600 +Comprehensive +income: +- +- +- +- +- +Reclassification adjustment for settlement of contracts +Included in net income (net of tax of $2,084,400) +- +- +- +- +- +3,274,000 +Changes in fair value of outstanding hedging positions +and +interest rate swap (net of tax of $2,865,000) +- +- +- +- +- +(4,500,100 ) +Other comprehensive loss +- +- +- +- +(1,226,100) +(1,226,100) +Comprehensive +income +_________ +___________ +_________ +___________ +___________ +________ +32,834,500 +Balance, +December 31, 2004 +16,589,324 +$ 165,800 +37,684,300 +130,109,800 +(882,000) +(2,405,000) +164,672,900 +See accompanying +notes to consolidated financial statements. +PETROLEUM +DEVELOPMENT CORPORATION AND SUBSIDIARIES +Consolidated +Statements of Cash Flows +Years Ended December +31, 2004, 2003 and 2002 +2004 +2003 +2002 +Cash flows from operating activities: +Net income +$34,060,600 +22,619,100 +9,284,800 +Adjustment to reconcile net income to cash provided by +operating activities: +Deferred income taxes +10,443,600 +8,870,700 +2,986,400 +Depreciation, depletion and amortization +17,958,200 +14,153,400 +12,103,300 +Cumulative effect of change in accounting principle +- +198,600 +- +Gain from sale of assets +(32,000) +(115,800) +(25,800) +Expired and abandoned leases +344,700 +1,418,400 +1,129,400 +Amortization of stock award +3,700 +8,900 +5,500 +(Increase) in notes and accounts receivable +(10,835,800) +(7,187,100) +(4,583,900) +Decrease (increase) in inventories +357,000 +(1,383,600) +(56,200) +Decrease (increase) in other current assets +4,776,200 +(1,095,900) +369,200 +(Increase) decrease in other assets +(281,300) +1,696,200 +56,300 +Increase in production tax liability +8,441,100 +3,974,800 +1,833,400 +Increase in accounts payable and accrued expenses +10,091,500 +12,782,200 +111,800 +(Decrease) increase in advances for future drilling +contracts +(7,961,500) +13,175,000 +5,691,600 +Increase (decrease) in funds held for future +distribution +4,500,900 +4,493,000 +(732,900 ) +Total +adjustments +37,806,300 +50,988,800 +18,888,100 +Net +cash provided by operating activities +71,866,900 +73,607,900 +28,172,900 +Cash flows from investing activities: +Capital expenditures +(45,391,800) +(73,042,300) +(19,777,000) +Proceeds from sale of leases to partnerships +1,950,900 +1,382,100 +1,042,500 +Proceeds from sale of fixed assets +94,700 +156,800 +25,800 +Decrease (increase) in restricted cash +1,201,500 +894,100 +(2,477,200 ) +Net cash used in +investing activities +(42,144,700 ) +(70,609,300 ) +(21,185,900 ) +Cash flows from financing activities: +(Retirement of) proceeds from debt, net +(32,000,000) +28,000,000 +(3,000,000) +Proceeds from issuance of stock +3,584,400 +- +78,800 +Repurchase and cancellation of treasury stock +(2,749,100 ) +(748,700 ) +(3,695,100 ) +Net cash (used +in) provided by financing activities +(31,164,700 ) +27,251,300 +(6,616,300 ) +Net (decrease) increase in cash and cash equivalents +(1,442,500) +30,249,900 +370,700 +Cash and cash equivalents, beginning +of year +78,512,900 +48,263,000 +47,892,300 +Cash and cash equivalents, end of +year +$ 77,070,400 +78,512,900 +48,263,000 +See accompanying notes to consolidated financial +statements. +PETROLEUM +DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to +Consolidated Financial Statements +Years Ended December +31, 2004, 2003 and 2002 +(1) Summary +of Significant Accounting Policies +Principles +of Consolidation +The accompanying +consolidated financial statements include the accounts of Petroleum Development +Corporation (PDC) and its wholly owned subsidiaries, Riley Natural Gas (RNG) +and PDC Securities Incorporated. All material intercompany accounts and +transactions have been eliminated in consolidation. The Company accounts for +its investment in limited partnerships under the proportionate consolidation +method. Under this method, the Company's financial statements include its +prorata share of assets and liabilities and revenues and expenses, +respectively, of the limited partnerships in which it participates. +The Company is +involved in four business segments. The segments are drilling and development, +natural gas marketing, oil and gas sales and well operations. (See Note 19) +The Company grants +credit to purchasers of oil and gas and the owners of managed properties, +substantially all of whom are located in West Virginia, Tennessee, +Pennsylvania, Michigan, North Dakota, Colorado and Kansas. +Cash Equivalents +For purposes of the +statement of cash flows, the Company considers all highly liquid debt +instruments with original maturities of three months or less to be cash +equivalents. +Restricted Cash +The Company is +required to maintain margin deposits with brokers for outstanding future +contracts. As of December 31, 2004 and 2003, cash in the amount of $664,900 and +$1,866,400 was on deposit. +Inventories +Inventories of well +equipment, parts and supplies are valued at the lower of average cost or +market. An inventory of natural gas is recorded when gas is purchased in excess +of deliveries to customers and is recorded at the lower of cost or market. +Oil and Gas +Properties +Exploration and +development costs are accounted for by the successful efforts method. +The Company assesses +impairment of capitalized costs of proved oil and gas properties by comparing +net capitalized costs to estimated undiscounted future net cash flows on a +field-by-field basis using expected prices. Prices utilized in each year's +calculation for measurement purposes and expected costs are held constant +throughout the estimated life of the properties. If net capitalized costs +exceed undiscounted future net cash flows, the measurement of impairment is +based on estimated fair value which would consider future discounted cash +flows. +Property acquisition +costs are capitalized when incurred. Geological and geophysical costs and +delay rentals are expensed as incurred. The costs of drilling exploratory +wells are capitalized pending determination of whether the wells have +discovered economically producible reserves. If reserves are not discovered, +such costs are expensed as dry holes. Development costs, including equipment +and intangible drilling costs related to both producing wells and developmental +dry holes, are capitalized. +Unproved properties +or leases are written-off to expense when it is determined that they will +expire or be abandoned. +(Continued) +PETROLEUM +DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to +Consolidated Financial Statements +Costs +of proved properties, including leasehold acquisition, exploration and +development costs and equipment, are depreciated or depleted by the +unit-of-production method based on estimated proved developed oil and gas +reserves. +Upon +sale or retirement of complete fields of depreciable or depletable property, the +book value thereof, less proceeds or salvage value, is credited or charged to +income. Upon sale of a partial unit of property, the proceeds are credited to +accumulated depreciation and depletion. +Transportation +Equipment, Pipelines and Other Equipment +Transportation +equipment, pipelines and other equipment are carried at cost. Depreciation is +provided principally on the straight-line method over useful lives of 3 to 17 +years. The Company adopted FASB Statement No. 144 "Accounting for the +Impairment or Disposal of Long-Lived Assets" on January 1, 2002. The +adoption of FASB No. 144 did not affect the Company's financial statements. +In +accordance with FASB Statement No. 144, long-lived assets, such as property, +plant, and equipment, are reviewed for impairment whenever events or changes in +circumstances indicate that the carrying amount of an asset may not be +recoverable. Recoverability of assets to be held and used is measured by a +comparison of the carrying amount of an asset to estimated undiscounted future +cash flows expected to be generated by the asset. If the carrying amount of an +asset exceeds its estimated future cash flows, an impairment charge is +recognized in the amount by which the carrying amount of the asset exceeds the +fair value of the asset. +Maintenance +and repairs are charged to expense as incurred. Major renewals and betterments +are capitalized. Upon the sale or other disposition of assets, the cost and +related accumulated depreciation, depletion and amortization are removed from +the accounts, the proceeds applied thereto and any resulting gain or loss is +reflected in income. +Buildings +Buildings +are carried at cost and depreciated on the straight-line method over estimated +useful lives of 30 years. +Asset +Retirement Obligations +The +Company incurs retirement obligations for its well drilling operations under +FASB Statement No. 143, "Accounting for Asset Retirement +Obligations". This requires entities to record the fair value of a +liability for an asset retirement obligation in the period incurred and a +corresponding increase in the carrying amount of the long-lived assets. The +costs associated with this liability are capitalized as part of the related +long-lived asset and depreciated. The Company adopted FASB No. 143 on January +1, 2003 and recorded a net asset of $271,800 and a related liability of +$592,100 (using a 6% discount rate) and a cumulative effect of change in +accounting principle on prior years of $198,600 (net of taxes of $121,700). +Since adoption the obligation has increased to $783,500 as of December 31, 2004 +due to the additional wells purchased and drilled by the Company and accretion, +offset in part by wells plugged. +Advances +for Future Drilling Contracts +Advances +for future drilling contracts represents funds received from Partnerships and +other joint ventures for drilling activities which have not been completed and +accordingly have not yet been recognized as revenue in accordance with the +Company's revenue recognition policies. +Retirement +Plans +The +Company has a 401-K contributory retirement plan (401-K Plan) covering +full-time employees. The Company provides a discretionary matching of employee +contributions to the plan. +The +Company also has a profit sharing plan covering full-time employees. The +Company's contributions to this plan are discretionary. +(Continued) +PETROLEUM +DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to +Consolidated Financial Statements +The +Company has a deferred compensation arrangement covering executive officers of +the Company as a supplemental retirement benefit. +Revenue +Recognition +The +Company's drilling segment recognizes revenue from our drilling contracts with +our publicly registered drilling programs using the percentage of completion +method. These contracts are footage rate based and completed within nine to +twelve months after the commencement of drilling. The Company provides +geological, engineering, and drilling supervision on the drilling and +completion process and uses subcontractors to perform drilling and completion +services. The percentage of completion method measures the percentage of +contract costs incurred to date to the estimated total contract costs for each +contract. The Company utilizes this method because reasonably dependable +estimates of the total estimated costs can be made. Because the revenue +recognized depends on estimates of the final contract costs, which are assessed +continually during the term of the contract, recognized revenues are subject to +revisions as the contract progresses. Anticipated losses, if any, on +uncompleted contracts would be recorded at the time that our estimated costs +exceeded the contract revenue. The Company has not experienced any contract +losses in 2004, 2003, or 2002. +Natural gas marketing is +recorded on the gross accounting method. Riley Natural Gas ("Riley"), our +marketing subsidiary, purchases gas from many small producers and bundles the +gas together to sell in larger amounts to purchasers of natural gas for a price +advantage. Riley has latitude in establishing price and discretion in supplier +and purchaser selection. Natural gas marketing revenues and expenses reflect +the full cost and revenue of those transactions because Riley takes title to +the gas it purchases from the various producers and bears the risks and enjoys +the benefits of that ownership. +Sales of natural gas are +recognized when natural gas has been delivered to a custody transfer point, +persuasive evidence of a sales arrangement exists, the rights and +responsibility of ownership pass to the purchaser upon delivery, collection of +revenue from the sale is reasonably assured and the sales price is fixed or +determinable. Natural gas is sold by the Company under contracts with terms +ranging from one month to three years. Virtually all of the Company's contracts +pricing provisions are tied to a market index, with certain adjustments based +on, among other factors, whether a well delivers to a gathering or transmission +line, quality of natural gas and prevailing supply and demand conditions, so +that the price of the natural gas fluctuates to remain competitive with other +available natural gas supplies. As a result, the Company's revenues from the +sale of natural gas will suffer if market prices decline and benefit if they +increase. The Company believes that the pricing provisions of its natural gas +contracts are customary in the industry. +Company currently uses the +"Net-Back" method of accounting for transportation arrangements of our natural +gas sales. The Company sells gas at the wellhead and collects a price and +recognizes revenues based on the wellhead sales price since transportation +costs downstream of the wellhead are incurred by our customers and reflected in +the wellhead price. +Sales of oil are recognized +when persuasive evidence of a sales arrangement exists, the oil is verified as +produced and is delivered in a stock tank, collection of revenue from the sale +is reasonably assured and the sales price is determinable. The Company is +currently able to sell all the oil that it can produce under existing sales +contracts with petroleum refiners and marketers. The Company does not refine +any of its oil production. The Company's crude oil production is sold to +purchasers at or near the Company's wells under short-term purchase contracts +at prices and in accordance with arrangements that are customary in the oil +industry. +Well operations and +pipeline income is recognized when persuasive evidence of an arrangement +exists, services have been rendered, collection of revenues is reasonably +assured and the sales price is fixed or determinable. The Company is paid a +monthly operating fee for each well it operates for outside owners including +the limited partnerships sponsored by the Company. The fee is competitive with +rates charged by other operators in the area. The fee covers monthly operating +and accounting costs, insurance and other recurring costs. The Company may +also receive additional compensation for special non-recurring activities, such +as reworks and recompletions. +(Continued) +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +Income +Taxes +Income +taxes are accounted for under the asset and liability method. +Deferred +tax assets and liabilities are recognized for the future tax consequences +attributable to differences between the financial statement carrying amounts of +existing assets and liabilities and their respective tax bases. Deferred tax +assets and liabilities are measured using enacted tax rates expected to apply +to taxable income in the years in which those temporary differences are +expected to be recovered or settled. The effect on deferred tax assets and +liabilities of a change in tax rates is recognized in income in the period that +includes the enactment date. +Derivative +Financial Instruments +The +Company accounts for derivatives and hedging in accordance with FASB Statement +No. 133 Accounting for Derivative Instruments and Certain Hedging Activities, +as amended which requires that all derivatives be recorded on the consolidated +balance sheet at their fair values. On the date the derivative contract is +entered into, the Company designates the derivative as either a hedge of a +forecasted transaction or the variability of cash flows to be received or paid +related to a recognized asset or liability ("Cash flow" hedge), or a +non-hedging derivative. The Company formally documents all relationships +between hedging instruments and hedged items, as well as its risk-management +objective and strategy for undertaking various hedge transactions. This process +includes linking all derivatives that are designated as cash-flow hedges to +specific firm commitments. The Company also formally assesses, both at the +hedge's inception and on an ongoing basis, whether the derivatives that are +used in hedging transactions are highly effective in offsetting changes in cash +flows of hedged items. When it is determined that a derivative is not highly +effective as a hedge or that it has ceased to be a highly effective hedge, the +Company discontinues hedge accounting prospectively. No hedging activities +were discontinued during 2004, 2003 or 2002. +Changes +in fair value of a derivative that is highly effective and that is designated +and qualifies as a cash-flow hedge are recorded in other comprehensive income, +until earnings are affected by the variability in cash flows of the designated +hedged item. Changes in the fair value of non-hedging derivatives are reported +in current-period earnings. The Company discontinues hedge accounting +prospectively when it is determined that the derivative is no longer effective +in offsetting changes in the cash flows of the hedged item, the derivative +expires or is sold, terminated, or exercised. Additionally, if the derivative +is designated as a hedging instrument, and it is subsequently determined to be +probable that a forecasted transaction will not occur or management determines +that designation of the derivative as a hedging instrument is no longer +appropriate, hedge accounting will be discontinued. +The +Company uses derivative financial instruments for several purposes. The Company +manages its exposure to price fluctuations in selling and producing natural gas +by entering into natural gas future contracts and options contracts. +Stock +Compensation +The +Company applies the intrinsic-value based method of accounting prescribed by +Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued +to Employees", and related interpretations including FASB Interpretation No. +44, "Accounting for Certain Transactions involving Stock Compensation, an +interpretation of APB Opinion No. 25", to account for its fixed-plan stock +options. Under this method, compensation expense is recorded on the date of +grant only if the current market price of the underlying stock exceeded the +exercise price. FASB Statement No. 123, "Accounting for Stock-Based +Compensation" and FASB Statement No. 148, "Accounting for Stock Based +Compensation- Transition and Disclosure, an amendment of FASB Statement No. +123", established accounting and disclosure requirements using a +fair-value-based method of accounting for stock-based employee compensation +plans. As permitted by existing accounting standards, the Company has elected +to continue to apply the intrinsic-value-based method of accounting described +above, and has adopted only the disclosure requirements of Statement 123, as +amended. If the fair-value-based method had been applied to all outstanding +and unvested awards in each period, the impact in 2004 would have been $18,400. +There would have been no impact or reported net income in 2003 or 2002. +(Continued) +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +Compensation +expense for stock options is measured as the excess, if any, of the quoted +market price of the Company stock at the date of the grant over the amount an +optionee must pay to acquire the stock. The Company records compensation +expense for restricted stock awards based on the quoted market price of the +Company' stock at the date of grant and vesting period. +The +pro forma amounts that would have been reported if FASB 123 had been in effect +for all years are based on the fair value of the stock-based awards granted for +each year and recognized over the vesting period. +The +fair value at date of grant for a common stock option granted under Company's +option plan during 2004 was $16.75. The fair value of each option granted +during 2004 was estimated on the date of grant using the Black-Scholes +option-pricing model with the following weighted-average assumptions. +Dividend yield +0% +Expected volatility +39.71% +Risk-free interest rate +4.06% +Expected option life (in years) +7.0 +As of +December 31, 2004, there was approximately $283,000 of total unrecognized, +pre-tax compensation cost related to non-vested stock options. This cost is +expected to be recognized over four years. The Company will adopt the +provisions of FASB Statement No. 123R (revised 2004), Share-Based Payment, in +2005 regarding stock compensation as discussed below. The Company will adopt +the provisions of FASB Statement No. 123R (revised 2004), "Share-Based +Payment", in 2005 regarding stock compensation as discussed below. Upon +adoption of FASB Statement No. 123R, such cost will be recognized directly in +our consolidated statement of income. +Use +of Estimates +Management +of the Company has made a number of estimates and assumptions relating to the +reporting of assets and liabilities and revenues and expenses and the +disclosure of contingent assets and liabilities to prepare these financial +statements in conformity with generally accepted accounting principles. Actual +results could differ from those estimates. Estimates which are particularly +significant to the consolidated financial statements include estimates of oil +and gas reserves and future cash flows from oil and gas properties. +Fair +Value of Financial Instruments +The +carrying values of the Company's receivables, payables and debt obligations are +estimated to be substantially the same as the fair values as of December 31, +2004, 2003 and 2002. +New +Accounting Standards +The +FASB issued FIN 46, "Consolidation of Variable Interest Entities", in January +2003 and amended the interpretation in December 2003. A variable interest +entity (VIE) is an entity in which its voting equity investors lack the +characteristics of having a controlling financial interest or where the +existing capital at risk is insufficient to permit the entity to finance its +activities without receiving additional financial support from other parties. +FIN 46 requires the consolidation of entities which are determined to be VIEs +when the reporting company determines itself to be the primary beneficiary (the +entity that will absorb a majority of the VIE's expected losses, receive a +majority of the VIE's residual returns, or both). The amended interpretation +was effective for the first interim or annual reporting period ending after +March 15, 2004, with the exception of special purpose entities for which the +statement was effective for periods ending after December 15, 2003. We have +completed a review of our partnership investments and have determined that +those entities do not qualify as VIEs. +(Continued) +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +On +December 16, 2004, the Financial Accounting Standards Board (FASB) issued FASB +Statement No. 123R (revised 2004), "Share-Based Payment" which is a revision of +FASB Statement No. 123, "Accounting for Stock-Based Compensation". Statement +123R supercedes APB opinion No. 25, "Accounting for Stock Issued to Employees", +and amends FASB Statement No. 95, "Statement of Cash Flows". Generally, the +approach in Statement 123R is similar to the approach described in Statement +123. However, Statement 123R requires all share-based payments to employees, +including grants of employee stock options, to be recognized in the income +statement based on their fair values. Pro-forma disclosure is no longer an +alternative. The provisions of this statement becomes effective for our third +quarter 2005. Management has not determined the impact that this statement +will have on our consolidated financial statements. +(2) Notes +and Accounts Receivable +Included +in other assets are noncurrent accounts receivable as of December 31, 2004 and +2003, in the amounts of $608,500 and $819,700 less of an allowance for +doubtful accounts of $244,400 and $338,100, respectively. +The +allowance for doubtful current accounts receivable as of December 31, 2004 and +2003 was $164,600 and $149,200, respectively. +(3) Long-Term +Debt +The +Company has a credit facility with J. P. Morgan Chase Bank NA (formerly Bank +One, NA) and BNP Paribas of $100 million subject to and secured by adequate +levels of oil and gas reserves. The current total borrowing base is $80.0 +million of which the Company has activated $60 million of the facility. The +Company is required to pay a commitment fee of 1/4 percent on the unused +portion of the activated credit facility. Interest accrues at prime, with LIBOR +(London Interbank Market Rate) alternatives available at the discretion of the +Company. No principal payments are required until the credit agreement expires +on July 3, 2008. +As of +December 31, 2004 and 2003 the outstanding balance was $21,000,000 and +$53,000,000, respectively. Any amounts outstanding under the credit facility +are secured by substantially all properties of the Company. The credit +agreement requires, among other things, the existence of satisfactory levels of +natural gas reserves, maintenance of certain working capital and tangible net +worth ratios along with a restriction on the payment of dividends. As of +December 31, 2004 and 2003 the Company was in compliance with all financial +covenants in the credit agreement. At December 31, 2004, the outstanding balance +was subject to a prime rate of 5.25%. +(4) Income +Taxes +The +Company's provision for income taxes consisted of the following: +2004 +2003 +2002 +Current: +Federal +$8,426,400 +2,401,000 +604,200 +State +1,672,500 +834,100 +206,800 +Total current +income taxes +10,098,900 +3,235,100 +811,000 +Deferred: +Federal +8,900,300 +7,802,800 +2,461,200 +State +1,543,300 +1,067,900 +525,200 +Total deferred +income taxes +10,443,600 +8,870,700 +2,986,400 +Total income taxes +$20,542,500 +12,105,800 +3,797,400 +Income tax expense differed from the amounts computed +by applying the U.S. federal income tax rate of 35 percent in 2004 and 2003 +and 34 percent in 2002 to pretax income as a result of the following: +(Continued) +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +2004 +2003 +2002 +Computed +"expected" tax +$19,111,100 +12,223,200 +4,447,900 +State income tax +2,129,500 +1,362,000 +483,100 +Percentage +depletion +(794,100) +(935,000) +(680,000) +Nonconventional +source fuel credit +- +(186,600) +(491,500) +Officers life +insurance +- +(360,000) +- +Surtax exemption +- +(100,000) +- +Change in federal +rate bracket +- +254,700 +- +Other +96,000 +(152,500 ) +37,900 +$ 20,542,500 +12,105,800 +3,797,400 +The tax effects of +temporary differences that give rise to significant portions of the deferred +tax assets and deferred tax liabilities at December 31, 2004 and 2003 are +presented below: +2004 +2003 +Deferred tax +assets: +Allowance +for doubtful accounts +$ 159,100 +189,500 +Drilling +notes +57,200 +73,500 +Alternative +minimum tax credit carryforwards (Section 29) +- +437,400 +Future +abandonment +725,500 +614,900 +Deferred +compensation +692,100 +1,784,200 +Asset Retirement +Obligations +121,700 +121,700 +Accumulated +Other Comprehensive Income +1,531,200 +750,500 +Other +21,800 +27,700 +Total +gross deferred tax assets +3,308,600 +3,999,400 +Less +valuation allowance +- +- +Deferred +tax assets +3,308,600 +3,999,400 +Less +current deferred tax assets +(included +in other current assets) +(337,300 ) +(1,957,400 ) +Net +non-current deferred tax assets +2,971,300 +2,042,000 +Deferred tax +liabilities: +Properties +and equipment, principally due to differences in +depreciation +and amortization +(32,814,500 ) +(23,842,200 ) +Total +gross deferred tax liabilities +(32,814,500 ) +(23,842,200 ) +Net +non-current deferred tax liability +$ (29,843,200 ) +(21,800,200 ) +Accumulated other +comprehensive loss is net of tax of $1,531,200, $750,500 and $1,092,200 as of +December 31, 2004, 2003 and 2002, respectively. +In assessing the +realizability of deferred tax assets, management considers whether it is more +likely than not that some portion or all of the deferred tax assets will not be +realized. The ultimate realization of deferred tax assets is dependent upon the +generation of future taxable income during the periods in which those temporary +differences become deductible. Based upon the level of historical taxable +income and projections for future taxable income over the periods in which the +deferred tax assets are deductible, management believes it is more likely than +not that the Company will realize the benefits of these deductible differences.. +The amount of the deferred tax asset considered realizable, however, could be +reduced in the near term if estimates of future taxable income during the +carryforward period are reduced. +(Continued) +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +Employee stock +options exercised during the year 2004 resulted in an income tax benefit of $7,394,800 +that is reflected in Stockholders' Equity and as a reduction of current tax +payable. +The deferred tax +asset related to AOCI increased in 2004 by $780,700 and decreased in 2003 by +$341,700. +(5) Common +Stock +Stock-Based +Compensation Plans +As of December 31, +2004, the Company has several stock-based compensation plans for certain +employees and officers. These plans are described below: +The Company +maintains a long-term equity compensation plan for officers and certain key +employees of the company. Under the plan, approved by the shareholders in June +2004, awards may be issued in the form of stock options, stock appreciation +rights, restricted stock, or performance shares. A total of 750,000 shares of +common stock have been reserved for issuance. During 2004, 23,380 shares were +granted with restriction periods of four years at the market price on the date +of issuance as deferred compensation and the related amount is being amortized +to operations over the respective vesting period. Compensation expense for the +year ended December 31, 2004 related to these shares of restricted stock was +$21,100. +Options amounting to +16,880 shares were granted during 2004 to certain employees and directors under +the Company's Stock Option Plan. These options were granted with an exercise +price equal to the market value of the Company's common stock as of the date of +grant and vest over a four year period. The outstanding options expire in 2014. +The following table +summarized the activity of the Company's option plans: +Number +of Shares +Average +Exercise +Price +Range of +Exercise +Prices +Outstanding +December 31, 2001 +1,230,000 +$4.29 +1.125 - 6.25 +Exercised +(70,000 ) +$1.125 +1.125 - 1.125 +Outstanding +December 31, 2002 +1,160,000 +$4.48 +1.125 - 6.25 +Granted +- +- +- +Exercised +- +- +- +Outstanding +December 31, 2003 +1,160,000 +$4.48 +1.125 - 6.25 +Granted +16,880 +$37.15 +37.15 +Exercised +(1,100,000) +$4.48 +1.125-6.25 +Outstanding +December 31, 2004 +76,880 +$11.64 +3.875-37.15 +(Continued) +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +Options +outstanding under the Company's plans as of December 31, 2004: +Range of Exercise Price +Options +Outstanding +Remaining +Life +Options +Exercisable +Weighted-Average +Exercise Price +$3.75 - $6.25 +60,000 +3.9 years +60,000 +$5.40 +$37.15 +16,880 +10 years +- +$37.15 +Total +76,880 +60,000 +Common +Stock Repurchase +On +March 13, 2003 the Company publicly announced the authorization by its Board of +Directors to repurchase up to 5% of the Company's common stock (785,000 shares) +at fair market value at the date of purchase. Under the program, the Board had +discretion as to the dates of purchase and amounts of stock to be purchased and +whether or not to make purchases. From inception of the program until December +31, 2004, the Company has repurchased 109,200 shares at an average price of +$6.86. This program expired on December 31, 2004. The following activity has +occurred since inception of the plan on March 13, 2003 until December 31, 2004. +Month of Purchase +March, 2003 +April, 2003 +September, 2003 +Average Price paid per share +$6.08 +$6.48 +$11.15 +Broker/Dealer +McDonald Investments +McDonald Investments +McDonald Investments +Number of Shares Purchased +46,500 +49,900 +12,800 +Remaining Number of Shares +to Purchase +738,500 +688,600 +675,800 +In +March 2004, the Compensation Committee of the Board of Directors approved a +repurchase of 48,650 shares of common stock from one of the Company's +officers. The repurchase price of the common stock was the closing price on +the date of the repurchase of $26.61 per share and totaled $1,294,600 which +approximated the tax savings to be realized by the Company as a result of the +exercise of said officer's non-qualified stock options in 2004. The Company +also repurchased 1,703 shares from an employee upon retirement from the Company +in June, 2004. Such treasury stock was subsequently cancelled. +At a +meeting held on Friday, March 18, 2005 the Board of Directors of Petroleum +Development Corporation approved a stock repurchase plan to allow the Company +to repurchase up to 2% of the Company's common stock in 2005. The Company +intends at a minimum to purchase adequate shares to insure no dilution from +employee stock compensation plans and may also make open market purchases from +time to time. +Stock +Repurchase Agreement +The +Company has stock repurchase agreements with four executive officers of the +Company. The agreements require the Company to maintain life insurance on each +executive in the amount of $1,000,000. The agreements provide that the Company +shall utilize the proceeds from such insurance to purchase from such +executives' estates or heirs, at their option, shares of the Company's stock. +The purchase price for the outstanding common stock is to be based upon the +average closing asked price for the Company's stock as quoted by NASDAQ on the date +of purchase. The Company is not required to purchase any shares in excess of +the amount provided for by such insurance. During the fourth quarter of 2003, +the Company received $1,000,000 in life insurance proceeds which was recorded +as other income from the death of the Company's Chief Financial Officer who had +a stock repurchase agreement. In May 2004, the Company repurchased 50,487 +shares of common stock from the estate of the Company's former officer in +accordance with the terms of this agreement. The repurchase price of the stock +was $27.73 per share (the 90-day average prior to the repurchase per +contract). The repurchase totaled $1,400,000 of which $1,000,000 was funded by +the life insurance proceeds. +(Continued) +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +(6) Employee +Benefit Plans +The +Company sponsors a qualified deferred compensation plan that enables eligible +employees to contribute a portion of their compensation through payroll +deductions in accordance with specific guidelines. The Company matches a +percentage of the employees' contributions up to certain limits. Expenses +related to this plan amounted to $382,700, $305,500 and $288,000 for 2004, 2003 +and 2002, respectively. +The +Company has a profit sharing plan (the Plan) covering full-time employees. The +Company contributed $300,000, $250,000 and $200,000 to the plan in cash during +2004, 2003 and 2002, respectively. +During +2003 and 2002 the Company expensed $90,000 each year under a deferred +compensation arrangement with certain executive officers of the Company. These +amounts were paid during 2003 to such executive officers. +The +Company has a deferred compensation arrangement covering certain executive +officers of the Company as a supplemental retirement benefit. During 2004, 2003 +and 2002 the Company expensed $171,900, $181,900 and $171,600, respectively, +and has recorded a related liability in the amount $1,000,200 and $868,300 as +of December 31, 2004 and 2003, respectively. The Company began paying the +retirement benefit during 2004 to the estate of one of the Company's former +officers. The Company paid $40,000 during 2004. +The +Company maintains a non-qualified deferred compensation plan created for +non-employee directors of the Company. The amount of compensation deferred by +each Participant is based on Participant elections. +(7) Earnings Per Share +2004 +2003 +2002 +Basic earnings per common share: +Net income before cumulative effect of change in +accounting principle +$34,060,600 +22,817,700 +9,284,800 +Cumulative effect of accounting change, net of tax +(198,600) +Net income +34,060,600 +22,619,100 +9,284,800 +Weighted average common shares outstanding +16,240,604 +15,659,591 +15,866,363 +Basic earnings per common share +$ 2.10 +$ 1.45 +$ 0.59 +Diluted earnings per common and common +equivalent share: +Net income before cumulative effect of change in +Accounting principle +34,060,600 +22,817,700 +9,284,800 +Cumulative effect of accounting change, net of tax +- +(198,600) +- +Net income applicable to common stock +34,060,600 +22,619,100 +9,284,800 +Weighted average common shares outstanding +16,240,604 +15,659,591 +15,866,363 +Potentially dilutive securities: +Stock options +406,570 +638,202 +277,051 +Weighted average common and common equivalent +shares outstanding +16,647,174 +16,297,793 +16,143,414 +Diluted earnings per common share +$ 2.05 +$ 1.39 +$0.58 +(8) Transactions with Affiliates +Funds +held for future distribution on the consolidated balance sheet of $12,911,800 +and $8,410,900 primarily represents amounts owed to affiliated partnerships as +of December 31, 2004 and 2003, respectively. +(Continued) +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +The +Company provided oil and gas well drilling services and well operations +services to affiliated partnerships. Substantially all of the Company's oil and +gas well drilling operations, well operations and pipeline income and other +income (except for $1.0 million of life insurance proceeds in 2003 discussed in +Note 5) was for such partnerships. Related services of tax return preparation +and other services relating to the operation of the partnerships are recorded +in other income. Amounts due from the affiliated partnerships as of December +31, 2004 and 2003 were $68,100 and $929,600, and are included in notes and +accounts receivable. +The +Company through its wholly-owned subsidiary, PDC Securities Incorporated, acts +as Dealer-Manager of the Public Drilling Partnerships. PDC Securities +Incorporated receives the applicable commissions and marketing allowances from +the Escrow Agent of the Drilling Program and distributes them to the Soliciting +Broker/Dealers who sell the programs. The commissions and marketing allowances +received by PDC Securities are included in other income net of the commissions +distributed to the soliciting broker/dealers in the amounts of $9,747,600, +$7,994,300 and $5,792,300 for the years ended December 31, 2004, 2003 and 2002, +respectively. The net commissions and marketing allowance amounts included in +other income were less than $1,000 for each of the years ending December 31, +2004, 2003 and 2002. +During +2004, 2003 and 2002, the Company paid $22,500, $30,000 and $51,800, +respectively, to the Corporate Secretary's law firm for various legal services. +(9) Commitments and Contingencies +The +nature of the independent oil and gas industry involves a dependence on outside +investor drilling capital and involves a concentration of gas sales to a few +customers. The Company sells natural gas to various public utilities and +industrial customers. No customer accounted for 10% or more of the Company's +total revenues in 2004. One customer accounted for 10.3% and 10.8% of total +revenues in 2003 and 2002, respectively. +The +Company would be exposed to natural gas price fluctuations on underlying purchase +and sale contracts should the counterparties to the Company's hedging +instruments or the counterparties to the Company's gas marketing contracts not +perform. Such nonperformance is not anticipated. There were no counterparty +default losses in 2004, 2003 or 2002. +Substantially +all of the Company's drilling programs contain a repurchase provision where +Investing Partners may request the Company to purchase their partnership units +at any time beginning with the third anniversary of the first cash distribution. +The provision provides that the Company is obligated to purchase an aggregate +of 10% of the initial subscriptions per calendar year (at a minimum price of +four times the most recent 12 months' cash distributions), only if such units +are requested by the investors, subject to the Company's financial ability to +do so. The maximum annual 10% repurchase obligation, if requested by the +investors, is currently approximately $6.6 million. The Company has adequate +liquidity to meet this obligation. During 2004, the Company paid $408,260 under +this provision for the repurchase of partnership units. +The Company's drilling programs formed +since 1996 contain a performance standard which states that if certain +performance levels are not met, the Company must remit a payment equal to +one-half of its share of revenue from such partnership to the investing +partners. During 2004, 2003, and 2002 the Company paid partnerships a total of +$597,300, $385,400 and $198,500, respectively in accordance with the provision. +During +the fourth quarter of 2003, the Company recorded a liability in accordance with +the death benefit of the employment contract of the Company's Chief Financial +Officer in the amount of $852,700. +As +Managing General Partner of 10 private partnerships and 62 public partnerships +the Company has liability for any potential casualty losses in excess of the +partnership assets and insurance. The Company's management believes its and its +subcontractors casualty insurance coverage is adequate to meet this potential +liability. +In +order to secure the services for drilling rigs, the Company makes commitments +to the drilling contractor which call for penalties for a specified amount of +time if the Company ceases to use such drilling rigs, an event that is not anticipated +to occur. As of December 31, 2004, the Company has an outstanding commitment +for $1,604,250. +(Continued) +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +The +Company drilled one exploratory well in 2004 and plans additional exploratory +wells in 2005. As of the date of this report, the exploratory well had been +completed and testing was underway but the well had not been classified as +successful or dry. Testing of the well was suspended in January due to lease +restrictions on the Federal lease. We expect to resume testing in the second +quarter of 2005. If the well is determined to be a dry hole, its costs will be +expensed in the period when the determination is made as required by the +successful efforts method of accounting. The cost of the well as of December +31, 2004 is $4,169,903. +From +time to time the Company is a party to various legal proceedings in the +ordinary course of business. The Company is not currently a party to any +litigation that it believes would have a materially adverse affect on the +Company's business, financial condition, results of operations, or liquidity. +(10) Lease +Obligations +The +Company has entered into certain operating leases on behalf of itself and its +Partnerships principally for the leasing of natural gas compressors on its Michigan operating facilities and office printing and copying equipment. The future minimum +lease payments under these non-cancelable operating leases as of December 31, +2004 are as follows: +Year +Lease Amount +2005 +$307,900 +2006 +209,400 +2007 +153,900 +2008 +127,200 +2009 +45,300 +Thereafter +52,000 +$895,700 +The Company's share +of this lease expense for operating leases for the years ended December 31, +2004, 2003 and 2002 was $310,000, $574,700 and $660,700, respectively. +(11) Supplemental Disclosure of Cash Flows +The +Company paid $1,049,200, $1,274,003 and $1,290,400 for interest in 2004, 2003 +and 2002, respectively. The Company paid income taxes in 2004, 2003 and 2002 +in the amounts of $5,027,800, $3,649,600 and $175,000, respectively. +During 2004 options +were exercised by exchanging mature shares with a fair value of $1,408,300. All +these mature shares were subsequently cancelled. +(12) Purchases +of Oil and Gas Properties +During +the second quarter of 2003, the Company purchased 166 wells in the Denver Julesburg Basin in northeastern Colorado from Williams Production RMT Company for $28 +million. The Company estimates the acquisition included approximately 22.6 +billion cubic feet (Bcf) of proved developed producing (PDP) and 3.4 Bcf of +proved developed non-producing reserves (PDNP), all of which is natural gas. +The Company received approval for increased density well spacing in 2004. The +Company drilled twenty new Niobrara wells on the property in 2004. The Company +estimates that there are approximately 100 remaining increased density well +locations, approximately 60 of which the Company plans to develop in 2005. +During +the fourth quarter of 2003, the Company purchased from one of its unaffiliated +joint venture partners in the Denver-Julesburg Basin in Weld County, Colorado +approximately 3.1 billion cubic feet equivalent (Bcfe) of proved developed +producing reserves from interests in 20.6 net wells (230 gross) and 1.8 Bcfe of +proved developed non-producing reserves from interests in 17 net wells (183 +gross). The purchase price was $5.2 million which also included over 30 +additional drilling locations. +(Continued) +PETROLEUM +DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated +Financial Statements +During +the fourth quarter of 2003, the Company purchased from an unaffiliated party 97 +gross wells (73 net) in the Denver-Julesburg Basin located in northeast Colorado and northwestern Kansas for $6.0 million. This purchase added approximately 4.5 +billion cubic feet equivalent (Bcfe) of proved developed producing and proved +developed non-producing reserves to the Company's oil and gas reserves along +with 100,000 acres of oil and gas leases. +(13) Derivative +Financial Instruments +The futures and option +contracts hedge forecasted natural gas purchases and sales, generally +forecasted to occur within a three year period. The Company does not hold or +issue derivatives for trading or speculative purposes. In addition, an interest +rate swap agreement was used to reduce the potential impact of increases in +interest rates on variable rate long-term debt. +The Company utilizes +commodity-based derivative instruments as hedges to manage a portion of its +exposure to price risk from its natural gas sales and marketing activities. +These instruments consist of NYMEX-traded natural gas futures contracts and +option contracts for Appalachian and Michigan production and CIG-based +contracts traded by JP Morgan Chase Bank, NA for Colorado production. These +hedging arrangements have the effect of locking in for specified periods (at +predetermined prices or ranges of prices) the prices the Company will receive +for the volume to which the hedge relates and, in the case of RNG, the cost of +gas supplies purchased for marketing activities. As a result, while these +hedging arrangements are structured to reduce the Company's exposure to changes +in price associated with the hedged commodity, they also limit the benefit the +Company might otherwise have received from price increases associated with the +hedged commodity. The Company's policy prohibits the use of natural gas future +and option contracts for speculative purposes. +The following +tables summarize the open futures and options contracts for Riley Natural Gas +and +PDC as of +December 31, 2004 and 2003. +Riley Natural Gas +Open Futures Contracts +Commodity +Type +Quantity +Gas-Mmbtu +Oil-Barrels +Weighted +Average +Price +Total +Contract +Amount +Fair +Market +Value +Total +Contracts as of December 31, 2004 +Natural Gas +Sale +3,260,000 +$5.60 +$18,249,250 +($1,982,964) +Natural Gas +Purchase +1,130,000 +$6.77 +$7,644,540 +($486,490) +Natural Gas +Floor +530,000 +$5.30 +$134,242 +Natural Gas +Ceiling +265,000 +$7.00 +($85,541) +Contracts maturing +in 12 months following December 31, 2004 +Natural Gas +Sale +2,230,000 +$5.84 +$13,014,810 +($841,102) +Natural Gas +Purchase +860,000 +$6.94 +$5,965,490 +($591,340) +Natural Gas +Floor +530,000 +$5.30 +$134,242 +Natural Gas +Ceiling +265,000 +$7.00 +($85,541) +Prior Year +Total Contracts as of December 31, 2003 +Natural Gas +Sale +2,660,000 +$4.58 +$12,174,130 +($1,810,500) +Natural Gas +Purchase +820,000 +$5.17 +$4,243,420 +$270,200 +The maximum +term over which RNG is hedging exposure to the variability of cash flows for +commodity +price risk is +27 months. +(Continued) +PETROLEUM +DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to +Consolidated Financial Statements +Petroleum Development Corporation +Open Futures Contracts +Commodity +Type +Quantity +Weighted +Total +Fair +Gas-Mmbtu +Average +Contract +Market +Oil-Barrels +Price +Amount +Value +Total +Contracts as of December 31, 2004 +Natural Gas +Purchase +46,776 +$6.63 +$310,339 +($17,806) +Natural Gas +Floor +3,562,020 +$4.56 +$337,842 +Natural Gas +Ceiling +1,556,010 +$5.39 +($1,526,868) +Crude Oil +Floor +166,536 +$32.30 +$141,880 +Crude Oil +Ceiling +83,268 +$40.00 +($450,405) +Contracts +maturing in 12 months following December 31, 2004 +Natural Gas +Sale +Natural Gas +Purchase +46,776 +$6.63 +$310,339 +($17,806) +Natural Gas +Floor +3,562,020 +$4.56 +$337,842 +Natural Gas +Ceiling +1,556,010 +$5.39 +($1,526,868) +Crude Oil +Floor +166,536 +$32.30 +$141,880 +Crude Oil +Ceiling +83,268 +$40.00 +($450,405) +Prior Year Total +Contracts as of December 31, 2003 +Natural Gas +Sale +53,300 +$5.40 +$288,000 +($40,000) +Natural Gas +Purchase +45,700 +$4.77 +$218,100 +$30,400 +Natural Gas +Floor +2,597,800 +$4.29 +$185,300 +Natural Gas +Ceiling +691,200 +$5.23 +($127,800) +The maximum term over which PDC is +hedging exposure to the variability of cash flows for commodity price risk is +12 months +The Company is required to +maintain margin deposits with brokers for outstanding futures contracts. As of +December 31, 2004 and 2003, cash in the amount of $664,900 and $1,866,400 was +on deposit. +An interest rate swap +agreement was used to reduce the potential impact of increases in interest +rates on variable rate long-term debt. Such swap agreement expired in October +2004. At December 31, 2003, the Company was a party to an interest rate swap +agreement which expired on October 11, 2004. The agreement required the +Company, on a quarterly basis, to make a fixed-rate interest payment of 6.89% +plus its current LIBOR rate margin (+1.50% At December 31, 2003) on a +$10,000,000 amount related to its outstanding line of credit. +The fair value of the +interest rate swap agreement was $(436,800), $(266,900) net of tax at December +31, 2003. Current market pricing models were used to estimate fair value. +By using derivative +financial instruments to hedge exposures to changes in interest rates and +commodity prices, the Company exposes itself to credit risk and market risk. +Credit risk is the failure of the counterparty to perform under the terms of +the derivative contract. When the fair value of a derivative contract is +positive, the counterparty owes the Company, which creates repayment risk. The +Company minimizes the credit or repayment risk in derivative instruments by +entering into transactions with high-quality counterparties. +Changes in the fair value +of natural gas futures contracts designated as hedging instruments and that +effectively offset the variability of cash flows associated with anticipated +sales of natural gas are reported in accumulated other comprehensive income +(AOCI). These amounts subsequently are reclassified into gas purchases for RNG +and gas sales for PDC when the related gas is sold and affects earnings. +Changes in the fair value of the interest rate swap agreement were reclassified +into interest expense. +PETROLEUM +DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to +Consolidated Financial Statements +(14) Costs Incurred in Oil and Gas Property +Acquisition, Exploration and Development Activities +Costs +incurred by the Company in oil and gas property acquisition, exploration and +development are presented below: +Years Ended December 31, +2004 +2003 +2002 +Property acquisition cost: +Proved undeveloped properties +$ 4,583,000 +6,167,800 +1,892,700 +Producing properties +720,000 +33,946,600 +240,000 +Development costs +36,870,400 +30,630,100 +16,429,400 +$ 42,173,400 +70,744,500 +18,562,100 +The +proved reserves attributable to the development costs in the above table were +40,716,000 Mcf and 358,000 bbls for 2004, 27,719,000 Mcf and 517,000 bbls for +2003 and 19,607,000 Mcf and 130,000 bbls for 2002 (amounts unaudited). Of the +above development costs incurred for the years ended December 31, 2004, 2003 +and 2002 the amounts of $1,819,619, $4,289,600 and $2,699,500, respectively, +were incurred to develop proved undeveloped properties from the prior year end. +Property +acquisition costs include costs incurred to purchase, lease or otherwise +acquire a property. Development costs include costs incurred to gain access to +and prepare development well locations for drilling, to drill and equip +development wells, recompletions and to provide facilities to extract, treat, +gather and store oil and gas. +(15) Oil +and Gas Capitalized Costs +Aggregate +capitalized costs for the Company related to oil and gas exploration and +production activities with applicable accumulated depreciation, depletion and +amortization are presented below: +December 31, +2004 +2003 +Proved properties: +Tangible well equipment +$157,787,800 +$133,356,900 +Intangible drilling costs +123,171,200 +110,087,300 +Undeveloped properties +9,864,300 +7,576,900 +Capitalized asset retirement cost +613,400 +537,800 +291,436,700 +251,558,900 +Less accumulated depreciation, +depletion and amortization +80,762,100 +64,205,100 +$ 210,674,600 +$ 187,353,800 +(16) Results +of Operations for Oil and Gas Producing Activities +The +results of operations for oil and gas producing activities (excluding +marketing) are presented below: +Years +Ended December +31, +2004 +2003 +2002 +Revenue: +Oil and gas sales +$67,947,700 +47,021,600 +22,857,100 +Expenses: +Production costs +14,974,000 +10,212,500 +6,407,900 +Depreciation, depletion and +amortization +16,482,600 +12,997,600 +11,149,000 +31,456,600 +23,210,100 +17,556,900 +PETROLEUM +DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to +Consolidated Financial Statements +Results of operations for oil and gas +producing activities before provision +for income taxes +36,491,100 +23,811,500 +5,300,200 +Provision for income taxes +13,728,000 +8,262,600 +1,538,400 +Results of operations for oil and gas +producing activities (excluding corporate +overhead and interest costs) +$ 22,763,100 +15,548,900 +3,761,800 +Production +costs include those costs incurred to operate and maintain productive wells and +related equipment, including such costs as labor, repairs, maintenance, +materials, supplies, fuel consumed, insurance and other production taxes. In +addition, production costs include administrative expenses and depreciation +applicable to support equipment associated with these activities. +Depreciation, +depletion and amortization expense includes those costs associated with +capitalized acquisition, exploration and development costs, but does not +include the depreciation applicable to support equipment. +The +provision for income taxes is computed using the Company's effective tax rate. +(17) Net +Proved Oil and Gas Reserves (Unaudited) +The +proved reserves of oil and gas of the Company have been estimated by an +independent petroleum engineer, Wright & Company, Inc. at December 31, +2004, 2003 and 2002. These reserves have been prepared in compliance with the +Securities and Exchange Commission rules based on year end prices. An analysis +of the change in estimated quantities of oil and gas reserves, all of which are +located within the United States, is shown below: +Oil +(BBLS) +2004 +2003 +2002 +Proved developed and undeveloped reserves: +Beginning of year +3,029,000 +2,073,000 +2,126,000 +Revisions of previous estimates +305,000 +533,000 +124,000 +Beginning of year as revised +3,334,000 +2,606,000 +2,250,000 +New discoveries and extensions: +Rocky Mountain Region +358,000 +517,000 +130,000 +Dispositions to partnerships +(12,000) +(112,000) +(80,000) +Acquisitions: +Rocky Mountain Region +17,000 +307,000 +- +Production +(381,000) +(289,000 ) +(227,000 ) +End of year +3,316,000 +3,029,000 +2,073,000 +Proved developed reserves: +Beginning of year +2,889,000 +1,849,000 +1,801,000 +End of year +3,190,000 +2,889,000 +1,849,000 +(Continued) +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +Gas +(MCF) +2004 +2003 +2002 +Proved developed and undeveloped +reserves: +Beginning of year +180,998,000 +128,851,000 +118,608,000 +Revisions of previous estimates +(10,635,000) +4,394,000 +1,469,000 +Beginning of year as revised +170,363,000 +133,245,000 +120,077,000 +New discoveries and extensions: +Rocky Mountain Region +40,716,000 +27,719,000 +19,607,000 +Dispositions to partnerships +(4,240,000) +(4,410,000) +(4,792,000) +Acquisitions: +Michigan Basin +96,000 +265,000 +4,000 +Rocky Mountain Region +242,000 +32,169,000 +75,000 +Appalachian Basin +744,000 +722,000 +342,000 +Production +(10,372,000 ) +(8,712,000 ) +(6,462,000 ) +End of year +197,549,000 +180,998,000 +128,851,000 +Proved developed reserves: +Beginning of year +134,936,000 +94,847,000 +88,477,000 +End of year +146,152,000 +134,936,000 +94,847,000 +(18) Standardized +Measure of Discounted Future Net Cash Flows and Changes Therein Relating to +Proved Oil and Gas Reserves (Unaudited) +Summarized +in the following table is information for the Company with respect to the +standardized measure of discounted future net cash flows relating to proved oil +and gas reserves. Future cash inflows are computed by applying year-end prices +of oil and gas relating to the Company's proved reserves to the year-end +quantities of those reserves. Future production, development, site restoration +and abandonment costs are derived based on current costs assuming continuation +of existing economic conditions. Future income tax expenses are computed by +applying the statutory rate in effect at the end of each year to the future +pretax net cash flows, less the tax basis of the properties and gives effect to +permanent differences, tax credits and allowances related to the properties. +As of December +31, +2004 +2003 +2002 +Future estimated revenues +$1,298,394,000 +$1,088,415,000 +$548,949,000 +Future estimated production costs +(319,065,000) +(250,735,000) +(143,878,000) +Future estimated development costs +(95,498,000) +(65,275,000) +(50,971,000) +Future estimated income tax expense +(332,497,000 ) +(265,707,000 ) +(105,876,000 ) +Future net cash flows +551,334,000 +506,698,000 +248,224,000 +10% annual discount for estimated +timing of cash flows +(317,099,000 ) +(289,408,000 ) +( 149,755,000 ) +Standardized measure of discounted future +estimated net cash flows +$ 234,235,000 +$217,290,000 +$98,469,000 +(Continued) +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +The +following table summarizes the principal sources of change in the standardized +measure of discounted future estimated net cash flows: +Years Ended December +31, +2004 +2003 +2002 +Sales of oil and gas production, net of +production costs +$(52,974,000) +$(36,810,000) +$(16,449,000) +Net changes in prices and production costs +36,656,000 +162,422,000 +143,574,000 +Extensions, discoveries and improved recovery, +less related cost +135,816,000 +114,533,000 +39,347,000 +Dispositions to partnerships +(16,782,000) +(12,936,000) +(6,940,000) +Acquisitions +6,451,000 +139,078,000 +1,167,000 +Development costs incurred during the period +36,870,000 +30,630,000 +16,429,000 +Revisions of previous quantity estimates +(34,611,000) +21,388,000 +3,318,000 +Net changes in estimated income taxes +(66,790,000) +(159,831,000) +(55,516,000) +Accretion of discount +(27,691,000 ) +(139,653,000 ) +(72,900,000 ) +$16,945,000 +$118,821,000 +$ 52,030,000 +It is +necessary to emphasize that the data presented should not be viewed as +representing the expected cash flow from, or current value of, existing proved +reserves since the computations are based on a large number of estimates and +arbitrary assumptions. Reserve quantities cannot be measured with precision +and their estimation requires many judgmental determinations and frequent +revisions. The required projection of production and related expenditures over +time requires further estimates with respect to pipeline availability, rates of +demand and governmental control. Actual future prices and costs are likely to +be substantially different from the current prices and costs utilized in the +computation of reported amounts. Any analysis or evaluation of the reported +amounts should give specific recognition to the computational methods utilized +and the limitations inherent therein. +(19) Business Segments (Thousands) +PDC's +operating activities can be divided into four major segments: drilling and +development, natural gas marketing, oil and gas sales, and well operations. +The Company drills natural gas wells for Company-sponsored drilling +partnerships and retains an interest in each well. A wholly-owned subsidiary, +Riley Natural Gas, engages in the marketing of natural gas to commercial and +industrial end-users. The Company owns an interest in approximately 2,700 +wells from which it derives oil and gas working interests. The Company charges +Company-sponsored partnerships and other third parties competitive industry +rates for well operations and gas gathering. All material inter-company +accounts and transactions between segments have been eliminated. Segment +information for the years ended December 31, 2004, 2003 and 2002 is as follows: +2004 +2003 +2002 +REVENUES +Drilling +and Development +$119,211 +71,841 +57,149 +Natural +Gas Marketing +93,231 +73,141 +46,366 +Oil +and Gas Sales +67,948 +47,022 +22,857 +Well +Operations +8,384 +7,348 +6,116 +Unallocated +amounts (1) +1,946 +3,499 +2,854 +Total +$ 290,720 +202,851 +135,342 +(Continued) +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +SEGMENT +INCOME BEFORE INCOME TAXES +Drilling +and Development +$16,380 +10,564 +7,983 +Natural +Gas Marketing +1,324 +689 +174 +Oil +and Gas Sales +36,491 +23,812 +5,300 +Well +Operations +4,402 +3,059 +2,788 +Unallocated +amounts (2) +General +and Administrative expenses +(4,506) +(4,974) +(4,392) +Interest +expense +(874) +(1,329) +(1,340) +Other +(1) +1,386 +3,103 +2,569 +Total +$ 54,603 +34,924 +13,082 +SEGMENT +ASSETS +Drilling +and Development +$64,348 +62,546 +31,279 +Natural +Gas Marketing +28,689 +17,006 +16,641 +Oil +and Gas Sales +221,516 +204,849 +145,591 +Well +Operations +16,518 +11,602 +10,706 +Unallocated +amounts +Cash +112 +800 +1,736 +Other +10,210 +9,919 +6,299 +Total +$ 341,393 +306,722 +212,252 +EXPENDITURES +FOR SEGMENT +LONG-LIVED +ASSETS +Drilling +and Development +$ 4,583 +6,168 +1,800 +Natural +Gas Marketing +6 +- +4 +Oil +and Gas Sales +37,590 +63,588 +16,670 +Well +Operations +1,911 +2,944 +1,221 +Unallocated +amounts +1,302 +342 +82 +Total +$ 45,392 +73,042 +19,777 +(1) Includes +interest on investments and partnership management fees in 2004, 2003 and +2002 and gain on sale +of +assets in 2004, 2003 and 2002 which are not allocated in assessing segment +performance. +(2) Items +which are not allocated in assessing segment performance. +(20) +Subsequent Event +In +January 2005, the Company sold a portion of one of its undeveloped Garfield County, Colorado leases to another operator. The gain on such sale to be recorded +in the first quarter 2005 was approximately $5.2 million, net of a $1.0 million +liability recorded for a future commitment. The interest sold consisted of +half the Company's leasehold interest on a "checkerboard" pattern. The Company +will retain the other half of the lease. The terms of the agreement require +the purchaser to drill a number of wells over a period of time on the acquired +acreage. If the drilling requirements are not met part or all of the lease +will revert to the Company. +(Continued) +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +(21) Quarterly Financial Data (Unaudited ) +Summarized quarterly financial data for the years ended +December 31, 2004 and 2003, are as follows: +2004 +Quarter +Year +First +Second +Third +Fourth +Revenues +$71,048,500 +$73,923,800 +$73,157,400 +$72,590,100 +$290,719,800 +Cost +of operations +56,624,200 +59,315,500 +58,357,200 +56,439,900 +230,736,800 +Gross +profit +14,424,300 +14,608,300 +14,800,200 +16,150,200 +59,983,000 +General +and administrative expenses +994,200 +900,900 +926,300 +1,684,200 +4,505,600 +Interest +expense +243,500 +255,000 +252,600 +123,200 +874,300 +Income +before income taxes +13,186,600 +13,452,400 +13,621,300 +14,342,800 +54,603,100 +Income +taxes +4,747,200 +4,839,300 +4,929,700 +6,026,300 (1) +20,542,500 +Net income +$ 8,439,400 +$ 8,613,100 +$ 8,691,600 +$ 8,316,500 +$34,060,600 +Basic earnings per +share +$ .53 +$ .53 +$ .53 +$.50 +$2.10 +Diluted +earnings per share +$ .52 +$ .52 +$ .52 +$.49 +$2.05 +(1) Includes approximately $630,000 of adjustments to the +tax provision of the prior three quarters. +2003 +Quarter +Year +First +Second +Third +Fourth +Revenues +$53,994,400 +$42,192,500 +$47,207,900 +$59,456,200 +$202,851,000 +Cost +of operations +45,125,800 +33,836,200 +37,648,600 +45,013,400 +161,624,000 +Gross +profit +8,868,600 +8,356,300 +9,559,300 +14,442,800 +41,227,000 +General +and administrative expenses +1,177,700 +1,186,600 +1,377,300 +1,232,800 +4,974,400 +Interest +expense +236,200 +259,800 +415,000 +418,100 +1,329,100 +Income +before income taxes +7,454,700 +6,909,900 +7,767,000 +12,791,900 +34,923,500 +Income +taxes +2,460,000 +2,280,300 +2,563,100 +4,802,400 +12,105,800 +Net income before +cumulative +effect +of change of change in +accounting +principle +4,994,700 +4,629,600 +5,203,900 +7,989,500 +22,817,700 +Cumulative effect +of change in +Accounting +principle (net of taxes) +(198,600) +- +- +- +(198,600) +Net income +$ 4,796,100 +$ 4,629,600 +$ 5,203,900 +$ 7,989,500 +$ 22,619,100 +Basic +earnings per share +before +accounting change +$ .32 +$ .29 +$ .33 +$.52 +$1.46 +Cumulative effect +of change +in +accounting principle +(.01) +.00 +.00 +.00 +(.01) +Basic earnings per +share +$ .31 +$ .29 +$ .33 +$.52 +$1.45 +Diluted earnings +per share before +Accounting +principle +$ .31 +$ .29 +$ .31 +$.49 +$1.40 +Cumulative effect +of change in +Accounting +principle +(.01) +.00 +.00 +.00 +(.01) +Diluted +earnings per share +$ .30 +$ .29 +$ .31 +$.49 +$1.39 +Cost of operations +include cost of oil and gas well drilling operations, cost of gas marketing +activities, oil and gas production costs and depreciation, depletion and +amortization. +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS +AND RESERVES +Years Ended December 31, 2004, 2003 and 2002 +Column +A +Column B +Column C +Column +D +Column E +Additions, +Balance at +Charged to +Balance +Beginning +Costs and +At End +Description +of Period +Expenses +Deductions +of Period +Allowance for +doubtful accounts deducted +from accounts and +notes receivable in the +Balance sheet +2004 +$487,300 +$ - +$ 78,300 +$409,000 +2003 +$524,500 +$ - +$ 37,200 +$487,300 +2002 +$524,500 +$ - +$ +- +$524,500 \ No newline at end of file diff --git a/raw/filings/0000077877/2004/0000077877-05-000019/filing_metadata.csv b/raw/filings/0000077877/2004/0000077877-05-000019/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..665bdc642db1b3e514775fcd31a12d29a1261a88 --- /dev/null +++ b/raw/filings/0000077877/2004/0000077877-05-000019/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 +0000077877,PDCE,"PDC ENERGY, INC.",10-K,2005-03-31,2004-12-31,2005-03-31T21:49:51.000Z,0000077877-05-000019,pdc10k20041.htm,,1598750,0,0,https://www.sec.gov/Archives/edgar/data/77877/000007787705000019/pdc10k20041.htm,https://www.sec.gov/Archives/edgar/data/77877/000007787705000019/,2004,2004,1 diff --git a/raw/filings/0000077877/2004/0000077877-05-000019/item1.txt b/raw/filings/0000077877/2004/0000077877-05-000019/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..ee8fefdcc5eafd54731a8e9401d1f2648850e91e --- /dev/null +++ b/raw/filings/0000077877/2004/0000077877-05-000019/item1.txt @@ -0,0 +1,1419 @@ +Item 1. Business +Petroleum +Development Corporation is an independent energy company engaged primarily in +the development, production and marketing of natural gas and oil. Since it +began oil and gas operations in 1969, the Company has grown primarily through +drilling and development activities, the acquisition of producing natural gas +and oil wells and the expansion of its natural gas marketing activities. As of +December 31, 2004, the Company operates approximately 2,700 wells located in +the Appalachian basin, Michigan, and the Rocky Mountain Region, with gross +proved reserves of 523 billion cubic feet equivalent of natural gas ("Bcfe", +based on one barrel of oil equals 6 thousand cubic feet equivalent of natural +gas ("Mcfe")) of which the Company's share is 217 Bcfe. The Company's share of +production for the fourth quarter of 2004 averaged 34,500 Mcfe per day. +Business Segments +The Company's +operations are divided into four segments for management and reporting purposes. +(See Consolidated Financial Statements, Note 19. Business Segments) +Drilling and Development +The Company drills +wells not only for itself, but also for other investor partners. When the +company drills wells for others it earns a profit above the cost of the wells. +The Drilling and Development segment records the payments received from others +as revenue and the related costs as expenses. +Since 1984, the +Company has sponsored limited partnerships formed to engage in drilling +operations. The Company typically purchases a 20% ownership interest in these +drilling limited partnerships. In 2004, the Company, through four public +drilling partnerships, raised $100 million making it the sponsor of the largest +public oil and gas partnership program in the United States as it has been for +the last several years. With the partnerships as a drilling partner the Company +has been able to expand its drilling opportunities, reduce its drilling risk +through greater diversification, and to share the costs of the infrastructure +necessary to support such activities. +Natural Gas Marketing +The Company's +wholly-owned subsidiary, Riley Natural Gas (RNG), purchases, aggregates and +resells natural gas developed by the Company and other producers. This allows +the Company to diversify its operations beyond natural gas drilling and +production. RNG has established relationships with many of the natural gas +producers in the Appalachian Basin and has significant expertise in the natural +gas end‑user market. In addition, RNG has extensive experience in the use +of hedging strategies, which the Company utilizes to help manage the financial +impact on the Company and its Partnerships of changes in the price of natural +gas and oil. RNG also manages the marketing of oil and gas for the Company's +wells outside the Appalachian Basin, but does not market gas or oil for +non-affiliated producers in those areas. +Oil and Gas Sales +Revenue from the +sale of oil and natural gas from the Company's interest in oil and gas wells is +reported in this segment. The Company has interests in approximately 2,700 +wells ranging from a few percent to 100 percent. During 2004 approximately 14% +of the Company's production was generated by Appalachian Basin wells, 14% by +Michigan Basin wells and 72% by Rocky Mountain wells. As of the end of 2004, +the Company's total proved reserves were located as follows: Appalachian Basin 19%, +Michigan 12% and Rocky Mountain Region 69%. The majority of the Company's +undeveloped reserves are in the Rocky Mountain Region and the planned drilling +for 2005 will be focused in that area. +Well Operations +The Company operates +almost all of the approximately 2,700 wells in which it owns an interest. When +it owns less than 100 percent of the working interest in a well, it charges the +other owners a competitive operating fee for operating the well. These +revenues and the associated costs are reflected in the Well Operations segment. +Areas of Operations +The Company's +operations are divided into three regions, the Appalachian Basin, Michigan, and +the Rocky Mountain Region. The Company has conducted operations in Appalachian +Basin since its inception in 1969, in Michigan since 1997, and in the Rocky +Mountain Region since 1999. +In all three regions +the Company has historically targeted shallow (less than 10,000 feet), +developmental natural gas reserves for development. In some areas of the Rocky +Mountain Region, Michigan and the Appalachian Basin the wells also produce oil +in conjunction with natural gas. Recently the Company has begun to drill to +progressively deeper targets in the Rocky Mountain Region. In particular it +has drilled several wells with depths of more than 12,000 feet. The Company's +management believes these deeper wells offer the possibility of significantly +greater reserves and production than shallow wells, although they are also more +expensive to drill. In addition the probability of encountering problems when +drilling a deep well is generally greater than when drilling a shallow well. +With increasing costs for and declining availability of proved developed drilling +locations, the Company's management believes the additional risk associated +with exploratory drilling is justified by the potential to generate additional +proved locations at a significantly lower cost than would be required to +purchase proved undeveloped locations. +Business Strategy +The Company's primary +objective is to increase shareholder value by expanding its oil and natural gas +reserves, production and revenues through a strategy that includes the +following key elements: +Drill and Develop +Drilling new wells, +particularly shallow, developmental natural gas wells, has been the mainstay of +the Company's drilling program for a number of years. The Company drilled 158 +wells in 2004, compared to 111 wells in 2003. In addition the Company seeks to maximize +the value of its existing wells through a program of well recompletions and +infill drilling in areas where attractive opportunities exist. The Company's +management believes that it will be able to drill a substantial number of new +wells on its current undeveloped leased properties. As of December 31, 2004, +the Company had leases or other development rights to +1,700 undeveloped acres in the Michigan Basin, 10,000 undeveloped acres in the northern +Appalachian Basin and 152,830 undeveloped acres in the Rocky Mountain Region. The Company also has about 40 Wattenberg Field wells +that it plans to recomplete in 2005, and the new wells it has drilled since +1999 in the field will be available for recompletions beginning in 2006. +To support future +development activities the Company began an exploratory drilling program in +2004 that it plans to continue in 2005. The goal of the exploration program is +to develop several significant new areas for the Company to include in its +future development drilling programs. +Acquire +The Company's +acquisition efforts are focused on producing properties that fit well within +existing operations or in areas where the Company is establishing new operations +and that have most of their value in producing wells, behind pipe reserves or +high quality proved undeveloped locations. Acquisitions have historically +offered economies in management and administration, and the Company's +management believes that it can acquire and manage more producing wells without +incurring substantial increases in its administrative costs. +Diversify and Focus +With operations in +the Rocky Mountains, Michigan and the Appalachian Basin, the Company has proven +its ability to grow through operations in geographically diverse areas. While +these areas provide geographic diversification, within each area the Company +has concentrated positions that lend themselves to effective development and +operation. The Company plans to conduct the majority of its drilling +activities in the Rocky Mountain region during 2005, but will continue to seek +additional opportunities for expansion in areas where the Company's experience +and expertise can be applied successfully. +Manage Risk +The Company seeks +opportunities to reduce the risks inherent in the oil and gas industry in a +variety of ways. For a number of years an integral part of the Company's +strategy has been to concentrate on development drilling and geographical +diversification to reduce risk levels associated with natural gas and oil drilling, +production and markets. Development drilling is less risky than exploratory +drilling and is likely to generate cash returns more quickly. Development +drilling will remain the foundation of our drilling activities in 2005. However +Company's management believes the increasing cost of high quality development +locations has made exploratory drilling more attractive. Exploratory wells +have the potential of identifying new development opportunities at a +significantly lower cost than the current cost of proven locations. While successful +exploratory efforts could add to the Company's future drilling opportunities at +favorable costs, under the successful efforts method of accounting, exploratory +dry holes are expensed at the time it is recognized that they are unproductive. +This could result in greater short term expenses and a reduction in the +near-term profitability of the Company. +To help offset the +relatively high business risk inherent in the oil and gas industry the company +maintains a conservative financial structure. The Company's management +believes that successful natural gas marketing is essential to profitable +operations in a deregulated gas market. To further this goal, the Company's +utilizes its marketing subsidiary, Riley Natural Gas, to manage the marketing +of the Company's oil and natural gas and its commodity hedges. This allows the +Company to maintain better control over third party risk in sales and hedging +activities. The Company uses natural gas and oil hedges to reduce the effects +of volatility of energy prices. +Available Information Posted on the Company's Website +The Company's +Internet address is www.petd.com. Electronic copies of the Company's annual report +on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, +and amendments to those reports are available free of charge by visiting the +"Financial Information" section of www.petd.com . These reports are posted as soon as reasonably +practicable after they are electronically filed with the Securities and +Exchange Commission. Additionally, information including the Company's press +releases, current drilling program sales, Bylaws, Committee Charters, Code of +Business Conduct and Ethics, Shareholder Communication Policy, Board Nomination +Procedures and the Whistleblower and Qualified Legal Compliance Committee +Hotline is also available at the site. +Industry Overview +Natural gas is the +second largest energy source in the United States, after liquid petroleum. The +estimated 21.9 Tcf of natural gas consumed in 2004 represented approximately 23% +of the total energy used in the United States. Natural gas is consumed in the +United States as follows: 35% by industrial end-users as feedstock for products +such as plastic and fertilizer or as the energy source for producing products +such as glass; 24% and 15% by residential and commercial end-users, +respectively, for uses including heating, cooling and cooking; and 25% by +utilities for the generation of electricity; and 1% for other users. (Source U.S. Energy Information Administration) +The Company's +management believes that the market for natural gas will continue to grow in +the future. Natural gas is the cleanest and most environmentally safe of the +fossil fuels. Relative to other energy sources, natural gas usage and losses +during transportation from source to destination are slight, averaging only +about 3% of the natural gas energy. The delivery of natural gas is among the +safest means of distributing energy to customers, as the natural gas +transmission system is fixed and is located underground. +The deregulation of +the natural gas industry and a favorable regulatory environment have resulted +in end-users' ability to purchase natural gas on a competitive basis from a +greater variety of sources. Increasing international demand for petroleum +combined with supply constraints drove oil prices to record high levels in +2004. Continuing increases in world energy demand appear likely in 2005 and +beyond. This makes natural gas more competitive in domestic markets as a +replacement for oil and increases the value of domestic oil and natural gas +reserves. +The Company's +management believes that the foregoing factors, together with the increased +availability of natural gas as a form of energy for residential, commercial and +industrial uses, should increase the demand for natural gas as well as create +new markets for natural gas even at prices that are high by historical +standards. +Because local +supplies of natural gas are inadequate to meet demand in sections of the +country, areas including the West Coast and the Northeast import natural gas +from producing areas via interstate natural gas pipelines. The cost of +transporting natural gas from the major producing areas to markets creates a +price advantage for production located closer to the consuming regions. Natural +gas producers in the Appalachian Basin and Michigan benefit from proximity to +the northeastern United States. +In contrast, much of +the production in the Rocky Mountains is transported significant distances to +end use markets. As a result the price received for gas in the Rocky Mountains +is generally less than the price received in areas closer to the primary +consuming areas. The Rocky Mountain region is believed to hold substantial +undeveloped natural gas resources. Recent and planned additions to pipeline +capacity in the region have made the area more attractive for development. +Although gas from the region will generally sell for less than gas in the +Appalachian and Michigan Basins, development costs may be less. +Operations +Exploration and Development Activities +The Company's +development activities focus on the identification and drilling of new +productive wells, the acquisition of existing producing wells from other +producers, and maximizing the value of the Company's current properties through +infill drilling, recompletions, and other production enhancements. +Prospect Generation +The Company's staff +of professional geologists is responsible for identifying areas with potential +for economic production of natural gas and oil. These geologists have decades +of cumulative experience evaluating prospects and drilling natural gas and oil +wells. They utilize results from logs, seismic data and other tools to evaluate +existing wells and to predict the location of economically attractive new gas +reserves. To further this process, the Company has collected and continues to +collect logs, core data, production information and other raw data available +from state and private agencies, other companies and individuals actively +drilling in the regions being evaluated. From this information the geologists +develop models of the subsurface structures and formations that are used to +predict areas with prospects for economic development. +On the basis of +these models, the geologists instruct the Company's land department to obtain +available natural gas leaseholds, farmouts and other development rights in +these prospective areas. These rights are then obtained, if possible, by the +Company's land department or contract landmen under the direction of the +Company's land manager. In most cases, the Company pays a lease bonus and +annual rental payments, converting, upon initiation of production, to a royalty +on gross production revenue in return for obtaining the leases. In addition +overriding royalty payments may be made to third parties in conjunction with +the acquisition of drilling rights initially leased by others. As of December +31, 2004, the Company had leasehold rights to approximately 164,530 acres +available for development. See--"Properties--Oil and Natural Gas Leases." +Drilling Activities +When prospects have +been identified and leased, the Company develops these properties by drilling +wells. In 2004, the Company drilled a total of 157 development wells of which 153 +were successfully completed as producing wells. Typically, the Company will act +as driller‑operator for these prospects, frequently selling interests in +the wells to partnerships, primarily Company‑sponsored partnerships, and +other entities that are interested in exploration or development of the prospects. +The Company retains an interest in each well it drills. +The Company also +drilled one exploratory well in 2004 and plans additional exploratory wells in +2005. As of the date of this report the exploratory well had been completed +and testing was underway but the well had not been classified as successful or +dry. Testing of the well was suspended in January due to lease restrictions on +the Federal lease. We expect to resume testing in the second quarter. If the +well is determined to be a dry hole, its cost will be expensed in the period +when the determination is made as required by the successful efforts method of +accounting. The cost of the well as of January 31, 2005 is $4,362,000. +Currently the Company plans to retain most if not all of the working interest +in the exploratory wells, since the Company partnerships focus on developmental +activities and are allowed only limited participation in exploratory drilling. +See "Financing of Company Drilling and Development Activities" And +"Drilling and Development Activities Conducted for Company Sponsored +Partnerships." +Much of the work +associated with drilling, completing and connecting wells, including drilling, +fracturing, logging and pipeline construction is performed under the Company's +direction by subcontractors specializing in those operations, as is common in +the industry. When judged advantageous, material and services used by the +Company in the development process are acquired through competitive bidding by +approved vendors. The Company also directly negotiates rates and costs for +services and supplies when conditions indicate that such an approach is +warranted. As the prices paid to the Company by its drilling partnerships for +the Company's services are frequently fixed before the wells are drilled or are +determined based primarily on the well depth, the Company is subject to the +risk that prices of goods or services used in the development process could +increase, rendering its contracts with its investor partners less profitable or +unprofitable. In addition, problems encountered in the process can +substantially increase development costs, sometimes without recourse for the +Company to recover its costs from its partners. To minimize these risks, the +Company seeks to lock in its development costs in advance of drilling when +possible. +Drilling Activity +The following table +summarizes the Company's development drilling activity for the last five years. +There is no correlation between the number of productive wells completed during +any period and the aggregate reserves attributable to those wells. The +Company's exploratory wells drilled in the past five years (not included in the +table data) consist of one well (1.0 net) drilled in 2004 and one dry hole (1.0 +net) drilled in 2003. The exploratory well drilled in 2004 was completed late +in the year. Testing was commenced in December and suspended in January due to +lease restrictions on the federal lease that restrict access for heavy +equipment including service units during certain periods of the year to protect +wildlife and the environment. The lease restrictions would not prevent the +operation of producing wells during this period. Testing is scheduled to +resume late in the second quarter. The well cannot be classified as dry or +productive until testing is complete. If it is classified as dry the cost will +be expensed in the period when the determination is made as required by the successful +efforts method of accounting. +Development Wells +Drilled +Total +Productive +Dry +Drilled +Net +Drilled +Net +Drilled +Net +2000 +97 +27.39 +97 +27.39 +- +- +2001 +141 +40.00 +135 +37.94 +6 +2.06 +2002 +70 +13.71 +70 +13.71 +- +- +2003 +110 +28.51 +110 +28.51 +- +- +2004 +157 +43.00 +153 +42.40 +4 +.60 +Total +575 +152.61 +565 +149.95 +10 +2.66 +Financing of Company Drilling and Development Activities +The Company conducts +development drilling activities for its own account and acts as operator for +other investors. When conducting activities for its own account the Company +uses cash flow from operations and capital provided from its long term credit +facility to fund its share of operations. The Company currently has activated +$60 million of a $100 million credit facility with J.P. Morgan Chase Bank, NA and +BNP Paribas, however it has more than adequate reserves to allow the full line +to be activated if necessary. As of the end of 2004 the Company had $21 +million outstanding of the facility. +Drilling and Development Activities Conducted for Company +Sponsored Partnerships +In addition to wells +and interests in wells that it drills for itself, the company also acts as +operator for other oil and gas investors. Historically these other investors +have included individuals, corporations, partnerships formed by non-affiliated +parties and other investors. Currently the Company's drilling partners consist +primarily of public partnerships sponsored by the Company. A part of the Company's +drilling investment is used to purchase an interest in each partnership. +In 1984, the Company +began sponsoring private drilling limited partnerships, and, in 1989, the +Company began to offer partnership interests in public drilling programs registered +with the SEC. The Company's public partnerships had $100 million in +subscriptions in 2004, $78.3 million in subscriptions in 2003, and $56.9 +million in subscriptions in 2002. The Company generally invests, as its equity +contribution to each drilling partnership, an additional sum approximating 22% +of the aggregate subscriptions received for that particular drilling +partnership and receives a 20% working interest in each partnership. As a +result, the Company is subject to substantial cash commitments at the closing +of each drilling partnership, during 2004 this amounted to $22.0 million.. The +funds received from these programs are restricted to use in future drilling +operations. While funds were received by the Company pursuant to drilling +contracts in the years indicated, the Company recognizes revenues from drilling +operations on the percentage of completion method as the wells are drilled, +rather than when funds are received. Substantially all of the Company's +drilling and development funds are now received from partnerships in which the +Company serves as managing general partner. However, because wells produce for +a number of years, the Company continues to serve as operator for a number of +unaffiliated parties. +The process begins +when the Company enters into a development agreement with an investor partner, +pursuant to which the Company agrees to assign some or all of its rights in the +property to be drilled to the partnership or other entity. The partnership or +other entity thereby becomes owner of a working interest in the property. +The Company's drilling +contracts with its investor partners have historically taken many different +forms. Currently the agreements can be classified as on a +"footage-based" rate, whereby the Company receives drilling and +completion payments based on the depth of the well. Basic drilling and +completion operations are performed on a footage‑based rate, with leases +being contributed at the Company's cost. The Company may also purchase a +working interest in the subject properties. In its financial reporting the +Company reports only its share of reserves, production, revenue and costs +associated with wells in which other investors participate. The level of +the Company's third party drilling and development activity is dependent upon +the amount of subscriptions in its public drilling partnerships and investments +from other partnerships or other joint venture partners. Accepting investments +from third party investors and Company sponsored partnerships enables the +Company to diversify its holdings, thereby reducing the risk of the Company's +investments. Additionally, the Company benefits through such arrangements by +its receipt of fees for its management services and/or through an increased +share in the revenues produced by the developed properties. The Company's +management believes that investments in drilling activities, whether through +Company‑sponsored partnerships or other sources, are influenced in part +by the favorable treatment that such investments enjoy under the federal income +tax laws. No assurance can be given that the Company will continue to have +access to funds generated through these financing vehicles. +Purchases of Producing Properties +In addition to +drilling new wells, the Company continues to pursue opportunities to purchase +existing wells from other producers as well as greater ownership interests in +the wells it operates. Generally, outside interests purchased include a +majority interest in the wells and the right to operate the wells. Although the +Company made several offers to purchase properties during 2004, other potential +purchasers outbid the Company, therefore none of its offers were successful. +Several purchases made during 2003 as described below did contribute to the +Company's increased production in 2004. +During the second +quarter of 2003, the Company purchased 166 wells in the Denver Julesburg-Basin +in northeastern Colorado from Williams Production RMT Company for $28 million. +The Company estimates the acquisition included approximately 22.6 billion cubic +feet (Bcf) of proved developed producing (PDP) and 3.4 Bcf of proved developed +non-producing reserves (PDNP) at the time of acquisition, all of which is +natural gas. +During the fourth +quarter of 2003, the Company purchased from one of its unaffiliated joint +venture partners in the Denver-Julesburg Basin in Weld County, Colorado +approximately 3.1 billion cubic feet equivalent (Bcfe) of proved developed +producing reserves from interests in 20.6 net wells (230 gross) and 1.8 Bcfe of +proved developed non-producing reserves from interests in 17 net wells (183 +gross). The purchase price was $5.2 million. +During the fourth +quarter of 2003, the Company purchased from an unaffiliated party 97 gross +wells (73 net) in the Denver-Julesburg Basin located in northeast Colorado and northwestern Kansas for $6.0 million. This purchase included approximately 4.5 +billion cubic feet equivalent (Bcfe) of proved developed producing and proved +developed non-producing reserves along with 100,000 acres of oil and gas +leases. +The Company also +purchased a number of small interests in its partnerships from investor +partners wishing to sell their interests in 2004, 2003 and 2002. +Production +The following table +shows the Company's net production in barrels (Bbl) of crude oil and in +thousand cubic feet (Mcf) of natural gas and the costs and weighted average +selling prices thereof, for the last five years. +Year Ended December 31, +2004 +2003 +2002 +2001 +2000 +Production(1): +Oil(MBbl) +381 +289 +227 +195 +109 +Natural Gas (MMcf) +10,372 +8,712 +6,462 +6,085 +5,737 +Equivalent Mmcf(2) +12,658 +10,449 +7,824 +7,255 +6,391 +Average sales price: +Oil (per Bbl)(3) +$35.13 +$29.39 +$24.41 +$22.53 +$29.99 +Natural gas (per Mcf)(3) +$5.26 +$4.42 +$2.68 +$3.53 +$2.74 +Average production cost (lifting cost) +Per equivalent Mcf(4) +$1.18 +$0.98 +$0.82 +$0.83 +$0.66 +---------- +(1) Production +as shown in the table is net to the Company and is determined by multiplying +the gross production volume of properties in which the Company has an interest +by the percentage of the leasehold or other property interest owned by the +Company. +(2) A +ratio of energy content of natural gas and oil (six Mcf of natural gas equals +one barrel of oil) was used to obtain a conversion factor to convert oil +production into equivalent Mcf of natural gas. +(3) The +Company utilizes commodity-based derivative instruments as hedges to manage a +portion of its exposure to price volatility of its natural gas and oil sales. +The effect of hedges on the average sales price of natural gas per Mcf for the +years ended December 31, 2004, 2003, 2002, 2001, and 2000 was $(0.09), $(0.09), +$0.02, $(0.56),and $(0.91) respectively. The effect of hedges on the average +sales price of oil per barrel for the year ended December 31, 2004 was +$(2.71). There was no oil hedged in earlier years. +(4) Production +costs represent oil and gas operating expenses which include severance and ad +valorem taxes as reflected in the financial statements of the Company. See Oil +and Gas Production Costs in Management's Discussion and Analysis. +Natural Gas Sales +Natural gas produced +by the Company's well interests is sold under contracts with terms ranging from +one month to three years. Virtually all of +the Company's contract pricing provisions are tied to a market index, with +certain adjustments based on, among other factors, whether a well delivers to a +gathering or transmission line, quality of natural gas and prevailing supply +and demand conditions, so that the price of the natural gas fluctuates to +remain competitive with other available natural gas supplies. As a result, the +Company's revenues from the sale of natural gas will suffer if market prices +decline and benefit if they increase. The Company's management believes that +the pricing provisions of its natural gas contracts are customary in the +industry. +The Company sells +its natural gas to industrial end-users, utilities, other gas marketers, and +other wholesale gas purchasers. Two customers accounted for 13.8% and 11.1% +respectively of the Company's revenues from oil and gas sales (7.8% and 6.3% of +total revenues) in 2004. Three customers accounted for 16.6%, 17.4% and 14.3%, +respectively of the Company's revenues from oil and gas sales (9.8%, 10.3% and +8.5% of total revenues) in 2003. Two customers accounted for 21.1% and 11.0%, +respectively of the Company's revenues from oil and gas sales (10.8% and 5.6% +of total revenues) in 2002. No other single purchaser of the Company's natural +gas accounted for 10% or more of the Company's total revenues during 2004, +2003, and 2002. +At December 31, +2004, natural gas produced by the Company sold at prices per Mcf ranging from +$0.90 to $12.22, depending upon well location, the date of the sales contract +and other factors. The weighted net average price of natural gas sold by the +Company during 2004 was $5.26 per Mcf. +In general, the +Company, together with its marketing subsidiary, RNG, has been and expects to +continue to be able to produce and sell natural gas from its wells without +significant curtailment by providing natural gas to purchasers at competitive +prices. Open access transportation through the country's interstate pipeline +system makes a broad range of markets accessible to the Company. Whenever +feasible the Company obtains access to multiple pipelines and markets from each +of its gathering systems seeking the best available market for its natural gas +at any point in time. +Oil Sales +Some of the +Company's wells in the Appalachian Basin and Michigan, and most of the +Company's wells in Wattenberg field in Colorado, produce oil in addition to +natural gas. At the end of 2004 oil was about 9% of the Company's total +equivalent reserves. +The Company is +currently able to sell all the oil that it can produce under existing sales +contracts with petroleum refiners and marketers. The Company does not refine +any of its oil production. The Company's crude oil production is sold to +purchasers at or near the Company's wells under short-term purchase contracts +at prices and in accordance with arrangements that are customary in the oil +industry. One purchaser accounted for 7.6%, 11.0% and 11.9% of the Company's +revenues from oil and gas sales (4.3%, 6.5% and 5.6% of total revenues) in 2004, +2003, and 2002. At December 31, 2004, oil produced by the Company sold at +prices ranging from $37.25 to $49.00 per barrel, +depending upon the location and quality of oil. In 2004, the weighted net +average price per barrel of oil sold by the Company was $35.13. +Oil production is +subject to many of the same operating hazards and environmental concerns as +natural gas production, but is also subject to the risk of oil spills. Federal +regulations require certain owners or operators of facilities that store or +otherwise handle oil, such as the Company, to procure and implement Spill Prevention, +Control and Counter-measures ("SPCC") plans relating to the possible discharge +of oil into surface waters. The Oil Pollution Act of 1990 ("OPA") +subjects owners of facilities to strict joint and several liability for all +containment and cleanup costs and certain other damages arising from oil +spills. Noncompliance with OPA may result in varying civil and criminal penalties +and liabilities. Operations of the Company are also subject to the Federal +Clean Water Act and analogous state laws relating to the control of water +pollution, which laws provide varying civil and criminal penalties and +liabilities for release of petroleum or its derivatives into surface waters or +into the ground. +Natural Gas Marketing +The Company's +natural gas marketing activities involve the purchase of natural gas from other +producers and the sale of that natural gas along with natural gas produced by +the Company. The Company's management believes that in a deregulated market, +successful natural gas marketing is an essential component of profitable +operations. A variety of factors affect the market for natural gas, including +the availability of other domestic production, natural gas imports, the +availability and price of alternative fuels, the proximity and capacity of +natural gas pipelines, general fluctuations in the supply and demand for +natural gas and the effects of state and federal regulations on natural gas +production and sales. The natural gas industry also competes with other +industries in supplying the energy and fuel requirements of industrial, +commercial and individual customers. +RNG, a wholly owned +subsidiary, is a natural gas marketing company that specializes in the +purchase, aggregation and sale of natural gas production in the Company's +operating areas. RNG markets natural gas produced by the Company and also +purchases natural gas from other producers and resells to utilities, end users +or other marketers. The employees of RNG have extensive knowledge of natural +gas markets in the Company's areas of operations. Such knowledge assists the +Company in maximizing its prices as it markets natural gas from +Company-operated wells. The gas is marketed to natural gas utilities, pipelines +and industrial and commercial customers, either directly through the Company's +gathering system, or utilizing transportation services provided by regulated +interstate pipeline companies. +Hedging Activities +The Company utilizes +commodity-based derivative instruments as hedges to manage a portion of the +exposure to price volatility stemming from its oil and natural gas sales and +marketing activities. These instruments consist of NYMEX-traded natural gas +futures and option contracts for Appalachian, Michigan and eastern Colorado production, and CIG (Colorado Interstate Gas Index)-based contracts for other Colorado production and NYMEX traded oil futures and option contracts for Colorado oil production. +The contracts hedge committed and anticipated natural gas purchases and sales +and anticipated oil sales, generally forecasted to occur within the next two +year period. Company policy prohibits the use of natural gas or oil futures or +options for speculative purposes and permits utilization of hedges only if +there is an underlying physical position. +The Company through +RNG has extensive experience with the use of financial hedges to reduce the +risk and impact of natural gas price changes. These hedges are used by RNG to +coordinate fixed and variable priced purchases and sales, and by the Company to +"lock in" fixed prices from time to time for the Company's share of +production, and to establish "floors" and "ceilings" or +"collars" on the possible range of the price realized for the sale of +natural gas and oil. In order for contracts to serve as effective hedges, the +derivatives must be highly effective in offsetting changes in cash flows of +hedged items. There must be sufficient correlation to the underlying hedged +transaction. While hedging can help provide price protection if spot prices +drop, hedges can also limit upside potential. +For unhedged natural +gas sales not subject to fixed price contracts, the Company is subject to price +fluctuations for natural gas sold in the spot market and under market index +contracts. The Company continues to evaluate the potential for reducing these +risks by entering into hedge transactions. In addition, the Company may also +close out any portion of hedges that may exist from time to time which may +result in a gain or loss on that hedge transaction. Generally the Company +hedges only a portion of its anticipated production, so some or all of the +production is subject to the full fluctuation of market pricing. +Well Operations +The +Company currently operates approximately 1,476 wells in the Appalachian Basin, +204 wells in the Michigan Basin and 991 wells in the Rocky Mountain Region. The +Company's ownership interest in these wells ranges from 0% to 100%, and, on +average, the Company has an approximate 51% ownership interest in the wells it +operates. +The Company is paid +a monthly operating fee for each well it operates for outside owners including +the limited partnerships sponsored by the Company. The fee is competitive with +rates charged by other operators in the area. The fee covers monthly operating +and accounting costs, insurance and other recurring costs. The Company may also +receive additional compensation for special non-recurring activities, such as +reworks and recompletions. +Transportation +Natural gas wells +are connected by pipelines to natural gas markets. Over the years, the Company +has developed gathering systems in some of its areas of operations. The Company +also continues to construct new trunk lines as necessary to provide for the +marketing of natural gas being developed from new areas and to enhance or +maintain its existing systems. +The Company is paid +a transportation fee for natural gas that is moved by other shippers through +these pipeline systems. In many cases the Company has been able to receive +higher natural gas prices as a result of its ability to move natural gas to +more attractive markets through this pipeline system, to the benefit of both +the Company and its investor partners. +Governmental Regulation +The Company's +business and the natural gas industry in general are heavily regulated. The +availability of a ready market for natural gas production depends on several +factors beyond the Company's control. These factors include regulation of +natural gas production, federal and state regulations governing environmental +quality and pollution control, the amount of natural gas available for sale, +the availability of adequate pipeline and other transportation and processing +facilities and the marketing of competitive fuels. State and federal +regulations generally are intended to protect consumers from unfair treatment, +control and reduce the risk to the public and workers from the drilling +completion, production and transportation of oil and natural gas, prevent waste +of natural gas, protect rights to produce natural gas between owners in a +common reservoir and control contamination of the environment. Pipelines are +subject to the jurisdiction of various federal, state and local agencies. In +the western part of the United States the federal and state governments own a +large percentage of the land and the rights to develop oil and natural gas. +Recently the Company has increased its positions in these types of leases. +Generally government leases are subject to additional regulations and controls +not commonly seen on private leases. The Company takes the steps necessary to +comply with applicable regulations both on its own behalf and as part of the +services it provides to its investor partnerships. The Company's management +believes that it is in substantial compliance with such statutes, rules, +regulations and governmental orders, although there can be no assurance that +this is or will remain the case. The following discussion of the regulation of +the United States natural gas industry is not intended to constitute a complete +discussion of the various statutes, rules, regulations and environmental orders +to which the Company's operations may be subject. +Regulation of Oil and Natural Gas Exploration and +Production +The Company's oil +and natural gas operations are subject to various types of regulation at the +federal, state and local levels. Prior to commencing drilling activities for a +well, the Company must procure permits and/or approvals for the various stages +of the drilling process from the applicable state and local agencies in the +state in which the area to be drilled is located. Such permits and approvals +include those for the drilling of wells, and such regulation includes +maintaining bonding requirements in order to drill or operate wells and +regulating the location of wells, the method of drilling and casing wells, the +surface use and restoration of properties on which wells are drilled, the +plugging and abandoning of wells and the disposal of fluids used in connection with +operations. The Company's operations are also subject to various conservation +laws and regulations. These include the regulation of the size of drilling and +spacing units or proration units and the density of wells which may be drilled +and the unitization or pooling of properties. In this regard, some states allow +the forced pooling or integration of tracts to facilitate exploration while +other states rely primarily or exclusively on voluntary pooling of lands and +leases. In areas where pooling is voluntary, it may be more difficult to form +units, and therefore, more difficult to develop a project if the operator owns +less than 100% of the leasehold. In addition, state conservation laws may +establish maximum rates of production from oil and natural gas wells, generally +prohibiting the venting or flaring of natural gas and imposing certain +requirements regarding the ratability of production. Where wells are to be +drilled on state or federal leases additional regulations and conditions may +apply. The effect of these regulations may limit the amount of oil and natural +gas the Company can produce from its wells and may limit the number of wells or +the locations at which the Company can drill. The regulatory burden on the oil +and natural gas industry increases the Company's costs of doing business and, +consequently, affects its profitability. In as much as such laws and +regulations are frequently expanded, amended and reinterpreted, the Company is +unable to predict the future cost or impact of complying with such regulations. +Regulation of Sales and Transportation of Natural Gas +Historically, the +transportation and sale for resale of natural gas in interstate commerce were +regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act +of 1978 (the "NGPA") and the regulations promulgated thereunder by +the Federal Energy Regulatory Commission (FERC). Maximum selling prices of +certain categories of natural gas sold in "first sales," whether sold +in interstate or intrastate commerce, were regulated pursuant to the NGPA. The +Natural Gas Wellhead Decontrol Act (the "Decontrol Act") removed, as +of January 1, 1993, all remaining federal price controls from natural gas sold +in "first sales" on or after that date. FERC's jurisdiction over +natural gas transportation was unaffected by the Decontrol Act. While sales by +producers of natural gas and all sales of crude oil, condensate and natural gas +liquids can currently be made at market prices, Congress could reenact price +controls in the future. +The Company's sales +of natural gas are affected by the availability, terms and cost of +transportation. The price and terms for access to pipeline transportation are +subject to extensive regulation. In the past, FERC has undertaken various +initiatives to increase competition within the natural gas industry. As a +result of initiatives like FERC Order No.636, issued in April 1992, the +interstate natural gas transportation and marketing system was substantially +restructured to remove various barriers and practices that historically limited +non‑pipeline natural gas sellers, including producers, from effectively +competing with interstate pipelines for sales to local distribution companies +and large industrial and commercial customers. The most significant provisions +of Order No.636 require that interstate pipelines provide transportation +separate or "unbundled" from their sales service, and require that +pipelines provide firm and interruptible transportation service on an open +access basis that is equal for all natural gas suppliers. In many instances, +the result of Order No.636 and related initiatives have been to substantially +reduce or eliminate the interstate pipelines' traditional role as wholesalers +of natural gas in favor of providing only storage and transportation services. +Another effect of regulatory restructuring is the greater transportation access +available on interstate pipelines. In some cases, producers and marketers have +benefited from this availability. However, competition among suppliers has +greatly increased and traditional long‑term producer-pipeline contracts +are rare. Furthermore, gathering facilities of interstate pipelines are no +longer regulated by FERC, thus allowing gatherers to charge higher gathering +rates. +Additional proposals +and proceedings that might affect the natural gas industry occur frequently in +the Congress, FERC, state commissions, state legislatures, 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 FERC and Congress will continue. The Company cannot determine to +what extent future operations and earnings of the Company will be affected by +new legislation, new regulations, or changes in existing regulation, at +federal, state or local levels. +Environmental Regulations +The Company's +operations are subject to numerous laws and regulations governing the discharge +of materials into the environment or otherwise relating to environmental +protection. Public interest in the protection of the environment has increased +dramatically in recent years. The trend of more expansive and stricter +environmental legislation and regulations could continue. To the extent laws +are enacted or other governmental action is taken that restricts drilling or +imposes environmental protection requirements that result in increased costs +and reduced access to the natural gas industry in general, the business and +prospects of the Company could be adversely affected. +The Company +generates wastes that may be subject to the Federal Resource Conservation and +Recovery Act ("RCRA") and comparable state statutes. The U.S. +Environmental Protection Agency ("EPA") and various state agencies +have limited the approved methods of disposal for certain hazardous and +nonhazardous wastes. Furthermore, certain wastes generated by the Company's +operations that are currently exempt from treatment as "hazardous +wastes" may in the future be designated as "hazardous wastes," +and therefore be subject to more rigorous and costly operating and disposal +requirements. +The Company +currently owns or leases numerous properties that for many years have been used +for the exploration and production of oil and natural gas. Although the Company's +management believes that it has utilized good operating and waste disposal +practices, prior owners and operators of these properties may not have utilized +similar practices, and hydrocarbons or other wastes may have been disposed of +or released on or under the properties owned or leased by the Company or on or +under locations where such wastes have been taken for disposal. These +properties and the wastes disposed thereon may be subject to the Comprehensive +Environmental Response, Compensation and Liability Act ("CERCLA"), +RCRA and analogous state laws as well as state laws governing the management of +oil and natural gas wastes. Under such laws, the Company 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) or to perform remedial plugging operations to +prevent future contamination. +CERCLA and similar +state laws impose liability, without regard to fault or the legality of the +original conduct, on certain classes of persons that are considered to have +contributed to the release of a "hazardous substance" into the +environment. These persons include the owner or operator of the disposal site +or sites where the release occurred and companies that disposed of or arranged +for the disposal of the hazardous substances found at the site. Persons who are +or were responsible for release of 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, and 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. +The Company's +operations may be subject to the Clean Air Act ("CAA") and comparable +state and local requirements. Amendments to the CAA were adopted in 1990 and +contain provisions that may result in the gradual imposition of certain +pollution control requirements with respect to air emissions from the +operations of the Company. The EPA and states have been developing regulations +to implement these requirements. The Company may be required to incur certain +capital expenditures in the next several years for air pollution control +equipment in connection with maintaining or obtaining operating permits and +approvals addressing other air emission-related issues. +The Company's +expenses relating to preserving the environment during 2004 were not +significant in relation to operating costs and the Company expects no material +change in 2005. Environmental regulations have had no materially adverse effect +on the Company's operations to date, but no assurance can be given that +environmental regulations will not, in the future, result in a curtailment of +production or otherwise have a materially adverse effect on the Company's +business, financial condition or results of operations. +Operating Hazards and Insurance +The Company's +exploration and production operations include a variety of operating risks, +including the risk of fire, explosions, blowouts, cratering, pipe failure, +casing collapse, abnormally pressured formations, and environmental hazards +such as gas leaks, ruptures and discharges of toxic gas, the occurrence of any +of which could result in substantial losses to the Company due to injury and +loss of life, severe damage to and destruction of property, natural resources +and equipment, pollution and other environmental damage, clean‑up +responsibilities, regulatory investigation and penalties and suspension of +operations. The Company's pipeline, gathering and distribution operations are +subject to the many hazards inherent in the natural gas industry. These hazards +include damage to wells, pipelines and other related equipment, and surrounding +properties caused by hurricanes, floods, fires and other acts of God, +inadvertent damage from construction equipment, leakage of natural gas and +other hydrocarbons, fires and explosions and other hazards that could also +result in personal injury and loss of life, pollution and suspension of +operations. +Any significant +problems related to its facilities could adversely affect the Company's ability +to conduct its operations. In accordance with customary industry practice, the +Company maintains insurance against some, but not all, potential risks; +however, there can be no assurance that such insurance will be adequate to +cover any losses or exposure for liability. The occurrence of a significant +event not fully insured against could materially adversely affect the Company's +operations and financial condition. The Company cannot predict whether +insurance will continue to be available at premium levels that justify its +purchase or whether insurance will be available at all. +Competition +The Company's management believes that its exploration, +drilling and production capabilities and the experience of its management and +professional staff generally enable it to compete effectively. The Company +encounters competition from numerous other oil and natural gas companies, +drilling and income programs and partnerships in all areas of its operations, +including drilling and marketing natural gas and obtaining desirable natural +gas leases. Many of these competitors possess larger staffs and greater +financial resources than the Company, which may enable them to identify and +acquire desirable producing properties and drilling prospects more +economically. The Company's ability to explore for oil and natural gas +prospects and to acquire additional properties in the future depends upon its +ability to conduct its operations, to evaluate and select suitable properties +and to consummate transactions in this highly competitive environment. The +Company competes with a number of other companies that offer interests in +drilling partnerships with a wide range of investment objectives and program +structures. Competition for investment capital for both public and private +drilling programs is intense. The Company also faces intense competition in the +marketing of natural gas from competitors including other producers as well as +marketing companies. Also, international developments and the possible improved +economics of domestic natural gas exploration may influence other companies to +increase their domestic oil and natural gas exploration. Furthermore, +competition among companies for favorable prospects can be expected to +continue, and it is anticipated that the cost of acquiring properties may +increase in the future. During 2004 the industry experienced increased demand +for drilling services and supplies. This is resulting in increasing costs, and +in some cases the demand for supplies and services exceeds the available +supplies. This can result in higher well costs and delays in the execution of +planned drilling operations. Factors affecting competition in the oil and natural +gas industry include price, location, availability, quality and volumes +produced. The Company's management believes that it can compete effectively in +the oil and natural gas industry on each of the foregoing factors. +Nevertheless, the Company's business, financial condition or results of +operations could be materially adversely affected by competition. +Employees +As of December 31, +2004, the Company had 120 employees, including 17 in finance and data +processing, 8 in administration, 12 in exploration and development, 78 in +production and 5 in natural gas marketing. The Company's engineers, supervisors +and well tenders are responsible for the day-to-day operation of wells and +pipeline systems. In addition, the Company retains subcontractors to perform +drilling, fracturing, logging, and pipeline construction functions at drilling +sites. The Company's employees act as supervisors of the subcontractors. +The Company's +employees are not covered by a collective bargaining agreement. The Company +considers relations with its employees to be excellent. +Risks Related to the Oil and Natural Gas +Industry and the Company +Oil and natural +gas prices fluctuate unpredictably and a decline in oil and natural gas prices +can significantly affect the Company's financial results and impede its growth. +The +Company's revenue, profitability and cash flow depend in large part upon the +prices and demand for oil and natural gas. The markets for these commodities +are very volatile and even relatively modest drops in prices can significantly +affect the Company's financial results and impede its growth. Changes in oil +and natural gas prices have a significant impact on the value of the Company's +reserves and on its cash flow. Prices for oil and natural gas may fluctuate +widely in response to relatively minor changes in the supply of and demand for +oil and natural gas, market uncertainty and a variety of additional factors +that are beyond the Company's control, including national and international +economic and political factors and federal and state legislation. +Lower oil and natural gas prices may not +only decrease the Company's revenues , but also may reduce the amount of oil +and natural gas that the Company can produce economically. This may result in +the Company having to make substantial downward adjustments to its estimated +proved reserves. If this occurs or if the Company's estimates of development +costs increase, production data factors change or the Company's exploration +results deteriorate, successful efforts accounting rules may require us to +write down, as a non-cash charge to earnings, the carrying value of our oil and +natural gas properties for impairments. The +Company assesses impairment of capitalized costs of proved oil and gas +properties by comparing net capitalized costs to estimated undiscounted future +net cash flows on a field-by-field basis using expected prices. Prices utilized +in each year's calculation for measurement purposes and expected costs are held +constant throughout the estimated life of the properties. If net capitalized +costs exceed undiscounted future net cash flows, the measurement of impairment +is based on estimated fair value which would consider future discounted cash +flows. The Company may incur impairment charges in the future, which +could have a material adverse effect on its results of operations. +The Company's +estimated oil and gas reserves are based on many assumptions that may turn out +to be inaccurate. Any material inaccuracies in these reserve estimates or +underlying assumptions will materially affect the quantities and present value +of the Company's reserves. +No +one can measure underground accumulations of oil and natural gas in an exact +way. Oil and natural gas reserve engineering requires subjective estimates of +underground accumulations of oil and natural gas and assumptions concerning +future oil and natural gas prices, production levels, and operating and +development costs. As a result, estimated quantities of proved reserves and +projections of future production rates and the timing of development +expenditures may be inaccurate. The Company's estimates of oil and gas reserves +are prepared by Wright & Company (Wright), independent petroleum engineers, +using pricing, production, cost, tax and other information provided by the +Company. Over time, Wright may make material changes to reserve estimates +taking into account the results of actual drilling, testing, and production. Also, +Wright makes certain assumptions regarding future oil and natural gas prices, +production levels, and operating and development costs that may prove +incorrect. Any significant variance from these assumptions to actual figures +could greatly affect the estimates of reserves, the economically recoverable +quantities of oil and natural gas attributable to any particular group of +properties, the classifications of reserves based on risk of recovery, and +estimates of the future net cash flows. Some of our reserve estimates are made +without the benefit of a lengthy production history, which renders these +reserve estimates less reliable than estimates based on a lengthy production +history. Numerous changes over time to the assumptions on which the reserve +estimates are based, as described above, often result in the actual quantities +of oil and gas recovered being different from earlier reserve estimates. +The +present value of future net cash flows from the proved reserves is not +necessarily the same as the current market value of the estimated oil and +natural gas reserves (the Securities and Exchange Commission requires the use +of year end prices). The estimated discounted future net cash flows from proved +reserves are based on prices and costs in effect on the day of estimate. +However, actual future net cash flows from our oil and natural gas properties +also will be affected by factors such as actual prices we receive for oil and +natural gas, the amount and timing of actual production, supply of and demand +for oil and natural gas, and changes in governmental regulations or taxation. +The +timing of both our production and our incurrence of expenses in connection with +the development and production of oil and natural gas properties will affect +the timing of actual future net cash flows from proved reserves, and thus their +actual present value. In addition, the 10% discount factor we use when +calculating discounted future net cash flows may not be the most appropriate +discount factor based on interest rates in effect from time to time and risks +associated with us or the oil and natural gas industry in general. +Unless oil and +natural gas reserves are replaced as they are produced, the Company's reserves +and production will decline, which would adversely affect the Company's +business, financial condition and results of operations. +Producing +oil and natural gas reservoirs generally are characterized by declining +production rates that vary depending upon reservoir characteristics and other +factors. The rate of decline will change if production from existing wells +declines in a different manner than we have estimated and can change due to +other circumstances.Thus, the Company's future oil and natural gas reserves and +production and, therefore, its cash flow and income are highly dependent on +efficiently developing and exploiting the Company's current reserves and +economically finding or acquiring additional recoverable reserves. The Company +may not be able to develop, discover or acquire additional reserves to replace +our current and future production at acceptable costs. +Prospects +drilled by the Company may not yield natural gas or oil in commercially viable +quantities. +A +prospect is a property on which the Company's geologists have identified what +they believe, based on available information, to be indications of natural gas +or oil bearing rocks. However, the use of available data and other technologies +and the study of producing fields in the same area will not enable the +geologists to know conclusively prior to drilling and testing whether natural +gas or oil will be present or, if present, whether natural gas or oil will be +present in sufficient quantities to repay drilling or completion costs and generate +a profit. If a well is determined to be dry or uneconomic, which can occur even +though it contains some oil or gas reserves, it is classified as a dry hole and +must be plugged and abandoned in accordance with applicable regulations. This +generally results in the loss of the entire cost of drilling and completion to +that point, the cost of plugging, and lease costs associated with the +prospect. Even wells that are completed and placed into production may not +produce sufficient oil and gas to be profitable. If the Company drills a dry +hole or non-profitable well on current and future prospects, the profitability +of its operations will decline and the value of the Company will be reduced. In +sum, the cost of drilling, completing and operating any well is often uncertain +and new wells may not be productive. +The Company may +not be able to identify enough attractive prospects on a timely basis to meet +its own development needs and those of the partnerships it forms for investors, +which could limit the Company's development opportunities and/or force it to +reduce the partnership activity. +Our +geologists have identified a number of potential drilling locations on our +existing acreage. These drilling locations must be replaced as they are drilled +for the Company to continue to grow its reserves and production, and for it to +be able to continue its partnership drilling activities. The Company's ability +to identify and acquire new drilling locations depends on a number of +uncertainties, including the availability of capital, regulatory approvals, oil +and natural gas prices, competition, costs, drilling results, and the ability +of the Company's geologists to successfully identify potentially successful new +areas to develop. Because of these uncertainties, The Company's profitability +and growth opportunities may be limited by the timely availability of new +drilling locations, and it could be forced to terminate or curtail its +partnership activities because of a lack of suitable prospects for the +partnerships. +Drilling for +and producing oil and natural gas are high risk activities with many +uncertainties that could adversely affect the Company's business, financial +condition and results of operations. +Drilling +activities are subject to many risks, including the risk that wells will not +discover commercially productive reservoirs. Drilling for oil and natural gas +can be unprofitable, not only from dry holes, but from productive wells that do +not produce sufficient revenues to return a profit. In addition, drilling and +producing operations may be curtailed, delayed or canceled as a result of other +factors, including unusual or unexpected geological formations, pressures, +fires, blowouts, loss of drilling fluid circulation, title problems, facility +or equipment malfunctions, unexpected operational events, shortages or delivery +delays of equipment and services, compliance with environmental and other +governmental requirements, and adverse weather conditions. +Any of these risks can cause substantial +losses, including personal injury or loss of life, damage to or destruction of +property, natural resources and equipment, pollution, environmental +contamination or loss of wells and regulatory penalties. The Company maintains +insurance against various losses and liabilities arising from operations; +however, insurance against all operational risks is not available. +Additionally, the Company management may elect not to obtain insurance if the +cost of available insurance is excessive relative to the perceived risks +presented. Thus, losses could occur for uninsurable or uninsured risks or in +amounts in excess of existing insurance coverage. The occurrence of an event +that is not fully covered by insurance could have a material adverse impact on +the Company's business activities, financial condition and results of +operations. +Increased +drilling activity, particularly in the Rocky Mountain Region, may create a +shortage of drilling rigs, service providers, or materials forcing the Company +to curtail its drilling operations for itself and its partnerships thereby +reducing revenue and profits from new oil and gas wells and from the Company's +drilling and completion activities. +With high levels of oil and gas prices +many oil and gas companies have increased their levels of drilling and +completing new wells and reworking old wells. At the same time there is a +limited supply of drilling rigs, completion equipment and qualified personnel +to provide the services necessary to drill, complete and rework new wells. In +particular, the Rocky Mountain Region has seen a great increase in activity +over the past few years. If the demand for these goods and services continues +to increase shortages may develop, which could result in increased prices for +these goods and services or the Company's inability to complete all of the drilling +it has planned. This could result in decreased profitability for the Company +and the temporary or permanent loss of part or all of its partnership drilling +activity. +The +Company's drilling and development segment receives virtually all of its +revenue from the publicly registered partnerships it sponsors, and a reduction +or loss of that business could reduce or eliminate the revenue and profits +associated with those activities. +The Company's drilling activities are +dependent upon the capital raised by the Company as sponsor of SEC registered +limited partnerships. The Company sells oil and natural gas partnerships +through a network of non-affiliated NASD broker dealers. The largest of those +broker dealers sold about 11% of the partnership units in 2004. Investors in +the partnerships are interested in the tax deductions generated by the +intangible drilling costs and the cash flow generated by the partnerships. If +the tax laws were changed to reduce or eliminate the tax advantages, if the +cash flow from the partnerships were to decline due to weak wells or lower +energy prices, or if the brokers decide to stop offering our partnerships for +some other reason, the sales of the partnership units would decline, reducing +or eliminating the revenue and profits associated with the drilling and completion +business segment. +Under the +Successful Efforts accounting method used by the Company unsuccessful +exploratory wells must be expensed in the period when they are determined to be +non-productive which results in a reduction of net income and could have a +negative impact on the Company's stock price. +The +Company plans to increase its exploratory drilling in 2005 in order to identify +additional opportunities for future development. However the cost of +unsuccessful exploratory wells must be charged to expense in the period when +they are determined to be unsuccessful under the successful efforts method of +accounting used by the Company. In addition lease costs for acreage condemned +by the unsuccessful well must also be expensed. In contrast unsuccessful development +wells are capitalized as a part of the investment in the field where they are +located. Because exploratory wells generally are more likely to be +unsuccessful than development wells the Company anticipates that some or all of +its exploratory wells may not be productive. The costs of such unsuccessful +wells could result in a significant reduction in the Company's profitability in +periods when they are required to be expensed, which could have an adverse +effect on the Company's stock price. In addition unsuccessful wells will not +add to the Company's reserves or production. +Rising +finding and development costs may impair our profitability. +In order to continue to grow and maintain +its profitability, the Company must annually add new reserves exceeding its +yearly production at a finding and development cost that yields an acceptable +operating margin and depreciation, depletion and amortization rate. Without +cost effective exploration, development or acquisition activities, production, +reserves and profitability will decline over time. Given the relative maturity +of most gas basins in North America the cost of finding new reserves through +exploration and development operations has been increasing. The acquisition +market for natural gas properties has become extremely competitive among +producers for additional production and expanded drilling opportunities in North America. Acquisition values climbed toward historic highs during 2004 on a per unit +basis, particularly in the Rocky Mountain region, and the Company believes +these values may continue to increase in 2005. This increase in finding and +development costs is resulting in higher depreciation, depletion and +amortization rates. If the upward trend in finding and development costs +continues, the Company will be exposed to an increased likelihood of a +writedown in carrying value of its natural gas and oil properties in response +to falling prices, which would impair its profitability. +The Company's +development and exploration operations require substantial capital and it may +be unable to obtain needed capital or financing on satisfactory terms, which +could lead to a loss of properties and a decline in our natural gas and oil +reserves and production. +The +oil and natural gas industry is capital intensive. The Company makes and +expects to continue to make substantial capital expenditures in its business +and operations for the exploration for and development, production and +acquisition of oil and natural gas reserves. To date, the Company has financed capital +expenditures primarily with cash generated by operations and proceeds from bank +borrowings. Currently the Company intends to finance its capital expenditures +with cash flows from operations and its existing financing arrangements. Cash +flows from operations and access to capital are subject to a number of +variables, including the Company's proved reserves, the level of oil and +natural gas the Company is able to produce from existing wells, the prices at +which oil and natural gas are sold, and the Company's ability to acquire, +locate and produce new reserves. +If +the Company's revenues or the borrowing base under its revolving credit +facility decrease as a result of lower oil and natural gas prices, operating +difficulties, declines in reserves or for any other reason, it may have limited +ability to obtain the capital necessary to sustain its operations at planned +levels. +If +additional capital is needed, the Company may not be able to obtain debt or +equity financing on favorable terms, or at all. If cash generated by operations +or available under our revolving credit facility is not sufficient to meet our +capital requirements, the failure to obtain additional financing could result +in a curtailment of our operations relating to exploration and development of +our prospects, which in turn could lead to a possible loss of properties and a +decline in our natural gas and oil reserves. +The Company's +credit facility and other debt financing have substantial restrictions and +financial covenants and the Company may have difficulty obtaining additional +credit, which could adversely affect our operations. +The +Company will depend on its revolving credit facility for future capital needs. +The revolving credit facility restricts our ability to obtain additional +financing, make investments, lease equipment, sell assets and engage in +business combinations. We also are required to comply with certain financial +covenants and ratios. Our ability to comply with these restrictions and +covenants in the future is uncertain and will be affected by the levels of cash +flows from our operations and events or circumstances beyond our control. Our +failure to comply with any of the restrictions and covenants under the +revolving credit facility or other debt financing could result in a default +under those facilities, which could cause all of our existing indebtedness to +be immediately due and payable. +The +revolving credit facility limits the amounts we can borrow to a borrowing base +amount, determined by the lenders in their sole discretion, based upon +projected revenues from the oil and natural gas properties securing our loan. +The lenders can unilaterally adjust the borrowing base and the borrowings +permitted to be outstanding under the revolving credit facility. Outstanding +borrowings in excess of the borrowing base must be repaid immediately, or we +must pledge other oil and natural gas properties as additional collateral. We +do not currently have any substantial unpledged properties, and we may not have +the financial resources in the future to make any mandatory principal +prepayments required under the revolving credit facility. +A substantial +part of the Company's producing properties are located in the Rocky Mountains, +making it vulnerable to risks associated with operating in one major geographic +area. +The +Company's operations are becoming increasingly focused on the Rocky Mountain +region, which means its producing properties and new drilling opportunities are +geographically concentrated in that area. As a result, the Company, the success +of its operations, and its profitability may be disproportionately exposed to +the impact of delays or interruptions of production from existing or planned +new wells by significant governmental regulation, transportation capacity +constraints, curtailment of production, interruption of transportation, or +fluctuations in prices of oil and natural gas produced from the wells in the +region. +Seasonal +weather conditions and lease stipulations adversely affect the Company's +ability to conduct drilling activities in some of the areas where we operate. +Oil +and natural gas operations in the Rocky Mountains are adversely affected by +seasonal weather conditions and lease stipulations designed to protect various +wildlife. In certain areas, including parts of the Sand Wash and Piceance Basins, drilling and other oil and natural gas activities are restricted or +prohibited by lease stipulations, or prevented by weather conditions, for up to +6 months out of the year. This limits operations in those areas and can intensify +competition during those months for drilling rigs, oil field equipment, +services, supplies and qualified personnel, which may lead to periodic +shortages. These constraints and the resulting shortages or high costs could +delay operations and materially increase operating and capital costs and +therefore adversely affect profitability. +Properties that +the Company buys may not produce as projected and the Company may be unable to +determine reserve potential, identify liabilities associated with the properties +or obtain protection from sellers against them. +One +of the Company's growth strategies is to acquire producing oil and natural gas +reserves in its areas of operations and in new areas to help establish a base +of operations for further development. However, reviews of potential +acquisitions are inherently incomplete because it generally is not feasible to +review in depth every individual property. Ordinarily, the Company focuses +review efforts on the higher value properties and will sample the remainder. +However, even a detailed review of records and properties may not necessarily +reveal existing or potential problems, nor will it permit a buyer to become +sufficiently familiar with the properties to assess fully their deficiencies +and potential. Inspections may not always be performed on every well, and +environmental problems, such as ground water contamination, are not necessarily +observable or detectable even when an inspection is undertaken. Even when +problems are identified, the Company may choose to assume certain environmental +and other risks and liabilities in connection with acquired properties. +We have limited +control over activities on properties we do not operate, which could reduce our +production and revenues. +The +Company operates most of the wells in which it owns an interest. However it +also participates in some cases through joint operating agreements under which +it owns partial interests in oil and natural gas properties. If the Company +does not operate the properties in which it owns an interest, it does not have +control over normal operating procedures, expenditures or future development of +underlying properties. The failure of an operator to adequately perform +operations, or an operator's breach of the applicable agreements, could reduce +production and revenues. The success and timing of drilling and development +activities on properties operated by others therefore depends upon a number of +factors outside of the Company's control, including the operator's timing and +amount of capital expenditures, expertise and financial resources, inclusion of +other participants in drilling wells, and use of technology. +Market +conditions or operational impediments hinder access to oil and natural gas +markets or delay production. +Market +conditions or the unavailability of satisfactory oil and natural gas +transportation arrangements may hinder access to oil and natural gas markets or +delay production. The availability of a ready market for oil and natural gas +production depends on a number of factors, including the demand for and supply +of oil and natural gas and the proximity of reserves to pipelines and terminal +facilities. The Company's ability to market its production depends in +substantial part on the availability and capacity of gathering systems, pipelines +and processing facilities owned and operated by third parties. Failure to +obtain such services on acceptable terms could materially harm the Company's +business. We may be required to shut in wells for a lack of a market or because +of inadequacy or unavailability of natural gas pipeline, gathering system +capacity or processing facilities. If that were to occur, the Company would be +unable to realize revenue from those wells until production arrangements were +made to deliver the production to market. +Our hedging +activities could result in financial losses or could reduce our income. +To +achieve a more predictable cash flow, to reduce exposure to adverse +fluctuations in the prices of oil and natural gas and to allow our gas +marketing company to offer pricing options to gas sellers and purchasers, the +Company uses hedging arrangements for a portion of its oil and natural gas +production from its own wells, and for gas purchases and sales by its marketing +subsidiary. Hedging arrangements expose the Company to the risk of financial +loss in some circumstances, including when production, purchases or sales are +different than expected, the counter-party to the hedging contract defaults on +its contract obligations, or when there is a change in the expected differential +between the underlying price in the hedging agreement and actual prices +received. In addition, hedging arrangements may limit the benefit from +changes in the prices for oil and natural gas and may require the use of +Company resources to meet cash margin requirements. +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 the Company's overall credit +risk in that these entities may be similarly affected by changes in economic +and other conditions. In addition, the Company's oil and natural gas hedging +arrangements as well as the hedging arrangements of its marketing subsidiary +expose the Company to credit risk in the event of nonperformance by +counterparties. +The Company +depends on a limited number of key personnel who would be difficult to replace. +The Company depends on the performance of +our executive officers and other key employees. The loss of any member of +senior management or other key employees could negatively impact the Company's +ability to execute its strategy. The Company does not maintain key person life +insurance policies on any of its employees. +Competition in +the oil and natural gas industry is intense, which may adversely affect the +Company's ability to succeed. +The +oil and natural gas industry is intensely competitive, and the Company competes +with other companies that have greater resources. Many of these companies not +only explore for and produce oil and natural gas, but also carry on refining +operations and market petroleum and other products on a regional, national or +worldwide basis. These companies may be able to pay more for productive oil and +natural gas properties and exploratory prospects or define, evaluate, bid for +and purchase a greater number of properties and prospects than our financial or +human resources permit. In addition, these companies may have a greater ability +to continue exploration activities during periods of low oil and natural gas +market prices. Larger competitors may be able to absorb the burden of present +and future federal, state, local and other laws and regulations more easily +than the Company can, which would adversely affect the Company's competitive +position. The Company's ability to acquire additional properties and to +discover reserves in the future will be dependent upon its ability to evaluate +and select suitable properties and to consummate transactions in a highly +competitive environment. In addition, because of the many companies in our +industry have greater financial and human resources, the Company may be at a disadvantage +in bidding for exploratory prospects and producing oil and natural gas +properties. These factors could adversely affect the success of the Company's +operations and its profitability. +The Company is +subject to complex federal, state, local and other laws and regulations that +could adversely affect the cost, manner or feasibility of doing business. +The +Company's exploration, development, production and marketing operations are +regulated extensively at the federal, state and local levels. Environmental and +other governmental laws and regulations have increased the costs to plan, +design, drill, install, operate and abandon oil and natural gas wells. Under +these laws and regulations, the Company could also be liable for personal +injuries, property damage and other damages. Failure to comply with these laws +and regulations may result in the suspension or termination of operations and +subject the Company to administrative, civil and criminal penalties. Moreover, +public interest in environmental protection has increased in recent years, and +environmental organizations have opposed, with some success, certain drilling +projects. +Part of the regulatory environment +includes, in some cases, federal requirements for obtaining environmental +assessments, environmental impact studies and/or plans of development before +commencing exploration and production activities. In addition, the Company's +activities are subject to the regulation by oil and natural gas-producing +states of conservation practices and protection of correlative rights. These +regulations affect operations and limit the quantity of oil and natural gas +that can be produced and sold. A major risk inherent in our drilling plans is +the need to obtain drilling permits from state and local authorities. Delays in +obtaining regulatory approvals, drilling permits, 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 the Company's +ability to explore on or develop its properties. Additionally, the oil and +natural gas regulatory environment could change in ways that might +substantially increase the financial and managerial costs to comply with the +requirements of these laws and regulations and, consequently, adversely affect +profitability. Furthermore, the Company may be put at a competitive +disadvantage to larger companies in the industry who can spread these +additional costs over a greater number of wells and larger operating staff. See +"Business - Governmental Regulation - Regulation of Oil and Natural Gas +Exploration and Production" and "Business - Governmental Regulation - +Environmental Regulations" for a description of the laws and regulations that +affect us. \ No newline at end of file diff --git a/raw/filings/0000077877/2004/0000077877-05-000019/item13.txt b/raw/filings/0000077877/2004/0000077877-05-000019/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..9e4aba3b14c8cb64d0858e1baf3c9c9d32b7254d --- /dev/null +++ b/raw/filings/0000077877/2004/0000077877-05-000019/item13.txt @@ -0,0 +1,8 @@ +Item 13. Certain Relationships and Related +Transactions +The response to this +item is set forth herein in Note 8 in the Notes to Consolidated Financial +Statements and under "Election of Directors - Interest of Management in +Certain Transactions," in the Company's definitive proxy statement for its +2005 annual meeting of stockholders filed or to be filed with the Commission on +or before April 30, 2005, which we incorporate by reference. \ No newline at end of file diff --git a/raw/filings/0000077877/2004/0000077877-05-000019/item9a.txt b/raw/filings/0000077877/2004/0000077877-05-000019/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..cdd0ca46a044bdcdcc4e7f445b51ca6f2116e0fa --- /dev/null +++ b/raw/filings/0000077877/2004/0000077877-05-000019/item9a.txt @@ -0,0 +1,3335 @@ +Item 9A. Controls and Procedures +(a) +Disclosure Controls and Procedures +The Chief Executive Officer and Chief +Financial Officer conducted an evaluation of the effectiveness of the design +and operation of the Company's disclosure controls and procedures (as defined +in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended +(the Exchange Act)) as of the end of the period covered by this report. Based +on that evaluation, the Chief Executive Officer and Chief Financial Officer +concluded that the Company's disclosure controls and procedures were effective +as of the end of the period covered by this report. +(b) Management's Report on Internal +Control over Financial Reporting +The management of Petroleum Development +Corporation is responsible for establishing and maintaining adequate internal +control over financial reporting (as such term is defined in Exchange Act Rule +13a-15(f)). Petroleum Development Corporation's internal control system is +designed to provide reasonable assurance to the Company's management and Board +of Directors regarding the reliability of financial reporting and the +preparation of financial statements for external purposes in accordance with +generally accepted accounting principles. All internal control systems, +no matter how well designed, have inherent limitations. Accordingly, even +effective controls can provide only reasonable assurance with respect to +financial statement preparation and presentation. +Petroleum Development Corporation's +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 (COSO) in Internal +Control-Integrated Framework . Based on this assessment, management +concluded that the Company maintained effective internal control over financial +reporting as of December 31, 2004. +Management's assessment of the +effectiveness of internal control over financial reporting as of December 31, +2004 has been audited by KPMG LLP, the independent registered public accounting +firm that also audited the Company's consolidated financial statements. +KPMG LLP's attestation report on management's assessment of the Company's +internal control over financial reporting appears below. +(c) Changes in Internal Control over +Financial Reporting +There were no significant changes in +internal control over financial reporting (as defined in Rule 13a-15(f) under +the Exchange Act) that occurred during the fourth quarter of 2004 that have +materially affected, or are reasonably likely to materially affect, the +Company's internal control over financial reporting. +Report of +Independent Registered Public Accounting Firm +The Board of Directors and Stockholders +Petroleum Development Corporation: +We have audited management's assessment, included in the +accompanying Management's Report on Internal Control over Financial Reporting (Item +9A(b)), that Petroleum Development Corporation (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 (COSO). +Petroleum Development Corporation'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 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, management's assessment that Petroleum +Development Corporation 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 +(COSO). Also, in our opinion, Petroleum Development Corporation 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 (COSO). +We also have audited, in accordance with the standards +of the Public Company Accounting Oversight Board (United States), the +consolidated balance sheets of Petroleum Development Corporation and subsidiaries +as of December 31, 2004 and 2003, and the related consolidated statements of +income, stockholders' equity and comprehensive income (loss) and cash flows for +each of the years in the three-year period ended December 31, 2004, and our +report dated March 30, 2005 expressed an unqualified opinion on those +consolidated financial statements. +KPMG LLP +Pittsburgh, Pennsylvania +March 30, 2005 +PART III +Item +10. Directors and Executive Officers of the Company +Directors and Executive Officers of the Company +The executive officers and directors of the +Company, their principal occupations for the past five years and additional +information are set forth below: +Name +Age +Positions and Offices Held +Held Current +Position Since +Steven R. Williams +53 +Chairman and Chief Executive Officer, +and Director +January 2004 +March 1983 +Thomas E. Riley +52 +President +Director +December 2004 +November 2003 +Darwin L. Stump +49 +Chief Financial Officer and Treasurer +November 2003 +Eric R. Stearns +47 +Executive Vice President Exploration and Development +November 2003 +Gregory A. Morgan +46 +Secretary +September 2004 +Vincent F. D'Annunzio +52 +Director +February 1989 +Jeffrey C. Swoveland +49 +Director +March 1991 +Donald B. Nestor +56 +Director +March 2000 +Kimberly Luff Wakim +46 +Director +January 2003 +David C. Parke +38 +Director +November 2003 +Steven R. Williams was elected Chairman and Chief +Executive Officer in January 2004. Mr. Williams served as President From March +1983 until December 2004 and has been a Director of PDC since March 1983. +Thomas E. Riley was elected Director in January 2004 by +the Board of Directors and assumed the position of President in December 2004. +Previously Mr. Riley was appointed Executive Vice President of Production, +Natural Gas Marketing and Business Development in November 2003. Prior thereto, +Mr. Riley served as Vice President Gas Marketing and Acquisitions of PDC since +April 1996. Prior to joining PDC, Mr. Riley was president of Riley Natural Gas +Company, a natural gas marketing company which PDC acquired in April 1996. +Darwin L. Stump was appointed Chief Financial Officer and +Treasurer in November 2003. Mr. Stump has been an officer of the Company since +April 1995 and held the position of Corporate Controller since 1980. Mr. Stump, +a CPA, was a senior accountant with Main Hurdman, Certified Public Accountants +prior to joining PDC. +Eric R. Stearns was appointed Executive Vice President of +Exploration and Development in November 2003. Prior thereto, Mr. Stearns was +Vice President of Exploration and Development since April 1995. Mr. Stearns +joined PDC as a geologist in 1985 after working for Hywell, Incorporated and +for Petroleum Consultants. +Gregory A. Morgan has been a member of the law firm of +Young, Morgan & Cann, Clarksburg, West Virginia since 1986. Mr. Morgan is +not active in the day-to-day business of PDC, but his law firm provides legal +services to PDC. +Vincent F. D'Annunzio has served as president of Beverage +Distributors, Inc. located in Clarksburg, West Virginia since 1985. +Jeffrey C. Swoveland has served as Chief Financial +Officer of Body Media since September, 2000. Prior thereto, Mr. Swoveland was +Vice President-Finance and Treasurer of Equitable Resources Inc since 1994. +Donald B. Nestor, is a Certified Public Accountant and a +Partner in the CPA firm of Toothman Rice, P.L.L.C. and is in charge of the +firm's Buckhannon, West Virginia office. Mr. Nestor has served in that +capacity since 1975. +Kimberly Luff Wakim, an Attorney and Certified Public +Accountant, is a Partner with the law firm Thorp, Reed & Armstrong LLP. +Ms. Wakim joined Thorp Reed & Armstrong LLP in 1990. +David C. Parke was elected Director by the Board of +Directors in November 2003. In 2003, Mr. +Parke joined Mufson/Howe/Hunter & Company LLC, an investment banking firm +as a founder and Director. From 1992-2003, Mr. Parke was with the corporate +finance department of Investec, Inc. and its predecessor Pennsylvania Merchant +Group Ltd., investment banking companies. Prior to joining Pennsylvania +Merchant Group, Mr. Parke served in the corporate finance departments of Wheat +First Butcher & Singer, now part of Wachovia Securities, and Legg Mason, +Inc. +The Company's By-Laws +provide that the directors of the Company shall be divided into three classes +and that, at each annual meeting of stockholders of the Company, successors to +the class of directors whose term expires at the annual meeting will be elected +for a three-year term. The classes are staggered so that the term of one class +expires each year. Mr. Swoveland and Mr. Parke are members of the class whose +term expires in 2005. Mr. Williams, Mr. Nestor and Ms. Wakim are members of +the class whose term expires in 2006. Mr. D'Annunzio and Mr. Riley are members +of the class whose term expires in 2007. There is no family relationship +between any director or executive officer and any other director or executive +officer of the Company. There are no arrangements or understandings between any +director or officer and any other person pursuant to which such person was +selected as an officer. +On January 24, 2003, the +Company adopted a Code of Business Conduct and Ethics Policy meeting the +specified standards applicable to the Chief Executive Officer and Chief +Financial Officer. The policy also covers all the corporate officers. The +policy is posted on the Company's website at www.petd.com. The Company will provide a copy of the +Code to any person, without charge, upon request to the Company's Secretary at +the Company's principal executive offices or by telephone at 800-624-3821. +The Audit Committee +of the Board of Directors is comprised entirely of independent directors as +defined by the NASDAQ rule 4200(a)(15). Donald B. Nestor, CPA, a partner in +the certified public accounting firm of Toothman Rice PLLC, chairs the +committee. Mr. Nestor and the other audit committee members, qualify as audit +committee financial experts and are independent of management. +The Nominating and +Governance and Compensation Committees are also comprised entirely of +independent directors of the Company. Vincent F. D'Annunzio chairs the +Nominating and Governance Committee, and Jeffrey C. Swoveland chairs the +Compensation Committee. +Shareholders wishing +to communicate with the Board of Directors or a committee may do so by writing +to the attention of the Board or Committee at the corporate headquarters or by +emailing the Board at board@petd.com, with "Board" or appropriate +committee in the subject line. +Item 11 Executive Compensation +There is +incorporated by reference herein in response to this Item the material under +the heading "Election of Directors - Remuneration of Directors and +Officers", "Election of Directors - Stock Options" and +"Election of Directors - Interest of Management in Certain +Transactions" in the Company's definitive proxy statement for its 2005 +annual meeting of stockholders filed or to be filed with the Commission on or +before April 30, 2005. +Item 12. Security Ownership of Certain Beneficial +Owners, Management and Related Stockholder Matters +There is +incorporated by reference herein in response to this Item, the material under +the heading "Election of Directors", in the Company's definitive +proxy statement for its 2005 annual meeting of stockholders filed or to be +filed with the Commission on or before April 30, 2005. +The Company has the +following common stock options outstanding under the stock option plans +approved by the stockholders: +Equity +Compensation Plan Information +December 31, 2004 +Plan Category +Number of securities to +be issued upon exercise +of outstanding options, +warrants and rights +(a) +Weighted-average +exercise price of +outstanding options, +warrants and rights +(b) +Number of securities +remaining available for +future issuance under +equity compensation +plans (excluding +securities reflected in +column (a)) +(c) +Equity compensation plans +approved by security holders +76,880 +$11.64 +733,120 +Equity compensation plans not +approved by security holders +- +- +- +Total +76,880 +$11.64 +733,120 +Item 13. Certain Relationships and Related +Transactions +The response to this +item is set forth herein in Note 8 in the Notes to Consolidated Financial +Statements and under "Election of Directors - Interest of Management in +Certain Transactions," in the Company's definitive proxy statement for its +2005 annual meeting of stockholders filed or to be filed with the Commission on +or before April 30, 2005, which we incorporate by reference. +Item 14. Principal Accounting Fees and Services +The information under the caption "Fees Billed by +Independent Public Accountants for Services in 2004 and 2003" in the +Company's definitive Proxy Statement in connection with the 2005 annual +stockholders' meeting is incorporated by reference. +Item 15. Exhibits, Financial Statement Schedules and +Reports on Form 8-K +(a) (1) Financial +Statements: +See +Index to Financial Statements and Schedules on page F-1. +(2) Financial +Statement Schedules: +See +Index to Financial Statements and Schedules on page F-1. +Schedules +and Financial Statements Omitted +All other financial +statement schedules are omitted because they are not required, inapplicable, or +the information is included in the Financial Statements or Notes thereto. +(3) Exhibits: +See +Exhibits Index on page E-1. +CONFORMED COPY +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. +PETROLEUM +DEVELOPMENT CORPORATION +By /s/ +Steven R. Williams +Steven R. +Williams, Chairman +March 31, 2005 +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/ Steven R. Williams +Steven R. Williams +Chairman, Chief Executive Officer and Director +March 31, 2005 +/s/ Darwin L. Stump +Darwin L. Stump +Chief Financial Officer and Treasurer +(principal financial and accounting officer) +March 31, 2005 +/s/ Thomas E. Riley +Thomas E. Riley +President and Director +March 31, 2005 +/s/ Donald B. Nestor +Donald B. Nestor +Director, Chairman of Audit Committee +March 31, 2005 +/s/ Vincent F. D'Annunzio +Vincent F. D'Annunzio +Director +March 31, 2005 +/s/ Jeffrey C. Swoveland +Jeffrey C. Swoveland +Director +March 31, 2005 +/s/ Kimberly Luff Wakim +Kimberly Luff Wakim +Director +March 31, 2005 +/s/ David C. Parke +David C. Parke +Director +March 31, 2005 +Exhibits Index +(a) Exhibits +Exhibit Name +Exhibit +Number +Location +Articles of Incorporation +3.1 +Incorporated by reference to Exhibit 3.1 to Form S-2 +SEC File No. 333-36369 filed on September 25, 1997 +By Laws +3.2 +Incorporated by reference to Exhibit 3.2 to Form 8-K +SEC File No. 0-07246 filed on September 8, 2003 +Credit Agreement, dated as of July 3, 2002, as extended +as of April 30, 2004 by and between Petroleum Development Corporation and the +lenders, Bank One N.A. and BNP Paribas +10.1 +Incorporated by reference to Exhibit 10.1 to Form 10-K +for year ended December 31, 2002, SEC File No. 0-07246 filed on March 7, 2003 +Employment Agreement with Steven R. Williams, Chief +Executive Officer and Chairman, dated as of March 7, 2003 +10.2 +Incorporated by reference in Exhibit 10.2 to Form 10-K filed +on March 7, 2003 +Employment Agreement with Darwin L. Stump, Chief +Financial Officer, dated as of January 5, 2004 +10.3 +Incorporated by reference to Exhibit 99.4 Form 8-K +dated January 5, 2004 +Employment Agreement with Thomas E. Riley, President, +dated as of January 5, 2004 +10.4 +Incorporated by reference to Exhibit 99.6 Form 8-K +dated January 5, 2004 +Employment Agreement with Eric R. Stearns, Executive +Vice President, dated as of January 5, 2004 +10.5 +Incorporated by reference to Exhibit 99.5 Form 8-K +dated January 5, 2004 +2004 Long-Term Equity Compensation Plan +10.6 +Incorporated by reference to Exhibit 99.1 to Form S-8, +SEC File No. 333-118215, filed on August 13, 2004 +Non-Employee Director Deferred Compensation Plan +10.7 +Incorporated by reference Exhibit 99.1 to Form S-8, SEC +File No. 333-118222, filed on August 13, 2004 +1999 Incentive Stock Option and Non-Qualified Stock +10.8 +Incorporated by reference to Exhibit 99.1 to form S-8, +SEC File No. 333-111825, filed on January 9, 2004 +1997 Employee Incentive Stock Option Plan +10.9 +Incorporated by reference to Exhibit 99.1 to Form S-8, +SEC File No. 333-111824, filed on January 9, 2004 +Tom Carpenter Employment Agreement Stock Option Plan +10.10 +Incorporated by reference to Exhibit 99.1 to Form S-8, +SEC File No. 333-111823, filed on January 9, 2004 +Code of Business Conduct and Ethics +14 +Incorporated by reference to Exhibit 3.1 to +Form 10-K for the year ended December 31, 2002, SEC +File No. 0-07246 filed on March 7, 2003 +Subsidiaries +21 +Riley Natural Gas Company, a West Virginia Corporation +21 +PDC Securities Incorporated, a West Virginia +Corporation +Consent of Independent Registered Public Accounting +Firm +23.1 +Filed herewith. +Consent of Independent Petroleum Engineers +23.2 +Filed herewith. +Rule 13a-14(a)/15d-14(a) Certification by Chief +Executive Officer +31.1 +Filed herewith. +Rule 13a-14(a)/15d-14(a) Certification by Chief +Financial Officer +31.2 +Filed herewith. +Title 18 U.S.C. Section 1350 (Section 906 of +Sarbanes-Oxley Act of 2002) Certifications by Chief Executive Officer and +Chief Financial Officer +32.1 +Filed herewith. +(b) +Reports +on Form 8-K during quarter ended December 31, 2004. +Form 8-K current +report dated December 16, 2004, under item 1.01 Entry into a Material +Definitive Agreement, the +Compensation Committee of Petroleum Development Corporation has established +2004 grants for the executive officers of the company (the Participants). The +grants are being awarded pursuant to the terms of the Petroleum Development +Corporation 2004 Long-Term Equity Compensation Plan that was approved by the +shareholders of the company at the June 11, 2004 Annual Meeting. +Form 8-K/A current report dated +December 15, 2004, under Item 5.02. Any +resignation, appointment, retirement, removal or termination of a director or +executive officer or any director's refusal to stand for reelection. The +Company issued a news release announcing that Thomas E. Riley has been selected +as President of the Company filling the position currently held by Steven R. +Williams. Mr. Williams will remain CEO and Chairman of PDC. +Form 8-K current report dated December 15, +2004, under Item 5 Other Events, the Company issued a news release announcing +that Thomas E. Riley has been selected as President of the Company filling the +position currently held by Steven R. Williams. Mr. Williams will remain CEO and +Chairman of PDC. +Form 8-K current report dated November 5, 2004, under Item 2.02 Results +of Operations and Financial Condition, the Company issued a news release +announcing financial and operating results for the third quarter 2004. +Form 8-K current report dated October 29, +2004, under Item 8.01. Other +Events, the Company issued a news release announcing upcoming earnings release +and invites you to join its third quarter earnings web cast. +PETROLEUM +DEVELOPMENT CORPORATION AND SUBSIDIARIES +Index to Financial +Statements and Financial Statement Schedule +1. +Financial Statements: +Report of Independent +Registered Public Accounting Firm +F-2 +Consolidated Balance +Sheets - December 31, 2004 and 2003 +F-3 & 4 +Consolidated Statements +of Income - +Years Ended +December 31, 2004, 2003 and 2002 +F-5 +Consolidated Statements +of Stockholders' Equity and Comprehensive Income (Loss) +Years Ended +December 31, 2004, 2003 and 2002 +F-6 +Consolidated Statements +of Cash Flows - +Years Ended +December 31, 2004, 2003 and 2002 +F-7 +Notes to Consolidated +Financial Statements +F-8 -F-27 +2. +Financial Statement Schedule: +Schedule II - Valuation and Qualifying Accounts and +Reserves +F-28 +Report of +Independent Registered Public Accounting Firm +The Board of Directors and Stockholders +Petroleum Development Corporation: +We have audited the accompanying consolidated balance +sheets of Petroleum Development Corporation and subsidiaries as of December 31, +2004 and 2003, and the related consolidated statements of income, stockholders' +equity and comprehensive income (loss), and cash flows for each of the years in +the three-year period ended December 31, 2004. In connection with our audits of +the consolidated financial statements, we also have audited financial statement +schedule II. These consolidated financial statements and financial statement +schedule are the responsibility of the Company's management. Our responsibility +is to express an opinion on these consolidated financial statements and +financial statement schedule 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, the consolidated financial statements +referred to above present fairly, in all material respects, the financial position +of Petroleum Development Corporation and subsidiaries as of December 31, 2004 +and 2003, and the results of their operations and their cash flows for each of +the years in the three-year period ended December 31, 2004, in conformity with +U. S. generally accounting principles. Also in our opinion, the related +financial statement schedule, when considered in relation to the basic +consolidated financial statements taken as a whole, presents fairly, in all +material respects, the information set forth therein. +As discussed in note 1 to the consolidated financial +statements, the Company adopted the provisions of Statement of Financial +Accounting Standards No. 143, Accounting for Asset Retirement Obligations, in +2003. +We also have audited, in accordance with the standards of +Public Company Accounting Oversight Board (United States), the effectiveness of +Petroleum Development Corporation's 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 (COSO) and our report dated March 30, 2005, expressed an unqualified +opinion on management's assessment of, and effective operation of, internal +control over financial reporting. +KPMG LLP +Pittsburgh, Pennsylvania +March 30, 2005 +PETROLEUM +DEVELOPMENT CORPORATION AND SUBSIDIARIES +Consolidated Balance +Sheets +December 31, 2004 +and 2003 +Assets +2004 +2003 +Current assets: +Cash and cash equivalents +$77,070,400 +$ 78,512,900 +Restricted cash +664,900 +1,866,400 +Notes and accounts receivable +33,902,800 +23,067,000 +Inventories +1,657,300 +2,014,300 +Other current assets +7,334,200 +5,907,000 +Total current assets +120,629,600 +111,367,600 +Properties and equipment: +Oil and gas properties (successful +efforts accounting method) +291,436,700 +251,558,900 +Pipelines +9,515,000 +9,097,000 +Transportation and other equipment +4,453,700 +3,460,900 +Land and buildings +2,942,800 +1,747,500 +308,348,200 +265,864,300 +Less accumulated depreciation, +depletion and amortization +88,341,300 +71,182,100 +220,006,900 +194,682,200 +Other assets +756,500 +672,200 +Total Assets +$341,393,000 +$306,722,000 +(Continued) +PETROLEUM +DEVELOPMENT CORPORATION AND SUBSIDIARIES +Consolidated Balance +Sheets +December 31, 2004 +and 2003 +2004 +2003 +Liabilities and Stockholders' Equity +Current liabilities: +Accounts payable +$42,438,400 +$ 29,453,000 +Production tax liability +17,510,500 +9,069,400 +Other accrued expenses +5,807,900 +7,744,800 +Advances for future drilling contracts +42,497,300 +50,458,800 +Funds held for future distribution +12,911,800 +8,410,900 +Total +current liabilities +121,165,900 +105,136,900 +Long-term debt +21,000,000 +53,000,000 +Other liabilities +3,927,500 +2,449,100 +Deferred income taxes +29,843,200 +21,800,200 +Asset retirement obligation +783,500 +731,200 +Commitments and contingencies (Note 9) +Stockholders' equity: +Common stock, par value $.01 per share; +authorized 50,000,000 shares; issued and +outstanding 16,589,324 and 15,628,433 shares +165,800 +156,200 +Additional paid-in capital +37,684,300 +28,592,900 +Retained earnings +130,109,800 +96,049,200 +Unamortized stock award +(882,000) +(14,800) +Accumulated other comprehensive loss, net of tax +(2,405,000) +(1,178,900 ) +Total +stockholders' equity +164,672,900 +123,604,600 +Total Liabilities and Stockholders' Equity +$341,393,000 +$306,722,000 +See accompanying notes to consolidated financial +statements. +PETROLEUM +DEVELOPMENT CORPORATION AND SUBSIDIARIES +Consolidated +Statements of Income +Years Ended December +31, 2004, 2003 and 2002 +2004 +2003 +2002 +Revenues: +Oil +and gas well drilling operations +$119,210,500 +71,841,500 +57,149,100 +Gas +sales from marketing activities +93,231,400 +73,141,100 +46,365,900 +Oil +and gas sales +67,947,700 +47,021,600 +22,857,100 +Well +operations and pipeline income +8,384,500 +7,347,700 +6,116,200 +Other +income +1,945,700 +3,499,100 +2,853,600 +290,719,800 +202,851,000 +135,341,900 +Costs +and expenses: +Cost +of oil and gas well drilling operations +102,830,700 +61,277,800 +49,166,200 +Cost +of gas marketing activities +91,898,100 +72,443,600 +46,184,300 +Oil +and gas production and well operations costs +18,049,800 +13,749,200 +9,074,200 +General +and administrative expenses +4,505,600 +4,974,400 +4,391,900 +Depreciation, +depletion and amortization +17,958,200 +14,153,400 +12,103,300 +Interest +874,300 +1,329,100 +1,339,800 +236,116,700 +167,927,500 +122,259,700 +Income +before income taxes and cumulative effect of +change +in accounting principle +54,603,100 +34,923,500 +13,082,200 +Income taxes +20,542,500 +12,105,800 +3,797,400 +Net +income before cumulative effect of change in +accounting +principle +34,060,600 +22,817,700 +9,284,800 +Cumulative effect +of change in accounting principle +(net +of taxes of $121,700) +- +(198,600 ) +- +Net income +$34,060,600 +22,619,100 +9,284,800 +Basic earnings per +common share before accounting change +$2.10 +1.46 +.59 +Cumulative effect of change in +accounting principle +- +(0.01) +- +Basic earnings per +common share +$ 2.10 +1.45 +.59 +Diluted earnings +per share before accounting change +$2.05 +1.40 +.58 +Cumulative effect +of change in accounting principle +- +(0.01) +- +Diluted earnings +per common and common equivalent share +$ 2.05 +1.39 +.58 +See +accompanying notes to consolidated financial statements. +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Consolidated +Statements of Stockholders' Equity and Comprehensive Income (Loss) +Years Ended December +31, 2004, 2003 and 2002 +Common +stock issued +Number +Of +Shares +Amount +Additional +Paid-in- +capital +Retained +Earnings +Unamortized +Stock Award +Accumulated +Other Comprehensive +Income (loss) +Total +Balance, +December 31, 2001 +16,245,752 +$ +162,400 +32,951,700 +64,145,300 +(29,200) +(457,400) +96,772,800 +Issuance +of common stock: +Exercise +of employee stock options +70,000 +700 +78,100 +- +- +78,800 +Amortization +of stock award +- +- +5,500 +- +5,500 +Repurchase +and cancellation of treasury stock +(580,985) +(5,800) +(3,689,300) +(3,695,100) +Net +income +- +- +- +9,284,800 +- +- +9,284,800 +Comprehensive +income: +Reclassification adjustment for settlement of contracts +Included in net income (net of tax of $9,100) +- +- +- +- +- +14,800 +Changes in fair value of outstanding hedging positions +and +interest rate swap (net of tax of $820,900) +- +- +- +- +- +(1,339,400 ) +Other comprehensive loss +(1,324,600) +(1,324,600 ) +Comprehensive +income +_________ +___________ +_________ +___________ +___________ +________ +7,960,200 +Balance, +December 31, 2002 +15,734,767 +157,300 +29,340,500 +73,430,100 +(23,700) +(1,782,000) +101,122,200 +Amortization +of stock award +- +- +8,900 +- +8,900 +Repurchase +and cancellation of treasury stock, net +(106,334) +(1,100) +(747,600) +(748,700) +Net +income +- +- +- +22,619,100 +- +- +22,619,100 +Comprehensive +income: +Reclassification adjustment for settlement of contracts +Included in net income (net of tax of $583,900) +- +- +- +- +- +917,200 +Changes in fair value of outstanding hedging positions +and +interest rate swap (net of tax of $200,000) +- +- +- +- +- +(314,100 ) +Other comprehensive income +603,100 +603,100 +Comprehensive +income +_________ +___________ +_________ +___________ +___________ +________ +23,222,200 +Balance, +December 31, 2003 +15,628,433 +156,200 +28,592,900 +96,049,200 +(14,800) +(1,178,900) +123,604,600 +Issuance +of common stock +Exercise +of employee stock options +1,100,000 +11,000 +4,981,700 +- +- +- +4,992,700 +Stock +Award +23,380 +200 +870,700 +- +(870,900) +- +Amortization +of stock award +- +- +- +3,700 +- +3,700 +Repurchase +and cancellation of treasury stock, net +(162,489) +(1,600) +(4,155,800) +- +- +- +(4,157,400) +Income +tax benefit from the exercise of stock options +- +- +7,394,800 +- +- +- +7,394,800 +Net +income +- +- +- +34,060,600 +- +- +34,060,600 +Comprehensive +income: +- +- +- +- +- +Reclassification adjustment for settlement of contracts +Included in net income (net of tax of $2,084,400) +- +- +- +- +- +3,274,000 +Changes in fair value of outstanding hedging positions +and +interest rate swap (net of tax of $2,865,000) +- +- +- +- +- +(4,500,100 ) +Other comprehensive loss +- +- +- +- +(1,226,100) +(1,226,100) +Comprehensive +income +_________ +___________ +_________ +___________ +___________ +________ +32,834,500 +Balance, +December 31, 2004 +16,589,324 +$ 165,800 +37,684,300 +130,109,800 +(882,000) +(2,405,000) +164,672,900 +See accompanying +notes to consolidated financial statements. +PETROLEUM +DEVELOPMENT CORPORATION AND SUBSIDIARIES +Consolidated +Statements of Cash Flows +Years Ended December +31, 2004, 2003 and 2002 +2004 +2003 +2002 +Cash flows from operating activities: +Net income +$34,060,600 +22,619,100 +9,284,800 +Adjustment to reconcile net income to cash provided by +operating activities: +Deferred income taxes +10,443,600 +8,870,700 +2,986,400 +Depreciation, depletion and amortization +17,958,200 +14,153,400 +12,103,300 +Cumulative effect of change in accounting principle +- +198,600 +- +Gain from sale of assets +(32,000) +(115,800) +(25,800) +Expired and abandoned leases +344,700 +1,418,400 +1,129,400 +Amortization of stock award +3,700 +8,900 +5,500 +(Increase) in notes and accounts receivable +(10,835,800) +(7,187,100) +(4,583,900) +Decrease (increase) in inventories +357,000 +(1,383,600) +(56,200) +Decrease (increase) in other current assets +4,776,200 +(1,095,900) +369,200 +(Increase) decrease in other assets +(281,300) +1,696,200 +56,300 +Increase in production tax liability +8,441,100 +3,974,800 +1,833,400 +Increase in accounts payable and accrued expenses +10,091,500 +12,782,200 +111,800 +(Decrease) increase in advances for future drilling +contracts +(7,961,500) +13,175,000 +5,691,600 +Increase (decrease) in funds held for future +distribution +4,500,900 +4,493,000 +(732,900 ) +Total +adjustments +37,806,300 +50,988,800 +18,888,100 +Net +cash provided by operating activities +71,866,900 +73,607,900 +28,172,900 +Cash flows from investing activities: +Capital expenditures +(45,391,800) +(73,042,300) +(19,777,000) +Proceeds from sale of leases to partnerships +1,950,900 +1,382,100 +1,042,500 +Proceeds from sale of fixed assets +94,700 +156,800 +25,800 +Decrease (increase) in restricted cash +1,201,500 +894,100 +(2,477,200 ) +Net cash used in +investing activities +(42,144,700 ) +(70,609,300 ) +(21,185,900 ) +Cash flows from financing activities: +(Retirement of) proceeds from debt, net +(32,000,000) +28,000,000 +(3,000,000) +Proceeds from issuance of stock +3,584,400 +- +78,800 +Repurchase and cancellation of treasury stock +(2,749,100 ) +(748,700 ) +(3,695,100 ) +Net cash (used +in) provided by financing activities +(31,164,700 ) +27,251,300 +(6,616,300 ) +Net (decrease) increase in cash and cash equivalents +(1,442,500) +30,249,900 +370,700 +Cash and cash equivalents, beginning +of year +78,512,900 +48,263,000 +47,892,300 +Cash and cash equivalents, end of +year +$ 77,070,400 +78,512,900 +48,263,000 +See accompanying notes to consolidated financial +statements. +PETROLEUM +DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to +Consolidated Financial Statements +Years Ended December +31, 2004, 2003 and 2002 +(1) Summary +of Significant Accounting Policies +Principles +of Consolidation +The accompanying +consolidated financial statements include the accounts of Petroleum Development +Corporation (PDC) and its wholly owned subsidiaries, Riley Natural Gas (RNG) +and PDC Securities Incorporated. All material intercompany accounts and +transactions have been eliminated in consolidation. The Company accounts for +its investment in limited partnerships under the proportionate consolidation +method. Under this method, the Company's financial statements include its +prorata share of assets and liabilities and revenues and expenses, +respectively, of the limited partnerships in which it participates. +The Company is +involved in four business segments. The segments are drilling and development, +natural gas marketing, oil and gas sales and well operations. (See Note 19) +The Company grants +credit to purchasers of oil and gas and the owners of managed properties, +substantially all of whom are located in West Virginia, Tennessee, +Pennsylvania, Michigan, North Dakota, Colorado and Kansas. +Cash Equivalents +For purposes of the +statement of cash flows, the Company considers all highly liquid debt +instruments with original maturities of three months or less to be cash +equivalents. +Restricted Cash +The Company is +required to maintain margin deposits with brokers for outstanding future +contracts. As of December 31, 2004 and 2003, cash in the amount of $664,900 and +$1,866,400 was on deposit. +Inventories +Inventories of well +equipment, parts and supplies are valued at the lower of average cost or +market. An inventory of natural gas is recorded when gas is purchased in excess +of deliveries to customers and is recorded at the lower of cost or market. +Oil and Gas +Properties +Exploration and +development costs are accounted for by the successful efforts method. +The Company assesses +impairment of capitalized costs of proved oil and gas properties by comparing +net capitalized costs to estimated undiscounted future net cash flows on a +field-by-field basis using expected prices. Prices utilized in each year's +calculation for measurement purposes and expected costs are held constant +throughout the estimated life of the properties. If net capitalized costs +exceed undiscounted future net cash flows, the measurement of impairment is +based on estimated fair value which would consider future discounted cash +flows. +Property acquisition +costs are capitalized when incurred. Geological and geophysical costs and +delay rentals are expensed as incurred. The costs of drilling exploratory +wells are capitalized pending determination of whether the wells have +discovered economically producible reserves. If reserves are not discovered, +such costs are expensed as dry holes. Development costs, including equipment +and intangible drilling costs related to both producing wells and developmental +dry holes, are capitalized. +Unproved properties +or leases are written-off to expense when it is determined that they will +expire or be abandoned. +(Continued) +PETROLEUM +DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to +Consolidated Financial Statements +Costs +of proved properties, including leasehold acquisition, exploration and +development costs and equipment, are depreciated or depleted by the +unit-of-production method based on estimated proved developed oil and gas +reserves. +Upon +sale or retirement of complete fields of depreciable or depletable property, the +book value thereof, less proceeds or salvage value, is credited or charged to +income. Upon sale of a partial unit of property, the proceeds are credited to +accumulated depreciation and depletion. +Transportation +Equipment, Pipelines and Other Equipment +Transportation +equipment, pipelines and other equipment are carried at cost. Depreciation is +provided principally on the straight-line method over useful lives of 3 to 17 +years. The Company adopted FASB Statement No. 144 "Accounting for the +Impairment or Disposal of Long-Lived Assets" on January 1, 2002. The +adoption of FASB No. 144 did not affect the Company's financial statements. +In +accordance with FASB Statement No. 144, long-lived assets, such as property, +plant, and equipment, are reviewed for impairment whenever events or changes in +circumstances indicate that the carrying amount of an asset may not be +recoverable. Recoverability of assets to be held and used is measured by a +comparison of the carrying amount of an asset to estimated undiscounted future +cash flows expected to be generated by the asset. If the carrying amount of an +asset exceeds its estimated future cash flows, an impairment charge is +recognized in the amount by which the carrying amount of the asset exceeds the +fair value of the asset. +Maintenance +and repairs are charged to expense as incurred. Major renewals and betterments +are capitalized. Upon the sale or other disposition of assets, the cost and +related accumulated depreciation, depletion and amortization are removed from +the accounts, the proceeds applied thereto and any resulting gain or loss is +reflected in income. +Buildings +Buildings +are carried at cost and depreciated on the straight-line method over estimated +useful lives of 30 years. +Asset +Retirement Obligations +The +Company incurs retirement obligations for its well drilling operations under +FASB Statement No. 143, "Accounting for Asset Retirement +Obligations". This requires entities to record the fair value of a +liability for an asset retirement obligation in the period incurred and a +corresponding increase in the carrying amount of the long-lived assets. The +costs associated with this liability are capitalized as part of the related +long-lived asset and depreciated. The Company adopted FASB No. 143 on January +1, 2003 and recorded a net asset of $271,800 and a related liability of +$592,100 (using a 6% discount rate) and a cumulative effect of change in +accounting principle on prior years of $198,600 (net of taxes of $121,700). +Since adoption the obligation has increased to $783,500 as of December 31, 2004 +due to the additional wells purchased and drilled by the Company and accretion, +offset in part by wells plugged. +Advances +for Future Drilling Contracts +Advances +for future drilling contracts represents funds received from Partnerships and +other joint ventures for drilling activities which have not been completed and +accordingly have not yet been recognized as revenue in accordance with the +Company's revenue recognition policies. +Retirement +Plans +The +Company has a 401-K contributory retirement plan (401-K Plan) covering +full-time employees. The Company provides a discretionary matching of employee +contributions to the plan. +The +Company also has a profit sharing plan covering full-time employees. The +Company's contributions to this plan are discretionary. +(Continued) +PETROLEUM +DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to +Consolidated Financial Statements +The +Company has a deferred compensation arrangement covering executive officers of +the Company as a supplemental retirement benefit. +Revenue +Recognition +The +Company's drilling segment recognizes revenue from our drilling contracts with +our publicly registered drilling programs using the percentage of completion +method. These contracts are footage rate based and completed within nine to +twelve months after the commencement of drilling. The Company provides +geological, engineering, and drilling supervision on the drilling and +completion process and uses subcontractors to perform drilling and completion +services. The percentage of completion method measures the percentage of +contract costs incurred to date to the estimated total contract costs for each +contract. The Company utilizes this method because reasonably dependable +estimates of the total estimated costs can be made. Because the revenue +recognized depends on estimates of the final contract costs, which are assessed +continually during the term of the contract, recognized revenues are subject to +revisions as the contract progresses. Anticipated losses, if any, on +uncompleted contracts would be recorded at the time that our estimated costs +exceeded the contract revenue. The Company has not experienced any contract +losses in 2004, 2003, or 2002. +Natural gas marketing is +recorded on the gross accounting method. Riley Natural Gas ("Riley"), our +marketing subsidiary, purchases gas from many small producers and bundles the +gas together to sell in larger amounts to purchasers of natural gas for a price +advantage. Riley has latitude in establishing price and discretion in supplier +and purchaser selection. Natural gas marketing revenues and expenses reflect +the full cost and revenue of those transactions because Riley takes title to +the gas it purchases from the various producers and bears the risks and enjoys +the benefits of that ownership. +Sales of natural gas are +recognized when natural gas has been delivered to a custody transfer point, +persuasive evidence of a sales arrangement exists, the rights and +responsibility of ownership pass to the purchaser upon delivery, collection of +revenue from the sale is reasonably assured and the sales price is fixed or +determinable. Natural gas is sold by the Company under contracts with terms +ranging from one month to three years. Virtually all of the Company's contracts +pricing provisions are tied to a market index, with certain adjustments based +on, among other factors, whether a well delivers to a gathering or transmission +line, quality of natural gas and prevailing supply and demand conditions, so +that the price of the natural gas fluctuates to remain competitive with other +available natural gas supplies. As a result, the Company's revenues from the +sale of natural gas will suffer if market prices decline and benefit if they +increase. The Company believes that the pricing provisions of its natural gas +contracts are customary in the industry. +Company currently uses the +"Net-Back" method of accounting for transportation arrangements of our natural +gas sales. The Company sells gas at the wellhead and collects a price and +recognizes revenues based on the wellhead sales price since transportation +costs downstream of the wellhead are incurred by our customers and reflected in +the wellhead price. +Sales of oil are recognized +when persuasive evidence of a sales arrangement exists, the oil is verified as +produced and is delivered in a stock tank, collection of revenue from the sale +is reasonably assured and the sales price is determinable. The Company is +currently able to sell all the oil that it can produce under existing sales +contracts with petroleum refiners and marketers. The Company does not refine +any of its oil production. The Company's crude oil production is sold to +purchasers at or near the Company's wells under short-term purchase contracts +at prices and in accordance with arrangements that are customary in the oil +industry. +Well operations and +pipeline income is recognized when persuasive evidence of an arrangement +exists, services have been rendered, collection of revenues is reasonably +assured and the sales price is fixed or determinable. The Company is paid a +monthly operating fee for each well it operates for outside owners including +the limited partnerships sponsored by the Company. The fee is competitive with +rates charged by other operators in the area. The fee covers monthly operating +and accounting costs, insurance and other recurring costs. The Company may +also receive additional compensation for special non-recurring activities, such +as reworks and recompletions. +(Continued) +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +Income +Taxes +Income +taxes are accounted for under the asset and liability method. +Deferred +tax assets and liabilities are recognized for the future tax consequences +attributable to differences between the financial statement carrying amounts of +existing assets and liabilities and their respective tax bases. Deferred tax +assets and liabilities are measured using enacted tax rates expected to apply +to taxable income in the years in which those temporary differences are +expected to be recovered or settled. The effect on deferred tax assets and +liabilities of a change in tax rates is recognized in income in the period that +includes the enactment date. +Derivative +Financial Instruments +The +Company accounts for derivatives and hedging in accordance with FASB Statement +No. 133 Accounting for Derivative Instruments and Certain Hedging Activities, +as amended which requires that all derivatives be recorded on the consolidated +balance sheet at their fair values. On the date the derivative contract is +entered into, the Company designates the derivative as either a hedge of a +forecasted transaction or the variability of cash flows to be received or paid +related to a recognized asset or liability ("Cash flow" hedge), or a +non-hedging derivative. The Company formally documents all relationships +between hedging instruments and hedged items, as well as its risk-management +objective and strategy for undertaking various hedge transactions. This process +includes linking all derivatives that are designated as cash-flow hedges to +specific firm commitments. The Company also formally assesses, both at the +hedge's inception and on an ongoing basis, whether the derivatives that are +used in hedging transactions are highly effective in offsetting changes in cash +flows of hedged items. When it is determined that a derivative is not highly +effective as a hedge or that it has ceased to be a highly effective hedge, the +Company discontinues hedge accounting prospectively. No hedging activities +were discontinued during 2004, 2003 or 2002. +Changes +in fair value of a derivative that is highly effective and that is designated +and qualifies as a cash-flow hedge are recorded in other comprehensive income, +until earnings are affected by the variability in cash flows of the designated +hedged item. Changes in the fair value of non-hedging derivatives are reported +in current-period earnings. The Company discontinues hedge accounting +prospectively when it is determined that the derivative is no longer effective +in offsetting changes in the cash flows of the hedged item, the derivative +expires or is sold, terminated, or exercised. Additionally, if the derivative +is designated as a hedging instrument, and it is subsequently determined to be +probable that a forecasted transaction will not occur or management determines +that designation of the derivative as a hedging instrument is no longer +appropriate, hedge accounting will be discontinued. +The +Company uses derivative financial instruments for several purposes. The Company +manages its exposure to price fluctuations in selling and producing natural gas +by entering into natural gas future contracts and options contracts. +Stock +Compensation +The +Company applies the intrinsic-value based method of accounting prescribed by +Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued +to Employees", and related interpretations including FASB Interpretation No. +44, "Accounting for Certain Transactions involving Stock Compensation, an +interpretation of APB Opinion No. 25", to account for its fixed-plan stock +options. Under this method, compensation expense is recorded on the date of +grant only if the current market price of the underlying stock exceeded the +exercise price. FASB Statement No. 123, "Accounting for Stock-Based +Compensation" and FASB Statement No. 148, "Accounting for Stock Based +Compensation- Transition and Disclosure, an amendment of FASB Statement No. +123", established accounting and disclosure requirements using a +fair-value-based method of accounting for stock-based employee compensation +plans. As permitted by existing accounting standards, the Company has elected +to continue to apply the intrinsic-value-based method of accounting described +above, and has adopted only the disclosure requirements of Statement 123, as +amended. If the fair-value-based method had been applied to all outstanding +and unvested awards in each period, the impact in 2004 would have been $18,400. +There would have been no impact or reported net income in 2003 or 2002. +(Continued) +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +Compensation +expense for stock options is measured as the excess, if any, of the quoted +market price of the Company stock at the date of the grant over the amount an +optionee must pay to acquire the stock. The Company records compensation +expense for restricted stock awards based on the quoted market price of the +Company' stock at the date of grant and vesting period. +The +pro forma amounts that would have been reported if FASB 123 had been in effect +for all years are based on the fair value of the stock-based awards granted for +each year and recognized over the vesting period. +The +fair value at date of grant for a common stock option granted under Company's +option plan during 2004 was $16.75. The fair value of each option granted +during 2004 was estimated on the date of grant using the Black-Scholes +option-pricing model with the following weighted-average assumptions. +Dividend yield +0% +Expected volatility +39.71% +Risk-free interest rate +4.06% +Expected option life (in years) +7.0 +As of +December 31, 2004, there was approximately $283,000 of total unrecognized, +pre-tax compensation cost related to non-vested stock options. This cost is +expected to be recognized over four years. The Company will adopt the +provisions of FASB Statement No. 123R (revised 2004), Share-Based Payment, in +2005 regarding stock compensation as discussed below. The Company will adopt +the provisions of FASB Statement No. 123R (revised 2004), "Share-Based +Payment", in 2005 regarding stock compensation as discussed below. Upon +adoption of FASB Statement No. 123R, such cost will be recognized directly in +our consolidated statement of income. +Use +of Estimates +Management +of the Company has made a number of estimates and assumptions relating to the +reporting of assets and liabilities and revenues and expenses and the +disclosure of contingent assets and liabilities to prepare these financial +statements in conformity with generally accepted accounting principles. Actual +results could differ from those estimates. Estimates which are particularly +significant to the consolidated financial statements include estimates of oil +and gas reserves and future cash flows from oil and gas properties. +Fair +Value of Financial Instruments +The +carrying values of the Company's receivables, payables and debt obligations are +estimated to be substantially the same as the fair values as of December 31, +2004, 2003 and 2002. +New +Accounting Standards +The +FASB issued FIN 46, "Consolidation of Variable Interest Entities", in January +2003 and amended the interpretation in December 2003. A variable interest +entity (VIE) is an entity in which its voting equity investors lack the +characteristics of having a controlling financial interest or where the +existing capital at risk is insufficient to permit the entity to finance its +activities without receiving additional financial support from other parties. +FIN 46 requires the consolidation of entities which are determined to be VIEs +when the reporting company determines itself to be the primary beneficiary (the +entity that will absorb a majority of the VIE's expected losses, receive a +majority of the VIE's residual returns, or both). The amended interpretation +was effective for the first interim or annual reporting period ending after +March 15, 2004, with the exception of special purpose entities for which the +statement was effective for periods ending after December 15, 2003. We have +completed a review of our partnership investments and have determined that +those entities do not qualify as VIEs. +(Continued) +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +On +December 16, 2004, the Financial Accounting Standards Board (FASB) issued FASB +Statement No. 123R (revised 2004), "Share-Based Payment" which is a revision of +FASB Statement No. 123, "Accounting for Stock-Based Compensation". Statement +123R supercedes APB opinion No. 25, "Accounting for Stock Issued to Employees", +and amends FASB Statement No. 95, "Statement of Cash Flows". Generally, the +approach in Statement 123R is similar to the approach described in Statement +123. However, Statement 123R requires all share-based payments to employees, +including grants of employee stock options, to be recognized in the income +statement based on their fair values. Pro-forma disclosure is no longer an +alternative. The provisions of this statement becomes effective for our third +quarter 2005. Management has not determined the impact that this statement +will have on our consolidated financial statements. +(2) Notes +and Accounts Receivable +Included +in other assets are noncurrent accounts receivable as of December 31, 2004 and +2003, in the amounts of $608,500 and $819,700 less of an allowance for +doubtful accounts of $244,400 and $338,100, respectively. +The +allowance for doubtful current accounts receivable as of December 31, 2004 and +2003 was $164,600 and $149,200, respectively. +(3) Long-Term +Debt +The +Company has a credit facility with J. P. Morgan Chase Bank NA (formerly Bank +One, NA) and BNP Paribas of $100 million subject to and secured by adequate +levels of oil and gas reserves. The current total borrowing base is $80.0 +million of which the Company has activated $60 million of the facility. The +Company is required to pay a commitment fee of 1/4 percent on the unused +portion of the activated credit facility. Interest accrues at prime, with LIBOR +(London Interbank Market Rate) alternatives available at the discretion of the +Company. No principal payments are required until the credit agreement expires +on July 3, 2008. +As of +December 31, 2004 and 2003 the outstanding balance was $21,000,000 and +$53,000,000, respectively. Any amounts outstanding under the credit facility +are secured by substantially all properties of the Company. The credit +agreement requires, among other things, the existence of satisfactory levels of +natural gas reserves, maintenance of certain working capital and tangible net +worth ratios along with a restriction on the payment of dividends. As of +December 31, 2004 and 2003 the Company was in compliance with all financial +covenants in the credit agreement. At December 31, 2004, the outstanding balance +was subject to a prime rate of 5.25%. +(4) Income +Taxes +The +Company's provision for income taxes consisted of the following: +2004 +2003 +2002 +Current: +Federal +$8,426,400 +2,401,000 +604,200 +State +1,672,500 +834,100 +206,800 +Total current +income taxes +10,098,900 +3,235,100 +811,000 +Deferred: +Federal +8,900,300 +7,802,800 +2,461,200 +State +1,543,300 +1,067,900 +525,200 +Total deferred +income taxes +10,443,600 +8,870,700 +2,986,400 +Total income taxes +$20,542,500 +12,105,800 +3,797,400 +Income tax expense differed from the amounts computed +by applying the U.S. federal income tax rate of 35 percent in 2004 and 2003 +and 34 percent in 2002 to pretax income as a result of the following: +(Continued) +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +2004 +2003 +2002 +Computed +"expected" tax +$19,111,100 +12,223,200 +4,447,900 +State income tax +2,129,500 +1,362,000 +483,100 +Percentage +depletion +(794,100) +(935,000) +(680,000) +Nonconventional +source fuel credit +- +(186,600) +(491,500) +Officers life +insurance +- +(360,000) +- +Surtax exemption +- +(100,000) +- +Change in federal +rate bracket +- +254,700 +- +Other +96,000 +(152,500 ) +37,900 +$ 20,542,500 +12,105,800 +3,797,400 +The tax effects of +temporary differences that give rise to significant portions of the deferred +tax assets and deferred tax liabilities at December 31, 2004 and 2003 are +presented below: +2004 +2003 +Deferred tax +assets: +Allowance +for doubtful accounts +$ 159,100 +189,500 +Drilling +notes +57,200 +73,500 +Alternative +minimum tax credit carryforwards (Section 29) +- +437,400 +Future +abandonment +725,500 +614,900 +Deferred +compensation +692,100 +1,784,200 +Asset Retirement +Obligations +121,700 +121,700 +Accumulated +Other Comprehensive Income +1,531,200 +750,500 +Other +21,800 +27,700 +Total +gross deferred tax assets +3,308,600 +3,999,400 +Less +valuation allowance +- +- +Deferred +tax assets +3,308,600 +3,999,400 +Less +current deferred tax assets +(included +in other current assets) +(337,300 ) +(1,957,400 ) +Net +non-current deferred tax assets +2,971,300 +2,042,000 +Deferred tax +liabilities: +Properties +and equipment, principally due to differences in +depreciation +and amortization +(32,814,500 ) +(23,842,200 ) +Total +gross deferred tax liabilities +(32,814,500 ) +(23,842,200 ) +Net +non-current deferred tax liability +$ (29,843,200 ) +(21,800,200 ) +Accumulated other +comprehensive loss is net of tax of $1,531,200, $750,500 and $1,092,200 as of +December 31, 2004, 2003 and 2002, respectively. +In assessing the +realizability of deferred tax assets, management considers whether it is more +likely than not that some portion or all of the deferred tax assets will not be +realized. The ultimate realization of deferred tax assets is dependent upon the +generation of future taxable income during the periods in which those temporary +differences become deductible. Based upon the level of historical taxable +income and projections for future taxable income over the periods in which the +deferred tax assets are deductible, management believes it is more likely than +not that the Company will realize the benefits of these deductible differences.. +The amount of the deferred tax asset considered realizable, however, could be +reduced in the near term if estimates of future taxable income during the +carryforward period are reduced. +(Continued) +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +Employee stock +options exercised during the year 2004 resulted in an income tax benefit of $7,394,800 +that is reflected in Stockholders' Equity and as a reduction of current tax +payable. +The deferred tax +asset related to AOCI increased in 2004 by $780,700 and decreased in 2003 by +$341,700. +(5) Common +Stock +Stock-Based +Compensation Plans +As of December 31, +2004, the Company has several stock-based compensation plans for certain +employees and officers. These plans are described below: +The Company +maintains a long-term equity compensation plan for officers and certain key +employees of the company. Under the plan, approved by the shareholders in June +2004, awards may be issued in the form of stock options, stock appreciation +rights, restricted stock, or performance shares. A total of 750,000 shares of +common stock have been reserved for issuance. During 2004, 23,380 shares were +granted with restriction periods of four years at the market price on the date +of issuance as deferred compensation and the related amount is being amortized +to operations over the respective vesting period. Compensation expense for the +year ended December 31, 2004 related to these shares of restricted stock was +$21,100. +Options amounting to +16,880 shares were granted during 2004 to certain employees and directors under +the Company's Stock Option Plan. These options were granted with an exercise +price equal to the market value of the Company's common stock as of the date of +grant and vest over a four year period. The outstanding options expire in 2014. +The following table +summarized the activity of the Company's option plans: +Number +of Shares +Average +Exercise +Price +Range of +Exercise +Prices +Outstanding +December 31, 2001 +1,230,000 +$4.29 +1.125 - 6.25 +Exercised +(70,000 ) +$1.125 +1.125 - 1.125 +Outstanding +December 31, 2002 +1,160,000 +$4.48 +1.125 - 6.25 +Granted +- +- +- +Exercised +- +- +- +Outstanding +December 31, 2003 +1,160,000 +$4.48 +1.125 - 6.25 +Granted +16,880 +$37.15 +37.15 +Exercised +(1,100,000) +$4.48 +1.125-6.25 +Outstanding +December 31, 2004 +76,880 +$11.64 +3.875-37.15 +(Continued) +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +Options +outstanding under the Company's plans as of December 31, 2004: +Range of Exercise Price +Options +Outstanding +Remaining +Life +Options +Exercisable +Weighted-Average +Exercise Price +$3.75 - $6.25 +60,000 +3.9 years +60,000 +$5.40 +$37.15 +16,880 +10 years +- +$37.15 +Total +76,880 +60,000 +Common +Stock Repurchase +On +March 13, 2003 the Company publicly announced the authorization by its Board of +Directors to repurchase up to 5% of the Company's common stock (785,000 shares) +at fair market value at the date of purchase. Under the program, the Board had +discretion as to the dates of purchase and amounts of stock to be purchased and +whether or not to make purchases. From inception of the program until December +31, 2004, the Company has repurchased 109,200 shares at an average price of +$6.86. This program expired on December 31, 2004. The following activity has +occurred since inception of the plan on March 13, 2003 until December 31, 2004. +Month of Purchase +March, 2003 +April, 2003 +September, 2003 +Average Price paid per share +$6.08 +$6.48 +$11.15 +Broker/Dealer +McDonald Investments +McDonald Investments +McDonald Investments +Number of Shares Purchased +46,500 +49,900 +12,800 +Remaining Number of Shares +to Purchase +738,500 +688,600 +675,800 +In +March 2004, the Compensation Committee of the Board of Directors approved a +repurchase of 48,650 shares of common stock from one of the Company's +officers. The repurchase price of the common stock was the closing price on +the date of the repurchase of $26.61 per share and totaled $1,294,600 which +approximated the tax savings to be realized by the Company as a result of the +exercise of said officer's non-qualified stock options in 2004. The Company +also repurchased 1,703 shares from an employee upon retirement from the Company +in June, 2004. Such treasury stock was subsequently cancelled. +At a +meeting held on Friday, March 18, 2005 the Board of Directors of Petroleum +Development Corporation approved a stock repurchase plan to allow the Company +to repurchase up to 2% of the Company's common stock in 2005. The Company +intends at a minimum to purchase adequate shares to insure no dilution from +employee stock compensation plans and may also make open market purchases from +time to time. +Stock +Repurchase Agreement +The +Company has stock repurchase agreements with four executive officers of the +Company. The agreements require the Company to maintain life insurance on each +executive in the amount of $1,000,000. The agreements provide that the Company +shall utilize the proceeds from such insurance to purchase from such +executives' estates or heirs, at their option, shares of the Company's stock. +The purchase price for the outstanding common stock is to be based upon the +average closing asked price for the Company's stock as quoted by NASDAQ on the date +of purchase. The Company is not required to purchase any shares in excess of +the amount provided for by such insurance. During the fourth quarter of 2003, +the Company received $1,000,000 in life insurance proceeds which was recorded +as other income from the death of the Company's Chief Financial Officer who had +a stock repurchase agreement. In May 2004, the Company repurchased 50,487 +shares of common stock from the estate of the Company's former officer in +accordance with the terms of this agreement. The repurchase price of the stock +was $27.73 per share (the 90-day average prior to the repurchase per +contract). The repurchase totaled $1,400,000 of which $1,000,000 was funded by +the life insurance proceeds. +(Continued) +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +(6) Employee +Benefit Plans +The +Company sponsors a qualified deferred compensation plan that enables eligible +employees to contribute a portion of their compensation through payroll +deductions in accordance with specific guidelines. The Company matches a +percentage of the employees' contributions up to certain limits. Expenses +related to this plan amounted to $382,700, $305,500 and $288,000 for 2004, 2003 +and 2002, respectively. +The +Company has a profit sharing plan (the Plan) covering full-time employees. The +Company contributed $300,000, $250,000 and $200,000 to the plan in cash during +2004, 2003 and 2002, respectively. +During +2003 and 2002 the Company expensed $90,000 each year under a deferred +compensation arrangement with certain executive officers of the Company. These +amounts were paid during 2003 to such executive officers. +The +Company has a deferred compensation arrangement covering certain executive +officers of the Company as a supplemental retirement benefit. During 2004, 2003 +and 2002 the Company expensed $171,900, $181,900 and $171,600, respectively, +and has recorded a related liability in the amount $1,000,200 and $868,300 as +of December 31, 2004 and 2003, respectively. The Company began paying the +retirement benefit during 2004 to the estate of one of the Company's former +officers. The Company paid $40,000 during 2004. +The +Company maintains a non-qualified deferred compensation plan created for +non-employee directors of the Company. The amount of compensation deferred by +each Participant is based on Participant elections. +(7) Earnings Per Share +2004 +2003 +2002 +Basic earnings per common share: +Net income before cumulative effect of change in +accounting principle +$34,060,600 +22,817,700 +9,284,800 +Cumulative effect of accounting change, net of tax +(198,600) +Net income +34,060,600 +22,619,100 +9,284,800 +Weighted average common shares outstanding +16,240,604 +15,659,591 +15,866,363 +Basic earnings per common share +$ 2.10 +$ 1.45 +$ 0.59 +Diluted earnings per common and common +equivalent share: +Net income before cumulative effect of change in +Accounting principle +34,060,600 +22,817,700 +9,284,800 +Cumulative effect of accounting change, net of tax +- +(198,600) +- +Net income applicable to common stock +34,060,600 +22,619,100 +9,284,800 +Weighted average common shares outstanding +16,240,604 +15,659,591 +15,866,363 +Potentially dilutive securities: +Stock options +406,570 +638,202 +277,051 +Weighted average common and common equivalent +shares outstanding +16,647,174 +16,297,793 +16,143,414 +Diluted earnings per common share +$ 2.05 +$ 1.39 +$0.58 +(8) Transactions with Affiliates +Funds +held for future distribution on the consolidated balance sheet of $12,911,800 +and $8,410,900 primarily represents amounts owed to affiliated partnerships as +of December 31, 2004 and 2003, respectively. +(Continued) +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +The +Company provided oil and gas well drilling services and well operations +services to affiliated partnerships. Substantially all of the Company's oil and +gas well drilling operations, well operations and pipeline income and other +income (except for $1.0 million of life insurance proceeds in 2003 discussed in +Note 5) was for such partnerships. Related services of tax return preparation +and other services relating to the operation of the partnerships are recorded +in other income. Amounts due from the affiliated partnerships as of December +31, 2004 and 2003 were $68,100 and $929,600, and are included in notes and +accounts receivable. +The +Company through its wholly-owned subsidiary, PDC Securities Incorporated, acts +as Dealer-Manager of the Public Drilling Partnerships. PDC Securities +Incorporated receives the applicable commissions and marketing allowances from +the Escrow Agent of the Drilling Program and distributes them to the Soliciting +Broker/Dealers who sell the programs. The commissions and marketing allowances +received by PDC Securities are included in other income net of the commissions +distributed to the soliciting broker/dealers in the amounts of $9,747,600, +$7,994,300 and $5,792,300 for the years ended December 31, 2004, 2003 and 2002, +respectively. The net commissions and marketing allowance amounts included in +other income were less than $1,000 for each of the years ending December 31, +2004, 2003 and 2002. +During +2004, 2003 and 2002, the Company paid $22,500, $30,000 and $51,800, +respectively, to the Corporate Secretary's law firm for various legal services. +(9) Commitments and Contingencies +The +nature of the independent oil and gas industry involves a dependence on outside +investor drilling capital and involves a concentration of gas sales to a few +customers. The Company sells natural gas to various public utilities and +industrial customers. No customer accounted for 10% or more of the Company's +total revenues in 2004. One customer accounted for 10.3% and 10.8% of total +revenues in 2003 and 2002, respectively. +The +Company would be exposed to natural gas price fluctuations on underlying purchase +and sale contracts should the counterparties to the Company's hedging +instruments or the counterparties to the Company's gas marketing contracts not +perform. Such nonperformance is not anticipated. There were no counterparty +default losses in 2004, 2003 or 2002. +Substantially +all of the Company's drilling programs contain a repurchase provision where +Investing Partners may request the Company to purchase their partnership units +at any time beginning with the third anniversary of the first cash distribution. +The provision provides that the Company is obligated to purchase an aggregate +of 10% of the initial subscriptions per calendar year (at a minimum price of +four times the most recent 12 months' cash distributions), only if such units +are requested by the investors, subject to the Company's financial ability to +do so. The maximum annual 10% repurchase obligation, if requested by the +investors, is currently approximately $6.6 million. The Company has adequate +liquidity to meet this obligation. During 2004, the Company paid $408,260 under +this provision for the repurchase of partnership units. +The Company's drilling programs formed +since 1996 contain a performance standard which states that if certain +performance levels are not met, the Company must remit a payment equal to +one-half of its share of revenue from such partnership to the investing +partners. During 2004, 2003, and 2002 the Company paid partnerships a total of +$597,300, $385,400 and $198,500, respectively in accordance with the provision. +During +the fourth quarter of 2003, the Company recorded a liability in accordance with +the death benefit of the employment contract of the Company's Chief Financial +Officer in the amount of $852,700. +As +Managing General Partner of 10 private partnerships and 62 public partnerships +the Company has liability for any potential casualty losses in excess of the +partnership assets and insurance. The Company's management believes its and its +subcontractors casualty insurance coverage is adequate to meet this potential +liability. +In +order to secure the services for drilling rigs, the Company makes commitments +to the drilling contractor which call for penalties for a specified amount of +time if the Company ceases to use such drilling rigs, an event that is not anticipated +to occur. As of December 31, 2004, the Company has an outstanding commitment +for $1,604,250. +(Continued) +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +The +Company drilled one exploratory well in 2004 and plans additional exploratory +wells in 2005. As of the date of this report, the exploratory well had been +completed and testing was underway but the well had not been classified as +successful or dry. Testing of the well was suspended in January due to lease +restrictions on the Federal lease. We expect to resume testing in the second +quarter of 2005. If the well is determined to be a dry hole, its costs will be +expensed in the period when the determination is made as required by the +successful efforts method of accounting. The cost of the well as of December +31, 2004 is $4,169,903. +From +time to time the Company is a party to various legal proceedings in the +ordinary course of business. The Company is not currently a party to any +litigation that it believes would have a materially adverse affect on the +Company's business, financial condition, results of operations, or liquidity. +(10) Lease +Obligations +The +Company has entered into certain operating leases on behalf of itself and its +Partnerships principally for the leasing of natural gas compressors on its Michigan operating facilities and office printing and copying equipment. The future minimum +lease payments under these non-cancelable operating leases as of December 31, +2004 are as follows: +Year +Lease Amount +2005 +$307,900 +2006 +209,400 +2007 +153,900 +2008 +127,200 +2009 +45,300 +Thereafter +52,000 +$895,700 +The Company's share +of this lease expense for operating leases for the years ended December 31, +2004, 2003 and 2002 was $310,000, $574,700 and $660,700, respectively. +(11) Supplemental Disclosure of Cash Flows +The +Company paid $1,049,200, $1,274,003 and $1,290,400 for interest in 2004, 2003 +and 2002, respectively. The Company paid income taxes in 2004, 2003 and 2002 +in the amounts of $5,027,800, $3,649,600 and $175,000, respectively. +During 2004 options +were exercised by exchanging mature shares with a fair value of $1,408,300. All +these mature shares were subsequently cancelled. +(12) Purchases +of Oil and Gas Properties +During +the second quarter of 2003, the Company purchased 166 wells in the Denver Julesburg Basin in northeastern Colorado from Williams Production RMT Company for $28 +million. The Company estimates the acquisition included approximately 22.6 +billion cubic feet (Bcf) of proved developed producing (PDP) and 3.4 Bcf of +proved developed non-producing reserves (PDNP), all of which is natural gas. +The Company received approval for increased density well spacing in 2004. The +Company drilled twenty new Niobrara wells on the property in 2004. The Company +estimates that there are approximately 100 remaining increased density well +locations, approximately 60 of which the Company plans to develop in 2005. +During +the fourth quarter of 2003, the Company purchased from one of its unaffiliated +joint venture partners in the Denver-Julesburg Basin in Weld County, Colorado +approximately 3.1 billion cubic feet equivalent (Bcfe) of proved developed +producing reserves from interests in 20.6 net wells (230 gross) and 1.8 Bcfe of +proved developed non-producing reserves from interests in 17 net wells (183 +gross). The purchase price was $5.2 million which also included over 30 +additional drilling locations. +(Continued) +PETROLEUM +DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated +Financial Statements +During +the fourth quarter of 2003, the Company purchased from an unaffiliated party 97 +gross wells (73 net) in the Denver-Julesburg Basin located in northeast Colorado and northwestern Kansas for $6.0 million. This purchase added approximately 4.5 +billion cubic feet equivalent (Bcfe) of proved developed producing and proved +developed non-producing reserves to the Company's oil and gas reserves along +with 100,000 acres of oil and gas leases. +(13) Derivative +Financial Instruments +The futures and option +contracts hedge forecasted natural gas purchases and sales, generally +forecasted to occur within a three year period. The Company does not hold or +issue derivatives for trading or speculative purposes. In addition, an interest +rate swap agreement was used to reduce the potential impact of increases in +interest rates on variable rate long-term debt. +The Company utilizes +commodity-based derivative instruments as hedges to manage a portion of its +exposure to price risk from its natural gas sales and marketing activities. +These instruments consist of NYMEX-traded natural gas futures contracts and +option contracts for Appalachian and Michigan production and CIG-based +contracts traded by JP Morgan Chase Bank, NA for Colorado production. These +hedging arrangements have the effect of locking in for specified periods (at +predetermined prices or ranges of prices) the prices the Company will receive +for the volume to which the hedge relates and, in the case of RNG, the cost of +gas supplies purchased for marketing activities. As a result, while these +hedging arrangements are structured to reduce the Company's exposure to changes +in price associated with the hedged commodity, they also limit the benefit the +Company might otherwise have received from price increases associated with the +hedged commodity. The Company's policy prohibits the use of natural gas future +and option contracts for speculative purposes. +The following +tables summarize the open futures and options contracts for Riley Natural Gas +and +PDC as of +December 31, 2004 and 2003. +Riley Natural Gas +Open Futures Contracts +Commodity +Type +Quantity +Gas-Mmbtu +Oil-Barrels +Weighted +Average +Price +Total +Contract +Amount +Fair +Market +Value +Total +Contracts as of December 31, 2004 +Natural Gas +Sale +3,260,000 +$5.60 +$18,249,250 +($1,982,964) +Natural Gas +Purchase +1,130,000 +$6.77 +$7,644,540 +($486,490) +Natural Gas +Floor +530,000 +$5.30 +$134,242 +Natural Gas +Ceiling +265,000 +$7.00 +($85,541) +Contracts maturing +in 12 months following December 31, 2004 +Natural Gas +Sale +2,230,000 +$5.84 +$13,014,810 +($841,102) +Natural Gas +Purchase +860,000 +$6.94 +$5,965,490 +($591,340) +Natural Gas +Floor +530,000 +$5.30 +$134,242 +Natural Gas +Ceiling +265,000 +$7.00 +($85,541) +Prior Year +Total Contracts as of December 31, 2003 +Natural Gas +Sale +2,660,000 +$4.58 +$12,174,130 +($1,810,500) +Natural Gas +Purchase +820,000 +$5.17 +$4,243,420 +$270,200 +The maximum +term over which RNG is hedging exposure to the variability of cash flows for +commodity +price risk is +27 months. +(Continued) +PETROLEUM +DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to +Consolidated Financial Statements +Petroleum Development Corporation +Open Futures Contracts +Commodity +Type +Quantity +Weighted +Total +Fair +Gas-Mmbtu +Average +Contract +Market +Oil-Barrels +Price +Amount +Value +Total +Contracts as of December 31, 2004 +Natural Gas +Purchase +46,776 +$6.63 +$310,339 +($17,806) +Natural Gas +Floor +3,562,020 +$4.56 +$337,842 +Natural Gas +Ceiling +1,556,010 +$5.39 +($1,526,868) +Crude Oil +Floor +166,536 +$32.30 +$141,880 +Crude Oil +Ceiling +83,268 +$40.00 +($450,405) +Contracts +maturing in 12 months following December 31, 2004 +Natural Gas +Sale +Natural Gas +Purchase +46,776 +$6.63 +$310,339 +($17,806) +Natural Gas +Floor +3,562,020 +$4.56 +$337,842 +Natural Gas +Ceiling +1,556,010 +$5.39 +($1,526,868) +Crude Oil +Floor +166,536 +$32.30 +$141,880 +Crude Oil +Ceiling +83,268 +$40.00 +($450,405) +Prior Year Total +Contracts as of December 31, 2003 +Natural Gas +Sale +53,300 +$5.40 +$288,000 +($40,000) +Natural Gas +Purchase +45,700 +$4.77 +$218,100 +$30,400 +Natural Gas +Floor +2,597,800 +$4.29 +$185,300 +Natural Gas +Ceiling +691,200 +$5.23 +($127,800) +The maximum term over which PDC is +hedging exposure to the variability of cash flows for commodity price risk is +12 months +The Company is required to +maintain margin deposits with brokers for outstanding futures contracts. As of +December 31, 2004 and 2003, cash in the amount of $664,900 and $1,866,400 was +on deposit. +An interest rate swap +agreement was used to reduce the potential impact of increases in interest +rates on variable rate long-term debt. Such swap agreement expired in October +2004. At December 31, 2003, the Company was a party to an interest rate swap +agreement which expired on October 11, 2004. The agreement required the +Company, on a quarterly basis, to make a fixed-rate interest payment of 6.89% +plus its current LIBOR rate margin (+1.50% At December 31, 2003) on a +$10,000,000 amount related to its outstanding line of credit. +The fair value of the +interest rate swap agreement was $(436,800), $(266,900) net of tax at December +31, 2003. Current market pricing models were used to estimate fair value. +By using derivative +financial instruments to hedge exposures to changes in interest rates and +commodity prices, the Company exposes itself to credit risk and market risk. +Credit risk is the failure of the counterparty to perform under the terms of +the derivative contract. When the fair value of a derivative contract is +positive, the counterparty owes the Company, which creates repayment risk. The +Company minimizes the credit or repayment risk in derivative instruments by +entering into transactions with high-quality counterparties. +Changes in the fair value +of natural gas futures contracts designated as hedging instruments and that +effectively offset the variability of cash flows associated with anticipated +sales of natural gas are reported in accumulated other comprehensive income +(AOCI). These amounts subsequently are reclassified into gas purchases for RNG +and gas sales for PDC when the related gas is sold and affects earnings. +Changes in the fair value of the interest rate swap agreement were reclassified +into interest expense. +PETROLEUM +DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to +Consolidated Financial Statements +(14) Costs Incurred in Oil and Gas Property +Acquisition, Exploration and Development Activities +Costs +incurred by the Company in oil and gas property acquisition, exploration and +development are presented below: +Years Ended December 31, +2004 +2003 +2002 +Property acquisition cost: +Proved undeveloped properties +$ 4,583,000 +6,167,800 +1,892,700 +Producing properties +720,000 +33,946,600 +240,000 +Development costs +36,870,400 +30,630,100 +16,429,400 +$ 42,173,400 +70,744,500 +18,562,100 +The +proved reserves attributable to the development costs in the above table were +40,716,000 Mcf and 358,000 bbls for 2004, 27,719,000 Mcf and 517,000 bbls for +2003 and 19,607,000 Mcf and 130,000 bbls for 2002 (amounts unaudited). Of the +above development costs incurred for the years ended December 31, 2004, 2003 +and 2002 the amounts of $1,819,619, $4,289,600 and $2,699,500, respectively, +were incurred to develop proved undeveloped properties from the prior year end. +Property +acquisition costs include costs incurred to purchase, lease or otherwise +acquire a property. Development costs include costs incurred to gain access to +and prepare development well locations for drilling, to drill and equip +development wells, recompletions and to provide facilities to extract, treat, +gather and store oil and gas. +(15) Oil +and Gas Capitalized Costs +Aggregate +capitalized costs for the Company related to oil and gas exploration and +production activities with applicable accumulated depreciation, depletion and +amortization are presented below: +December 31, +2004 +2003 +Proved properties: +Tangible well equipment +$157,787,800 +$133,356,900 +Intangible drilling costs +123,171,200 +110,087,300 +Undeveloped properties +9,864,300 +7,576,900 +Capitalized asset retirement cost +613,400 +537,800 +291,436,700 +251,558,900 +Less accumulated depreciation, +depletion and amortization +80,762,100 +64,205,100 +$ 210,674,600 +$ 187,353,800 +(16) Results +of Operations for Oil and Gas Producing Activities +The +results of operations for oil and gas producing activities (excluding +marketing) are presented below: +Years +Ended December +31, +2004 +2003 +2002 +Revenue: +Oil and gas sales +$67,947,700 +47,021,600 +22,857,100 +Expenses: +Production costs +14,974,000 +10,212,500 +6,407,900 +Depreciation, depletion and +amortization +16,482,600 +12,997,600 +11,149,000 +31,456,600 +23,210,100 +17,556,900 +PETROLEUM +DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to +Consolidated Financial Statements +Results of operations for oil and gas +producing activities before provision +for income taxes +36,491,100 +23,811,500 +5,300,200 +Provision for income taxes +13,728,000 +8,262,600 +1,538,400 +Results of operations for oil and gas +producing activities (excluding corporate +overhead and interest costs) +$ 22,763,100 +15,548,900 +3,761,800 +Production +costs include those costs incurred to operate and maintain productive wells and +related equipment, including such costs as labor, repairs, maintenance, +materials, supplies, fuel consumed, insurance and other production taxes. In +addition, production costs include administrative expenses and depreciation +applicable to support equipment associated with these activities. +Depreciation, +depletion and amortization expense includes those costs associated with +capitalized acquisition, exploration and development costs, but does not +include the depreciation applicable to support equipment. +The +provision for income taxes is computed using the Company's effective tax rate. +(17) Net +Proved Oil and Gas Reserves (Unaudited) +The +proved reserves of oil and gas of the Company have been estimated by an +independent petroleum engineer, Wright & Company, Inc. at December 31, +2004, 2003 and 2002. These reserves have been prepared in compliance with the +Securities and Exchange Commission rules based on year end prices. An analysis +of the change in estimated quantities of oil and gas reserves, all of which are +located within the United States, is shown below: +Oil +(BBLS) +2004 +2003 +2002 +Proved developed and undeveloped reserves: +Beginning of year +3,029,000 +2,073,000 +2,126,000 +Revisions of previous estimates +305,000 +533,000 +124,000 +Beginning of year as revised +3,334,000 +2,606,000 +2,250,000 +New discoveries and extensions: +Rocky Mountain Region +358,000 +517,000 +130,000 +Dispositions to partnerships +(12,000) +(112,000) +(80,000) +Acquisitions: +Rocky Mountain Region +17,000 +307,000 +- +Production +(381,000) +(289,000 ) +(227,000 ) +End of year +3,316,000 +3,029,000 +2,073,000 +Proved developed reserves: +Beginning of year +2,889,000 +1,849,000 +1,801,000 +End of year +3,190,000 +2,889,000 +1,849,000 +(Continued) +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +Gas +(MCF) +2004 +2003 +2002 +Proved developed and undeveloped +reserves: +Beginning of year +180,998,000 +128,851,000 +118,608,000 +Revisions of previous estimates +(10,635,000) +4,394,000 +1,469,000 +Beginning of year as revised +170,363,000 +133,245,000 +120,077,000 +New discoveries and extensions: +Rocky Mountain Region +40,716,000 +27,719,000 +19,607,000 +Dispositions to partnerships +(4,240,000) +(4,410,000) +(4,792,000) +Acquisitions: +Michigan Basin +96,000 +265,000 +4,000 +Rocky Mountain Region +242,000 +32,169,000 +75,000 +Appalachian Basin +744,000 +722,000 +342,000 +Production +(10,372,000 ) +(8,712,000 ) +(6,462,000 ) +End of year +197,549,000 +180,998,000 +128,851,000 +Proved developed reserves: +Beginning of year +134,936,000 +94,847,000 +88,477,000 +End of year +146,152,000 +134,936,000 +94,847,000 +(18) Standardized +Measure of Discounted Future Net Cash Flows and Changes Therein Relating to +Proved Oil and Gas Reserves (Unaudited) +Summarized +in the following table is information for the Company with respect to the +standardized measure of discounted future net cash flows relating to proved oil +and gas reserves. Future cash inflows are computed by applying year-end prices +of oil and gas relating to the Company's proved reserves to the year-end +quantities of those reserves. Future production, development, site restoration +and abandonment costs are derived based on current costs assuming continuation +of existing economic conditions. Future income tax expenses are computed by +applying the statutory rate in effect at the end of each year to the future +pretax net cash flows, less the tax basis of the properties and gives effect to +permanent differences, tax credits and allowances related to the properties. +As of December +31, +2004 +2003 +2002 +Future estimated revenues +$1,298,394,000 +$1,088,415,000 +$548,949,000 +Future estimated production costs +(319,065,000) +(250,735,000) +(143,878,000) +Future estimated development costs +(95,498,000) +(65,275,000) +(50,971,000) +Future estimated income tax expense +(332,497,000 ) +(265,707,000 ) +(105,876,000 ) +Future net cash flows +551,334,000 +506,698,000 +248,224,000 +10% annual discount for estimated +timing of cash flows +(317,099,000 ) +(289,408,000 ) +( 149,755,000 ) +Standardized measure of discounted future +estimated net cash flows +$ 234,235,000 +$217,290,000 +$98,469,000 +(Continued) +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +The +following table summarizes the principal sources of change in the standardized +measure of discounted future estimated net cash flows: +Years Ended December +31, +2004 +2003 +2002 +Sales of oil and gas production, net of +production costs +$(52,974,000) +$(36,810,000) +$(16,449,000) +Net changes in prices and production costs +36,656,000 +162,422,000 +143,574,000 +Extensions, discoveries and improved recovery, +less related cost +135,816,000 +114,533,000 +39,347,000 +Dispositions to partnerships +(16,782,000) +(12,936,000) +(6,940,000) +Acquisitions +6,451,000 +139,078,000 +1,167,000 +Development costs incurred during the period +36,870,000 +30,630,000 +16,429,000 +Revisions of previous quantity estimates +(34,611,000) +21,388,000 +3,318,000 +Net changes in estimated income taxes +(66,790,000) +(159,831,000) +(55,516,000) +Accretion of discount +(27,691,000 ) +(139,653,000 ) +(72,900,000 ) +$16,945,000 +$118,821,000 +$ 52,030,000 +It is +necessary to emphasize that the data presented should not be viewed as +representing the expected cash flow from, or current value of, existing proved +reserves since the computations are based on a large number of estimates and +arbitrary assumptions. Reserve quantities cannot be measured with precision +and their estimation requires many judgmental determinations and frequent +revisions. The required projection of production and related expenditures over +time requires further estimates with respect to pipeline availability, rates of +demand and governmental control. Actual future prices and costs are likely to +be substantially different from the current prices and costs utilized in the +computation of reported amounts. Any analysis or evaluation of the reported +amounts should give specific recognition to the computational methods utilized +and the limitations inherent therein. +(19) Business Segments (Thousands) +PDC's +operating activities can be divided into four major segments: drilling and +development, natural gas marketing, oil and gas sales, and well operations. +The Company drills natural gas wells for Company-sponsored drilling +partnerships and retains an interest in each well. A wholly-owned subsidiary, +Riley Natural Gas, engages in the marketing of natural gas to commercial and +industrial end-users. The Company owns an interest in approximately 2,700 +wells from which it derives oil and gas working interests. The Company charges +Company-sponsored partnerships and other third parties competitive industry +rates for well operations and gas gathering. All material inter-company +accounts and transactions between segments have been eliminated. Segment +information for the years ended December 31, 2004, 2003 and 2002 is as follows: +2004 +2003 +2002 +REVENUES +Drilling +and Development +$119,211 +71,841 +57,149 +Natural +Gas Marketing +93,231 +73,141 +46,366 +Oil +and Gas Sales +67,948 +47,022 +22,857 +Well +Operations +8,384 +7,348 +6,116 +Unallocated +amounts (1) +1,946 +3,499 +2,854 +Total +$ 290,720 +202,851 +135,342 +(Continued) +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +SEGMENT +INCOME BEFORE INCOME TAXES +Drilling +and Development +$16,380 +10,564 +7,983 +Natural +Gas Marketing +1,324 +689 +174 +Oil +and Gas Sales +36,491 +23,812 +5,300 +Well +Operations +4,402 +3,059 +2,788 +Unallocated +amounts (2) +General +and Administrative expenses +(4,506) +(4,974) +(4,392) +Interest +expense +(874) +(1,329) +(1,340) +Other +(1) +1,386 +3,103 +2,569 +Total +$ 54,603 +34,924 +13,082 +SEGMENT +ASSETS +Drilling +and Development +$64,348 +62,546 +31,279 +Natural +Gas Marketing +28,689 +17,006 +16,641 +Oil +and Gas Sales +221,516 +204,849 +145,591 +Well +Operations +16,518 +11,602 +10,706 +Unallocated +amounts +Cash +112 +800 +1,736 +Other +10,210 +9,919 +6,299 +Total +$ 341,393 +306,722 +212,252 +EXPENDITURES +FOR SEGMENT +LONG-LIVED +ASSETS +Drilling +and Development +$ 4,583 +6,168 +1,800 +Natural +Gas Marketing +6 +- +4 +Oil +and Gas Sales +37,590 +63,588 +16,670 +Well +Operations +1,911 +2,944 +1,221 +Unallocated +amounts +1,302 +342 +82 +Total +$ 45,392 +73,042 +19,777 +(1) Includes +interest on investments and partnership management fees in 2004, 2003 and +2002 and gain on sale +of +assets in 2004, 2003 and 2002 which are not allocated in assessing segment +performance. +(2) Items +which are not allocated in assessing segment performance. +(20) +Subsequent Event +In +January 2005, the Company sold a portion of one of its undeveloped Garfield County, Colorado leases to another operator. The gain on such sale to be recorded +in the first quarter 2005 was approximately $5.2 million, net of a $1.0 million +liability recorded for a future commitment. The interest sold consisted of +half the Company's leasehold interest on a "checkerboard" pattern. The Company +will retain the other half of the lease. The terms of the agreement require +the purchaser to drill a number of wells over a period of time on the acquired +acreage. If the drilling requirements are not met part or all of the lease +will revert to the Company. +(Continued) +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +Notes to Consolidated Financial Statements +(21) Quarterly Financial Data (Unaudited ) +Summarized quarterly financial data for the years ended +December 31, 2004 and 2003, are as follows: +2004 +Quarter +Year +First +Second +Third +Fourth +Revenues +$71,048,500 +$73,923,800 +$73,157,400 +$72,590,100 +$290,719,800 +Cost +of operations +56,624,200 +59,315,500 +58,357,200 +56,439,900 +230,736,800 +Gross +profit +14,424,300 +14,608,300 +14,800,200 +16,150,200 +59,983,000 +General +and administrative expenses +994,200 +900,900 +926,300 +1,684,200 +4,505,600 +Interest +expense +243,500 +255,000 +252,600 +123,200 +874,300 +Income +before income taxes +13,186,600 +13,452,400 +13,621,300 +14,342,800 +54,603,100 +Income +taxes +4,747,200 +4,839,300 +4,929,700 +6,026,300 (1) +20,542,500 +Net income +$ 8,439,400 +$ 8,613,100 +$ 8,691,600 +$ 8,316,500 +$34,060,600 +Basic earnings per +share +$ .53 +$ .53 +$ .53 +$.50 +$2.10 +Diluted +earnings per share +$ .52 +$ .52 +$ .52 +$.49 +$2.05 +(1) Includes approximately $630,000 of adjustments to the +tax provision of the prior three quarters. +2003 +Quarter +Year +First +Second +Third +Fourth +Revenues +$53,994,400 +$42,192,500 +$47,207,900 +$59,456,200 +$202,851,000 +Cost +of operations +45,125,800 +33,836,200 +37,648,600 +45,013,400 +161,624,000 +Gross +profit +8,868,600 +8,356,300 +9,559,300 +14,442,800 +41,227,000 +General +and administrative expenses +1,177,700 +1,186,600 +1,377,300 +1,232,800 +4,974,400 +Interest +expense +236,200 +259,800 +415,000 +418,100 +1,329,100 +Income +before income taxes +7,454,700 +6,909,900 +7,767,000 +12,791,900 +34,923,500 +Income +taxes +2,460,000 +2,280,300 +2,563,100 +4,802,400 +12,105,800 +Net income before +cumulative +effect +of change of change in +accounting +principle +4,994,700 +4,629,600 +5,203,900 +7,989,500 +22,817,700 +Cumulative effect +of change in +Accounting +principle (net of taxes) +(198,600) +- +- +- +(198,600) +Net income +$ 4,796,100 +$ 4,629,600 +$ 5,203,900 +$ 7,989,500 +$ 22,619,100 +Basic +earnings per share +before +accounting change +$ .32 +$ .29 +$ .33 +$.52 +$1.46 +Cumulative effect +of change +in +accounting principle +(.01) +.00 +.00 +.00 +(.01) +Basic earnings per +share +$ .31 +$ .29 +$ .33 +$.52 +$1.45 +Diluted earnings +per share before +Accounting +principle +$ .31 +$ .29 +$ .31 +$.49 +$1.40 +Cumulative effect +of change in +Accounting +principle +(.01) +.00 +.00 +.00 +(.01) +Diluted +earnings per share +$ .30 +$ .29 +$ .31 +$.49 +$1.39 +Cost of operations +include cost of oil and gas well drilling operations, cost of gas marketing +activities, oil and gas production costs and depreciation, depletion and +amortization. +PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES +SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS +AND RESERVES +Years Ended December 31, 2004, 2003 and 2002 +Column +A +Column B +Column C +Column +D +Column E +Additions, +Balance at +Charged to +Balance +Beginning +Costs and +At End +Description +of Period +Expenses +Deductions +of Period +Allowance for +doubtful accounts deducted +from accounts and +notes receivable in the +Balance sheet +2004 +$487,300 +$ - +$ 78,300 +$409,000 +2003 +$524,500 +$ - +$ 37,200 +$487,300 +2002 +$524,500 +$ - +$ +- +$524,500 \ No newline at end of file diff --git a/raw/filings/0000077877/2004/0000077877-05-000019/rp_note.txt b/raw/filings/0000077877/2004/0000077877-05-000019/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2004/0000077877-05-000019/rpt_disclosure.txt b/raw/filings/0000077877/2004/0000077877-05-000019/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..9e4aba3b14c8cb64d0858e1baf3c9c9d32b7254d --- /dev/null +++ b/raw/filings/0000077877/2004/0000077877-05-000019/rpt_disclosure.txt @@ -0,0 +1,8 @@ +Item 13. Certain Relationships and Related +Transactions +The response to this +item is set forth herein in Note 8 in the Notes to Consolidated Financial +Statements and under "Election of Directors - Interest of Management in +Certain Transactions," in the Company's definitive proxy statement for its +2005 annual meeting of stockholders filed or to be filed with the Commission on +or before April 30, 2005, which we incorporate by reference. \ No newline at end of file diff --git a/raw/filings/0000077877/2005/0000077877-06-000037/filing.txt b/raw/filings/0000077877/2005/0000077877-06-000037/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..85c866446bc4e3273ecdb2170cbe931285d31694 --- /dev/null +++ b/raw/filings/0000077877/2005/0000077877-06-000037/filing.txt @@ -0,0 +1,9916 @@ +10-K +1 +pdc10k20053.htm +Pre-HTML Macros v1.9 +CONFORMED COPY +UNITED STATES +SECURITIES AND +EXCHANGE COMMISSION +Washington, D.C. 20549 +FORM 10-K +ANNUAL REPORT +PURSUANT TO +SECTIONS 13 OR 15(d) +OF THE SECURITIES +EXCHANGE ACT OF 1934 +(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, 2005 +OR +[ ] TRANSITION +REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition +period from to +Commission File Number 0-7246 +PETROLEUM +DEVELOPMENT CORPORATION +(Exact name of +registrant as specified in its charter) +Nevada +95-2636730 +(State or other jurisdiction of +(I.R.S. Employer +incorporation or organization) +Identification No.) +103 East Main +Street , Bridgeport, West Virginia 26330 +(Address of +principal executive offices) (zip code) +Registrant's +telephone number, including area code (304) +842-3597 +SECURITIES +REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: NONE +SECURITIES +REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: +Petroleum +Development Corporation Common Stock, $.01 par value +(Title of class) +Indicate by check mark if the registrant is a well-known +seasoned issuer, as defined in Rule 405 of the Securities Act. Yes +No X +Indicate by check mark if registrant is not required to +file reports pursuant to Section 13 or Section 15(d) of the Act. Yes +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 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 +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. [X] +Indicate by check mark whether the registrant is a large +accelerated filer, an accelerated filer, or non-accelerated file. See +definition of "accelerated filer and larger accelerated filer" in +Rule 12b-2 of the Exchange Act. (Check one): +Large Accelerated Filer [ ] +Accelerated +Filer [ X ] +Non-Accelerated Filer [ ] +Indicate by check mark whether the registrant is a shell +company (as defined in Rule 12b-2 of the Exchange Act). Yes +No X +As of May 5, 2006, 16,057,065 shares of the Registrant's +Common Stock were issued and outstanding, and the aggregate market value of +such shares held by non-affiliates of the Registrant on June 30, 2005, the last business day of the Registrant's most recently completed second quarter was $518,136,692 +(based on the last traded price of $31.85). +DOCUMENTS +INCORPORATED BY REFERENCE +Document +Form 10-K Part III +Proxy +Items 10, 11, 12, +and 13 +(except as presented +herein) +EXPLANATORY +NOTE REGARDING RESTATEMENT +In +this Annual Report on Form 10-K for the year ended December 31, 2005, the +Company is amending and restating its prior consolidated statements of income +for the years ended December 31, 2004 and 2003, and for each of the quarters +ended in the years 2004 and 2003. The restatement also affected periods prior +to 2003, those restated numbers are included in "Item 6. Selected +Financial Data". This Annual Report on Form 10-K is also amending and +restating our consolidated statements of income for the quarterly periods ended +March 31, 2005, June 30, 2005, and September 30, 2005. +As +previously announced in a Form 8K as filed with the Securities and Exchange +Commission on April 3, 2006, the Company identified that corrections were +needed to certain revenues and expenses to properly reflect the elimination of +transactions between the Company and the Company sponsored limited +partnerships. The corrections resulted in elimination of revenues and expenses +of equal amounts. The restatement had no effect on Net Income, Earnings per +Share, Cash Flow, Proved Oil and Gas Reserves, or the Company's financial +position. +For +a discussion of the individual restatement adjustments, see Note 22 to the +Company's consolidated financial statements in "Item 8. Financial Statements +and Supplementary Data". Additionally, see "Item 7. Management's Discussion and +Analysis of Financial Condition and Results of Operations." For more +information on the impact of the restatement on years 2001 and 2002, see "Item +6. Selected Financial Data." +The +Company did not amend its Annual Report on Form 10-K or Quarterly Reports on +Form 10-Q for prior periods affected by the restatement. The financial +statements and related financial information contained in the Company's +previously filed reports should no longer be relied upon. +All +referenced amounts in this Annual Report for prior periods and prior period +comparisons reflect the balances and amounts on a restated basis. +Item 1. Business +Petroleum +Development Corporation is an independent energy company engaged primarily in +the development, production and marketing of natural gas and oil. Since it +began oil and gas operations in 1969, the Company has grown primarily through +drilling and development activities, the acquisition of producing natural gas +and oil wells and the expansion of its natural gas marketing activities. As of December 31, 2005, the Company operates approximately 2,800 wells located in the +Appalachian Basin, Michigan, and the Rocky Mountain Region, with gross proved +reserves of 708 billion cubic feet equivalent of natural gas ("Bcfe", based on +one barrel of oil equals 6 thousand cubic feet equivalent of natural gas +("Mcfe")) of which the Company's share is 275 Bcfe. The Company's share of +production for the fourth quarter of 2005 averaged 38,800 Mcfe per day. +See Glossary of +Terms used in this Form 10-K on Page 61. +Business Segments +The Company's +operations are divided into four segments for management and reporting +purposes. (See Note 20). +Drilling and Development +The Company drills +wells not only for itself, but also for other investor partners. When the +Company drills wells for others it earns profit above the cost of the wells. +The Drilling and Development segment records the payments received from others +as revenue and the related costs as expenses. +Since 1984, the +Company has sponsored limited partnerships formed to engage in drilling +operations. The Company typically purchases a 20% to 30% ownership working interest +in these drilling limited partnerships. In 2005, the Company, through two public +and one private drilling partnership, raised $116 million making it one of the +largest sponsors of public oil and gas partnership programs in the United State s as it has been for the last several years. With the partnerships as a +drilling partner, the Company has been able to expand its drilling +opportunities, reduce its drilling risk through greater diversification, and to +share the costs of the infrastructure necessary to support such activities. +2 +Natural Gas Marketing +The Company's +wholly-owned subsidiary, Riley Natural Gas (RNG), purchases, aggregates and +resells natural gas developed by the Company and other producers. This allows +the Company to diversify its operations beyond natural gas drilling and +production. RNG has established relationships with many of the natural gas +producers in the Appalachian Basin and has significant expertise in the natural +gas end‑user market. In addition, RNG has extensive experience in the use +of economic hedging and derivative strategies, which the Company utilizes to +help manage the financial impact on the Company and its Partnerships of changes +in the price of natural gas and oil. RNG also manages the marketing of oil and +gas for the Company's wells outside the Appalachian Basin, but does not market +gas or oil for non-affiliated producers in those areas. +Oil and Gas Sales +Revenue from the +sale of oil and natural gas from the Company's interest in oil and gas wells is +reported in this segment. The Company has interests in approximately 2,800 wells +ranging from a few percent to 100 percent. During 2005 approximately 12% of the +Company's production was generated by Appalachian Basin wells, 12% by Michigan Basin wells and 76% by Rocky Mountain wells. As of the end of 2005, the Company's +total proved reserves were located as follows: Appalachian Basin 14%, Michigan 9% and Rocky Mountain Region 77%. The majority of the Company's undeveloped +reserves are in the Rocky Mountain Region and the planned drilling for 2006 +will be focused in that area. +Well Operations +The Company operates +almost all of the approximately 2,800 wells in which it owns an interest. When +it owns less than 100 percent of the working interest in a well, it charges the +other owners a competitive operating fee for operating the well. These +revenues and the associated costs are reflected in the Well Operations segment. +Areas of Operations +The Company's +operations are divided into three regions, the Appalachian Basin, Michigan, and +the Rocky Mountain Region. The Company has conducted operations in the Appalachian +Basin since its inception in 1969, in Michigan since 1997, and in the Rocky +Mountain Region since 1999. The Company includes its North Dakota operations in +the Rocky Mountain Region. +In all three regions +the Company has historically targeted shallow (less than 10,000 feet), +developmental natural gas reserves for development. In some areas of the Rocky +Mountain Region, Michigan and the Appalachian Basin the wells also produce oil +in conjunction with natural gas. Recently the Company has begun to drill to +progressively deeper targets in the Rocky Mountain Region. In particular it +has drilled several wells with depths of more than 12,000 feet and horizontal +wells with a total drilled footage approaching 20,000 feet. The Company's +management believes these deeper and horizontal wells offer the possibility of +significantly greater reserves and production than shallow wells, although they +are also more expensive to drill. In addition the probability of encountering +problems when drilling a deep or horizontal well is generally greater than when +drilling a shallow well. With increasing costs for and declining availability +of proved developed drilling locations, the Company's management believes the +additional risk associated with exploratory drilling is justified by the +potential to generate additional proved locations at a significantly lower cost +than would be required to purchase proved undeveloped locations. +Business Strategy +The Company's +primary objective is to increase shareholder value by expanding its oil and +natural gas reserves, production and revenues through a strategy that includes +the following key elements: +Drill and Develop +Drilling new wells, +particularly shallow, developmental natural gas wells, has been the mainstay of +the Company's drilling program for a number of years. The Company drilled 242 +wells in 2005, compared to 158 wells in 2004. In addition the Company seeks to +maximize the value of its existing wells through a program of well +recompletions and drilling in areas where attractive opportunities exist. The Company's +management believes that it will be able to drill a substantial number of new +wells on its current undeveloped leased properties. As of December 31, 2005, the Company had leases or other development rights to +3,000 undeveloped acres in the Michigan Basin, 10,000 undeveloped acres in the +northern Appalachian Basin and 245,250 undeveloped acres in the Rocky Mountain +Region. The Company also has about 67 +Wattenberg Field wells (Colorado) that it plans to recomplete in 2006, including +43 of the new wells it has drilled since 1999 in the field. +3 +To support future +development activities the Company has conducted exploratory drilling in the +past and has continuing exploratory drilling plans in 2006. The goal of the +exploration program is to develop several significant new areas for the Company +to include in its future development drilling programs. +Acquire +The Company's +acquisition efforts are focused on producing properties that fit well within +existing operations or in areas where the Company is establishing new +operations. Preferred properties have most of their value in producing wells, +behind pipe reserves or high quality proved undeveloped locations. +Acquisitions have historically offered economies in management and +administration, and the Company's management believes that it can acquire and +manage more producing wells without incurring substantial increases in its +administrative costs. +Diversify and Focus +With operations in +the Rocky Mountains, Michigan and the Appalachian Basin, the Company has proven +its ability to grow through operations in geographically diverse areas. While +these areas provide geographic diversification, within each area the Company +has concentrated positions that lend themselves to effective development and +operation. The Company plans to conduct the majority of its drilling +activities in the Rocky Mountain Region during 2006, but will continue to seek +additional opportunities for expansion in areas where the Company's experience +and expertise can be applied successfully. +Manage Risk +The Company seeks +opportunities to reduce the risks inherent in the oil and gas industry in a +variety of ways. For a number of years an integral part of the Company's +strategy has been to concentrate on development drilling and geographical +diversification to reduce risk levels associated with natural gas and oil drilling, +production and markets. Development drilling is less risky than exploratory +drilling and is likely to generate cash returns more quickly. Development +drilling will remain the foundation of our drilling activities in 2006. However +the Company's management believes the increasing cost of high quality +development locations has made exploratory drilling more attractive. +Exploratory wells have the potential of identifying new development +opportunities at a significantly lower cost than the current cost of proven +locations. While successful exploratory efforts could add to the Company's +future drilling opportunities at favorable costs, under the successful efforts +method of accounting, exploratory dry holes are expensed at the time it is +recognized that they are unproductive. This could result in greater short term +expenses and a reduction in the near-term profitability of the Company. +To help offset the +relatively high business risk inherent in the oil and gas industry the Company +maintains a conservative financial structure. The Company's management +believes that successful natural gas marketing is essential to profitable +operations in a deregulated gas market. To further this goal, the Company +utilizes its marketing subsidiary, Riley Natural Gas (RNG), to manage the +marketing of the Company's oil and natural gas and its commodity derivatives. This +allows the Company to maintain better control over third party risk in sales +and derivative activities. The Company uses natural gas and oil derivatives to reduce +the effects of volatility of energy prices. +Available Information Posted on the Company's Website +The Company's +Internet address is www.petd.com. Electronic copies of the Company's annual report +on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, +and amendments to those reports are available free of charge by visiting the +"Financial Information" section of www.petd.com. These reports are posted as soon as reasonably +practicable after they are electronically filed with the Securities and +Exchange Commission. Additionally, information including the Company's press +releases, current drilling program sales, Bylaws, Committee Charters, Code of +Business Conduct and Ethics, Shareholder Communication Policy, Board Nomination +Procedures and the Whistleblower and Qualified Legal Compliance Committee +Hotline is also available at the site. +Industry Overview +Natural gas is the +second largest energy source in the United States, after liquid petroleum. The +estimated 21.9 Tcf of natural gas consumed in 2005 represented approximately +23% of the total energy used in the United States. Natural gas is consumed in +the United States as follows: 35% by industrial end-users as feedstock for +products such as plastic and fertilizer or as the energy source for producing +products such as glass; 22% and 14% by residential and commercial end-users, +respectively, for uses including heating, cooling and cooking; and 26% by +utilities for the generation of electricity; and 3% for other users. (Source U.S. Energy Information Administration) +4 +The Company's +management believes that the market for natural gas will continue to grow in +the future. Natural gas is the cleanest and most environmentally safe of the +fossil fuels. Relative to other energy sources, natural gas usage and losses +during transportation from source to destination are slight, averaging only +about 3% of the natural gas energy. The delivery of natural gas is among the +safest means of distributing energy to customers, as the natural gas +transmission system is fixed and is located underground. +The deregulation of +the natural gas industry and a favorable regulatory environment have resulted +in end-users' ability to purchase natural gas on a competitive basis from a +greater variety of sources. Increasing international demand for petroleum +combined with supply constraints drove oil prices to record high levels in 2005. +Continuing increases in world energy demand appear likely in 2006 and beyond. +This makes natural gas more competitive in domestic markets as a replacement +for oil and increases the value of domestic oil and natural gas reserves. +The Company's +management believes that the foregoing factors, together with the increased +availability of natural gas as a form of energy for residential, commercial and +industrial uses, should increase the demand for natural gas as well as create +new markets for natural gas even at prices that are high by historical +standards. +Because local +supplies of natural gas are inadequate to meet demand in sections of the +country, areas including the West Coast and the Northeast import natural gas +from producing areas via interstate natural gas pipelines. The cost of +transporting natural gas from the major producing areas to markets creates a +price advantage for production located closer to the consuming regions. Natural +gas producers in the Appalachian Basin and Michigan benefit from proximity to +the northeastern United States. +In contrast, much of +the production in the Rocky Mountains is transported significant distances to +end user markets. As a result the price received for gas in the Rocky Mountains is generally less than the price received in areas closer to the primary +consuming areas. The Rocky Mountain Region is believed to hold substantial undeveloped +natural gas resources. Recent and planned additions to pipeline capacity in +the region have made the area more attractive for development. Although gas +from the region will generally sell for less than gas in the Appalachian and +Michigan Basins, development costs may be less. +Operations +Exploration and Development Activities +The Company's +development activities focus on the identification and drilling of new +productive wells, the acquisition of existing producing wells from other +producers, and maximizing the value of the Company's current properties through +infill drilling, recompletions, and other production enhancements. +Prospect Generation +The Company's staff +of professional geologists is responsible for identifying areas with potential +for economic production of natural gas and oil. These geologists have decades +of cumulative experience evaluating prospects and drilling natural gas and oil +wells. They utilize results from logs, seismic data and other tools to evaluate +existing wells and to predict the location of economically attractive new gas +reserves. To further this process, the Company has collected and continues to +collect logs, core data, production information and other raw data available +from state and private agencies, other companies and individuals actively +drilling in the regions being evaluated. From this information the geologists +develop models of the subsurface structures and formations that are used to +predict areas with prospects for economic development. +On the basis of +these models, the geologists instruct the Company's land department to obtain +available natural gas and oil leaseholds, farmouts and other development rights +in these prospective areas. These rights are then obtained, if possible, by the +Company's land department or contract landmen under the direction of the +Company's land manager. In most cases, the Company pays a lease bonus and +annual rental payments, converting, upon initiation of production, to a royalty +on gross production revenue in return for obtaining the leases. In addition +overriding royalty payments may be made to third parties in conjunction with +the acquisition of drilling rights initially leased by others. As of December 31, 2005, the Company had leasehold rights to approximately 258,000 acres +available for development. See "Properties--Oil and Natural Gas +Leases." +5 +Drilling Activities +When prospects have +been identified and leased, the Company develops these properties by drilling +wells. In 2005, the Company drilled a total of 234 development wells of which +232 were successfully completed as producing wells. Typically, the Company will +act as driller‑operator for these prospects, frequently selling interests +in the wells to partnerships, primarily Company‑sponsored partnerships, +and other entities that are interested in exploration or development of the +prospects. The Company retains a working interest in each well it drills. +The Company also +drilled 8 exploratory wells in 2005 and plans additional exploratory wells in +2006. Currently the Company plans to retain most if not all of the working +interest in the exploratory wells, since the Company partnerships focus on +developmental activities and are allowed only limited participation in +exploratory drilling. Five of the exploratory wells drilled in 2005 were dry. +The associated costs of these dry holes were $11,115,100 and these costs were +expensed in 2005. See "Financing of Company Drilling and Development Activities" +And "Drilling and Development Activities Conducted for Company Sponsored +Partnerships." +Much of the work +associated with drilling, completing and connecting wells, including drilling, +fracturing, logging and pipeline construction is performed under the Company's +direction by subcontractors specializing in those operations, as is common in +the industry. When judged advantageous, material and services used by the +Company in the development process are acquired through competitive bidding by +approved vendors. The Company also directly negotiates rates and costs for +services and supplies when conditions indicate that such an approach is +warranted. Because the prices paid to the Company by its drilling partnerships +for the Company's services are frequently fixed before the wells are drilled or +are determined based primarily on the well depth, the Company is subject to the +risk that prices of goods or services used in the development process could +increase, rendering its contracts with its investor partners less profitable or +unprofitable. In addition, problems encountered in the process can +substantially increase development costs, sometimes without recourse for the +Company to recover its costs from its partners. To minimize these risks, the +Company seeks to fix its development costs in advance of drilling when +possible. +Drilling Activity +The following tables +summarize the Company's development and exploratory drilling activity for the +last five years. There is no correlation between the number of productive wells +completed during any period and the aggregate reserves attributable to those +wells. +Development Wells Drilled +Total +Productive +Dry +Drilled +Net +Drilled +Net +Drilled +Net +2001 +141 +40.00 +135 +37.94 +6 +2.06 +2002 +70 +13.71 +70 +13.71 +- +- +2003 +110 +28.51 +110 +28.51 +- +- +2004 +157 +43.00 +153 +42.40 +4 +0.60 +2005 +234 +103.40 +232 +102.00 +2 +1.40 +Total +712 +228.62 +700 +224.56 +12 +4.06 +Exploratory Wells Drilled +Total +Productive +Dry +Drilled +Net +Drilled +Net +Drilled +Net +2001 +- +- +- +- +- +- +2002 +- +- +- +- +- +- +2003 +1 +1.00 +- +- +1 +1 +2004 +1 +1.00 +- +- +1 +1 +2005 +8 +7.30 +3 +2.30 +5 +5.00 +Total +10 +9.30 +3 +2.30 +7 +7.00 +6 +Financing of Company Drilling and Development Activities +The Company conducts +development drilling activities for its own account and acts as operator for +other investors. When conducting activities for its own account the Company +uses cash flow from operations and capital provided from its long term credit +facility to fund its share of operations. The Company currently has activated +$80 million of a $200 million credit facility with J.P. Morgan Chase Bank, NA +and BNP Paribas (collectively "the Banks"), however the Banks have determined +that the Company's current oil and gas reserves would support up to $125 +million of borrowing if the need arose. As of the end of 2005 the Company had $24 +million outstanding under the facility. +Drilling and Development Activities Conducted for Company +Sponsored Partnerships +In addition to wells +and interests in wells that it drills for itself, the Company also acts as +operator for other oil and gas investors. Historically these other investors +have included individuals, corporations, partnerships formed by non-affiliated +parties and other investors. Currently the Company's drilling partners consist +primarily of public and private partnerships sponsored by the Company. The +Company makes a cash investment to purchase an interest in the drilling and +development activities of each partnership. +In 1984, the Company +began sponsoring private drilling limited partnerships, and, in 1989, the +Company began to offer partnership interests in public drilling programs +registered with the SEC. The Company's public and private partnerships had $116 +million in subscriptions in 2005, $100 million in subscriptions in 2004, and $78.3 +million in subscriptions in 2003. The Company invests, as its equity +contribution to each drilling partnership, an additional sum approximating 22% to +32% of the aggregate subscriptions received for that particular drilling +partnership and receives a 20% to 30% working interest in each partnership, +respectively. As a result, the Company is subject to substantial cash +commitments at the closing of each drilling partnership. During 2005 this contribution +amounted to $29.0 million. The funds received from these programs are +restricted for future drilling operations. While funds were received by the Company +pursuant to drilling contracts in the years indicated, the Company recognizes +revenues from drilling operations on the percentage of completion method as the +wells are drilled, rather than when funds are received. Substantially all of +the Company's drilling and development funds are now received from partnerships +in which the Company serves as managing general partner. However, because wells +produce for a number of years, the Company continues to serve as operator for a +number of unaffiliated parties. +The process begins +when the Company enters into a development agreement with an investor partner, +pursuant to which the Company agrees to sell some or all of its rights in the +property to be drilled to the partnership or other entity. The partnership or +other entity thereby becomes owner of a working interest in the property. +The Company's drilling +contracts with its investor partners have historically taken many different +forms. Starting in 2006 the drilling agreements can be classified as a +"cost plus" rate, whereby the Company receives a percentage profit in +addition to the actual well costs. In the past the drilling contracts could be +classified as on a "footage-based" rate, whereby the Company received +drilling and completion payments based on the depth of the well. Oil and gas leases +are sold to the partnership at the Company's cost. The Company may also +purchase an additional working interest in the partnership properties. In its +financial reporting the Company reports only its share of reserves, production, +oil and gas sales and costs associated with wells in which other investors +participate. The level of the Company's drilling and development activity +is dependent upon the amount of subscriptions in its public drilling +partnerships and investments from other partnerships or other joint venture +partners. Accepting investments from third party investors and Company +sponsored partnerships enables the Company to diversify its holdings, thereby +reducing the risk of the Company's investments. Additionally, the Company +benefits through such arrangements by its receipt of fees for its management +services and/or through an increased share in the revenues produced by the +developed properties. The Company's management believes that investments in +drilling activities, whether through Company‑sponsored partnerships or +other sources, are influenced in part by the favorable treatment that such +investments enjoy under the federal income tax laws. No assurance can be given +that the Company will continue to have access to funds generated through these +financing vehicles or that the favorable tax treatment will continue. +Purchases of Producing Properties +In addition to +drilling new wells, the Company continues to pursue opportunities to purchase +existing wells from other producers as well as greater ownership interests in +the wells it operates. Generally, outside interests purchased include a +majority interest in the wells and the right to operate the wells. Although the +Company made several offers to purchase properties during 2005, other potential +purchasers outbid the Company; therefore none of its offers were successful. +The Company purchased +a number of small interests in its partnerships from investor partners wishing +to sell their interests in 2005, 2004 and 2003. +7 +Production +The following table +shows the Company's net production in thousands of barrels (MBbl) of crude oil +and in million cubic feet (Mmcf) of natural gas and the costs and weighted +average selling prices of oil in barrels (Bbl) and gas in thousands of cubic +feet (Mcf). +Year Ended December 31, +2005 +2004 +2003 +2002 +2001 +Production(1): +Oil(MBbl) +439 +381 +289 +227 +195 +Natural +Gas (Mmcf) +11,031 +10,372 +8,712 +6,462 +6,085 +Equivalent +Mmcf(2) +13,665 +12,659 +10,449 +7,824 +7,255 +Average sales price: +Oil +(per Bbl)(3) +$50.56 +$38.00 +$29.43 +$24.41 +$22.53 +Natural +gas (per Mcf)(3) +$7.29 +$5.30 +$4.58 +$2.65 +$4.08 +Average +production cost (lifting cost) +Per +equivalent Mcf(4) (restated) +$1.19 +$1.12 +$0.93 +$0.76 +$0.79 +(1) Production +as shown in the table is net to the Company and is determined by multiplying +the gross production volume of properties in which the Company has an interest +by the percentage of the leasehold or other property interest owned by the +Company. +(2) A +ratio of energy content of natural gas and oil (six Mcf of natural gas equals +one barrel of oil) was used to obtain a conversion factor to convert oil +production into equivalent Mcf of natural gas. +(3) The +Company utilizes commodity based economic derivative instruments to hedge and manage +a portion of its exposure to price volatility of its natural gas and oil sales. +The above table does not include the results of derivative transactions. +(4) Production +costs represent oil and gas operating expenses which include severance and ad +valorem taxes as reflected in the financial statements of the Company. See Oil +and Gas Production and Well Operations Costs in Management's Discussion and +Analysis. +Natural Gas Sales +Natural gas produced +by the Company's well interests is generally sold under monthly contracts. +Virtually all of the Company's contract pricing provisions are tied to a market +index, with certain adjustments based on, among other factors, whether a well +delivers to a gathering or transmission line, quality of natural gas and +prevailing supply and demand conditions, so that the price of the natural gas +fluctuates to remain competitive with other available natural gas supplies. As +a result, the Company's revenues from the sale of natural gas will suffer if +market prices decline and benefit if they increase. The Company's management +believes that the pricing provisions of its natural gas contracts are customary +in the industry. +The Company sells +its natural gas to industrial end-users, utilities, other gas marketers, and +other wholesale gas purchasers. Three customers accounted for 15.2%, 12.9% and +10.6% respectively of the Company's revenues from oil and gas sales (9.9%, 8.4% +and 6.9% of total revenues) in 2005. Two customers accounted for 14.1% and +11.3% respectively of the Company's revenues from oil and gas sales (8.6% and +7.0% of total revenues) in 2004. Three customers accounted for 16.4%, 17.2% and +14.2%, respectively of the Company's revenues from oil and gas sales (10.5%, 11.1% +and 9.1% of total revenues) in 2003. No other single purchaser of the Company's +natural gas accounted for 10% or more of the Company's total revenues during +2005, 2004, and 2003. +At December 31, 2005, natural gas produced by the Company sold at prices per Mcf ranging from +$2.52 to $13.31, depending upon well location, the date of the sales contract +and other factors. The weighted net average price of natural gas sold by the +Company during 2005 was $7.29 per Mcf. +In general, the +Company, together with its marketing subsidiary, RNG, has been and expects to +continue to be able to produce and sell natural gas from its wells without +significant curtailment by providing natural gas to purchasers at competitive +prices. Open access transportation through the country's interstate pipeline +system makes a broad range of markets accessible to the Company. Whenever +feasible the Company obtains access to multiple pipelines and markets from each +of its gathering systems seeking the best available market for its natural gas +at any point in time. +8 +Oil Sales +Some of the +Company's wells in the Appalachian Basin, Michigan, most of the Company's wells +in Wattenberg field in Colorado, and the Company's North Dakota wells produce +oil in addition to natural gas. At the end of 2005 oil was about 10% of the +Company's total equivalent reserves. +The Company is +currently able to sell all the oil that it can produce under existing sales +contracts with petroleum refiners and marketers. The Company does not refine +any of its oil production. The Company's crude oil production is sold to +purchasers at or near the Company's wells under short-term purchase contracts. One +purchaser accounted for 10.5%, 7.8% and 10.9% of the Company's revenues from +oil and gas sales (6.9%, 4.8% and 7.0% of total revenues) in 2005, 2004, and +2003. At December 31, 2005, oil produced by the Company sold at prices ranging +from $54.40 to $57.37 per barrel, depending upon +the location and quality of oil. In 2005, the weighted net average price per +barrel of oil sold by the Company was $50.56. +Oil production is +subject to many of the same operating hazards and environmental concerns as +natural gas production, but is also subject to the risk of oil spills. Federal +regulations require certain owners or operators of facilities that store or +otherwise handle oil, such as the Company, to procure and implement Spill Prevention, +Control and Counter-measures ("SPCC") plans relating to the possible discharge +of oil into surface waters. The Oil Pollution Act of 1990 ("OPA") +subjects owners of facilities to strict joint and several liability for all +containment and cleanup costs and certain other damages arising from oil +spills. Noncompliance with OPA may result in varying civil and criminal +penalties and liabilities. Operations of the Company are also subject to the +Federal Clean Water Act and analogous state laws relating to the control of +water pollution, which laws provide varying civil and criminal penalties and +liabilities for release of petroleum or its derivatives into surface waters or +into the ground. +Natural Gas Marketing +The Company's +natural gas marketing activities involve the purchase of natural gas from other +producers and the sale of that natural gas along with natural gas produced by +the Company. The Company's management believes that in a deregulated market, +successful natural gas marketing is an essential component of profitable +operations. A variety of factors affect the market for natural gas, including +the availability of other domestic production, natural gas imports, the +availability and price of alternative fuels, the proximity and capacity of +natural gas pipelines, general fluctuations in the supply and demand for +natural gas and the effects of state and federal regulations on natural gas production +and sales. The natural gas industry also competes with other industries in +supplying the energy and fuel requirements of industrial, commercial and +individual customers. +RNG, a wholly owned +subsidiary, is a natural gas marketing company that specializes in the +purchase, aggregation and sale of natural gas production in the Company's +operating areas. RNG markets natural gas produced by the Company and also +purchases natural gas from other producers and resells to utilities, end users +or other marketers. The employees of RNG have extensive knowledge of natural +gas markets in the Company's areas of operations. Such knowledge assists the +Company in maximizing its prices as it markets natural gas from +Company-operated wells. The gas is marketed to natural gas utilities, pipelines +and industrial and commercial customers, either directly through the Company's +gathering system, or utilizing transportation services provided by regulated +interstate pipeline companies. +Derivative Activities +The Company utilizes +commodity based economic derivative instruments to manage a portion of the +exposure to price volatility stemming from its oil and natural gas sales and +marketing activities. These instruments consist of NYMEX-traded natural gas +futures and option contracts for Appalachian, Michigan and eastern Colorado production, and CIG (Colorado Interstate Gas Index)-based contracts for other Colorado production and NYMEX traded oil futures and option contracts for Colorado oil +production. The Company may utilize derivatives based on other indices or +markets where appropriate. The contracts economically hedge committed and +anticipated natural gas purchases and sales and anticipated oil sales, +generally forecasted to occur within the next two to three year period. Company +policy prohibits the use of natural gas or oil futures or options for +speculative purposes and permits utilization of derivatives only if there is an +underlying physical position. +9 +The Company through +RNG has extensive experience with the use of cash-settled derivatives to reduce +the risk and impact of natural gas price changes. These financial derivatives are +used by RNG to coordinate fixed and variable priced purchases and sales, and by +the Company to "lock in" fixed prices from time to time for the +Company's share of production, and to establish "floors" and +"ceilings" or "collars" on the possible range of the prices +realized for the sale of natural gas and oil. RNG also enters into fixed-price +purchases and sales contracts with counterparties. These fixed physical +contracts meet the FAS 133 definition of a derivative. Both types of +derivatives (i.e., the physical deals and the cash settled contracts) are +carried on the balance sheet at fair value with changes in fair values recognized +currently in the income statement. While derivatives can help provide price +protection if spot prices drop, derivatives can also limit upside potential. +For natural gas +sales not subject to fixed price contracts, the Company is subject to price +fluctuations for natural gas sold in the spot market and under market index +contracts. The Company continues to evaluate the potential for reducing these +risks by entering into derivative transactions. In addition, the Company may +also close out any portion of derivatives that may exist from time to time +which may result in a realized gain or loss on that derivative transaction. The +Company economically manages the price risk on only a portion of its +anticipated production, so some of the production is subject to the full +fluctuation of market pricing. +Well Operations +The +Company currently operates approximately 1,365 wells in the Appalachian Basin, 205 +wells in the Michigan Basin and 1,077 wells in the Rocky Mountain Region. The +Company's ownership interest in these wells ranges from less than 1% to 100%, +and, on average, the Company has an approximate 50.35% ownership interest in +the wells it operates. The Company has an interest in approximately 143 +non-operated wells in the Rocky Mountain Region. +The Company is paid +a monthly operating fee for each well it operates for outside owners including +the limited partnerships sponsored by the Company. The fee is competitive with +rates charged by other operators in the area. The fee covers monthly operating +and accounting costs, insurance and other recurring costs. The Company may also +receive additional compensation for special non-recurring activities, such as +reworks and recompletions. +Transportation +Natural gas wells +are connected by pipelines to natural gas markets. Over the years, the Company +has developed gathering systems in some of its areas of operations. The Company +also continues to construct new trunk lines as necessary to provide for the +marketing of natural gas being developed from new areas and to enhance or +maintain its existing systems. +The Company is paid +a transportation fee for natural gas that is moved by other shippers through +these pipeline systems. In many cases the Company has been able to receive +higher natural gas prices as a result of its ability to move natural gas to +more attractive markets through this pipeline system, to the benefit of both +the Company and its investor partners. +Governmental Regulation +The Company's +business and the natural gas industry in general are heavily regulated. The +availability of a ready market for natural gas production depends on several +factors beyond the Company's control. These factors include regulation of +natural gas production, federal and state regulations governing environmental +quality and pollution control, the amount of natural gas available for sale, +the availability of adequate pipeline and other transportation and processing +facilities and the marketing of competitive fuels. State and federal +regulations generally are intended to protect consumers from unfair treatment, +control and reduce the risk to the public and workers from the drilling, +completion, production and transportation of oil and natural gas, prevent waste +of natural gas, protect rights to produce natural gas between owners in a common +reservoir and control contamination of the environment. Pipelines are subject +to the jurisdiction of various federal, state and local agencies. In the +western part of the United States the federal and state governments own a large +percentage of the land and the rights to develop oil and natural gas. Recently +the Company has increased its positions in these types of leases. Generally government +leases are subject to additional regulations and controls not commonly seen on +private leases. The Company takes the steps necessary to comply with applicable +regulations both on its own behalf and as part of the services it provides to +its investor partnerships. The Company's management believes that it is in +compliance with such statutes, rules, regulations and governmental orders, +although there can be no assurance that this is or will remain the case. The +following discussion of the regulation of the United States natural gas +industry is not intended to constitute a complete discussion of the various +statutes, rules, regulations and environmental orders to which the Company's +operations may be subject. +10 +Regulation of Oil and Natural Gas Exploration and +Production +The Company's oil +and natural gas operations are subject to various types of regulation at the +federal, state and local levels. Prior to commencing drilling activities for a +well, the Company must procure permits and/or approvals for the various stages +of the drilling process from the applicable state and local agencies in the state +in which the area to be drilled is located. Such permits and approvals include +those for the drilling of wells, and such regulation includes maintaining +bonding requirements in order to drill or operate wells and regulating the +location of wells, the method of drilling and casing wells, the surface use and +restoration of properties on which wells are drilled, the plugging and +abandoning of wells and the disposal of fluids used in connection with +operations. The Company's operations are also subject to various conservation +laws and regulations. These include the regulation of the size of drilling and +spacing units or proration units and the density of wells which may be drilled +and the unitization or pooling of properties. In this regard, some states allow +the forced pooling or integration of tracts to facilitate exploration while +other states rely primarily or exclusively on voluntary pooling of lands and +leases. In areas where pooling is voluntary, it may be more difficult to form +units, and therefore, more difficult to develop a project if the operator owns +less than 100% of the leasehold. In addition, state conservation laws may +establish maximum rates of production from oil and natural gas wells, generally +prohibiting the venting or flaring of natural gas and imposing certain +requirements regarding the ratability of production. Where wells are to be +drilled on state or federal leases, additional regulations and conditions may +apply. The effect of these regulations may limit the amount of oil and natural +gas the Company can produce from its wells and may limit the number of wells or +the locations at which the Company can drill. The regulatory burden on the oil +and natural gas industry increases the Company's costs of doing business and, +consequently, affects its profitability. Inasmuch as such laws and regulations +are frequently expanded, amended and reinterpreted, the Company is unable to +predict the future cost or impact of complying with such regulations. +Regulation of Sales and Transportation of Natural Gas +Historically, the +transportation and sale for resale of natural gas in interstate commerce were +regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act +of 1978 (the "NGPA") and the regulations promulgated thereunder by +the Federal Energy Regulatory Commission (FERC). Maximum selling prices of +certain categories of natural gas sold in "first sales," whether sold +in interstate or intrastate commerce, were regulated pursuant to the NGPA. The +Natural Gas Wellhead Decontrol Act (the "Decontrol Act") removed, as +of January 1, 1993, all remaining federal price controls from natural gas sold +in "first sales" on or after that date. FERC's jurisdiction over +natural gas transportation was unaffected by the Decontrol Act. While sales by +producers of natural gas and all sales of crude oil, condensate and natural gas +liquids can currently be made at market prices, Congress could reenact price +controls in the future. +The Company's sales +of natural gas are affected by the availability, terms and cost of +transportation. The price and terms for access to pipeline transportation are +subject to extensive regulation. In the past, FERC has undertaken various +initiatives to increase competition within the natural gas industry. As a +result of initiatives like FERC Order No. 636, issued in April 1992, the +interstate natural gas transportation and marketing system was substantially +restructured to remove various barriers and practices that historically limited +non‑pipeline natural gas sellers, including producers, from effectively +competing with interstate pipelines for sales to local distribution companies +and large industrial and commercial customers. The most significant provisions +of Order No. 636 require that interstate pipelines provide transportation +separate or "unbundled" from their sales service, and require that +pipelines provide firm and interruptible transportation service on an open +access basis that is equal for all natural gas suppliers. In many instances, +the result of Order No. 636 and related initiatives has been to substantially +reduce or eliminate the interstate pipelines' traditional role as wholesalers +of natural gas in favor of providing only storage and transportation services. +Another effect of regulatory restructuring is the greater transportation access +available on interstate pipelines. In some cases, producers and marketers have +benefited from this availability. However, competition among suppliers has +greatly increased and traditional long‑term producer-pipeline contracts +are rare. Furthermore, gathering facilities of interstate pipelines are no +longer regulated by FERC, thus allowing gatherers to charge higher gathering +rates. +Additional proposals +and proceedings that might affect the natural gas industry occur frequently in +the Congress, FERC, state commissions, state legislatures, 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 FERC and Congress will continue. The Company cannot determine to +what extent future operations and earnings of the Company will be affected by +new legislation, new regulations, or changes in existing regulation, at +federal, state or local levels. +Environmental Regulations +The Company's +operations are subject to numerous laws and regulations governing the discharge +of materials into the environment or otherwise relating to environmental +protection. Public interest in the protection of the environment has increased +dramatically in recent years. The trend of more expansive and stricter +environmental legislation and regulations could continue. To the extent laws +are enacted or other governmental action is taken that restricts drilling or +imposes environmental protection requirements that result in increased costs +and reduced access to the natural gas industry in general, the business and +prospects of the Company could be adversely affected. +11 +The Company +generates wastes that may be subject to the Federal Resource Conservation and +Recovery Act ("RCRA") and comparable state statutes. The U.S. +Environmental Protection Agency ("EPA") and various state agencies +have limited the approved methods of disposal for certain hazardous and nonhazardous +wastes. Furthermore, certain wastes generated by the Company's operations that +are currently exempt from treatment as "hazardous wastes" may in the +future be designated as "hazardous wastes," and therefore be subject +to more rigorous and costly operating and disposal requirements. +The Company +currently owns or leases numerous properties that for many years have been used +for the exploration and production of oil and natural gas. Although the Company's +management believes that it has utilized good operating and waste disposal +practices, prior owners and operators of these properties may not have utilized +similar practices, and hydrocarbons or other wastes may have been disposed of +or released on or under the properties owned or leased by the Company or on or +under locations where such wastes have been taken for disposal. These +properties and the wastes disposed thereon may be subject to the Comprehensive +Environmental Response, Compensation and Liability Act ("CERCLA"), +RCRA and analogous state laws as well as state laws governing the management of +oil and natural gas wastes. Under such laws, the Company 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) or to perform remedial plugging operations to +prevent future contamination. +CERCLA and similar +state laws impose liability, without regard to fault or the legality of the +original conduct, on certain classes of persons that are considered to have +contributed to the release of a "hazardous substance" into the +environment. These persons include the owner or operator of the disposal site +or sites where the release occurred and companies that disposed of or arranged +for the disposal of the hazardous substances found at the site. Persons who are +or were responsible for release of 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, and 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. +The Company's +operations may be subject to the Clean Air Act ("CAA") and comparable +state and local requirements. Amendments to the CAA were adopted in 1990 and +contain provisions that may result in the gradual imposition of certain pollution +control requirements with respect to air emissions from the operations of the +Company. The EPA and states have been developing regulations to implement these +requirements. The Company may be required to incur certain capital expenditures +in the next several years for air pollution control equipment in connection +with maintaining or obtaining operating permits and approvals addressing other +air emission-related issues. +The Company's +expenses relating to preserving the environment during 2005 were not significant +in relation to operating costs and the Company expects no material change in +2006. Environmental regulations have had no materially adverse effect on the +Company's operations to date, but no assurance can be given that environmental +regulations will not, in the future, result in a curtailment of production or +otherwise have a materially adverse effect on the Company's business, financial +condition or results of operations. +Operating Hazards and Insurance +The Company's +exploration and production operations include a variety of operating risks, +including the risk of fire, explosions, blowouts, cratering, pipe failure, +casing collapse, abnormally pressured formations, and environmental hazards +such as gas leaks, ruptures and discharges of toxic gas, the occurrence of any +of which could result in substantial losses to the Company due to injury and +loss of life, severe damage to and destruction of property, natural resources +and equipment, pollution and other environmental damage, clean‑up +responsibilities, regulatory investigation and penalties and suspension of +operations. The Company's pipeline, gathering and distribution operations are +subject to the many hazards inherent in the natural gas industry. These +hazards include damage to wells, pipelines and other related equipment, and +surrounding properties caused by hurricanes, floods, fires and other acts of +God, inadvertent damage from construction equipment, leakage of natural gas and +other hydrocarbons, fires and explosions and other hazards that could also +result in personal injury and loss of life, pollution and suspension of +operations. +Any significant +problems related to its facilities could adversely affect the Company's ability +to conduct its operations. In accordance with customary industry practice, the +Company maintains insurance against some, but not all, potential risks; +however, there can be no assurance that such insurance will be adequate to +cover any losses or exposure for liability. The occurrence of a significant +event not fully insured against could materially adversely affect the Company's +operations and financial condition. The Company cannot predict whether +insurance will continue to be available at premium levels that justify its +purchase or whether insurance will be available at all. +12 +Competition +The Company's management believes that its exploration, +drilling and production capabilities and the experience of its management and +professional staff generally enable it to compete effectively. The Company +encounters competition from numerous other oil and natural gas companies, +drilling and income programs and partnerships in all areas of its operations, +including drilling and marketing oil and natural gas and obtaining desirable oil +and natural gas leases. Many of these competitors possess larger staffs and +greater financial resources than the Company, which may enable them to identify +and acquire desirable producing properties and drilling prospects more +economically. The Company's ability to explore for oil and natural gas +prospects and to acquire additional properties in the future depends upon its +ability to conduct its operations, to evaluate and select suitable properties +and to consummate transactions in this highly competitive environment. The +Company competes with a number of other companies that offer interests in +drilling partnerships with a wide range of investment objectives and program +structures. Competition for investment capital for both public and private +drilling programs is intense. The Company also faces intense competition in the +marketing of natural gas from competitors including other producers as well as +marketing companies. Also, international developments and the possible improved +economics of domestic natural gas exploration may influence other companies to +increase their domestic oil and natural gas exploration. Furthermore, +competition among companies for favorable prospects can be expected to +continue, and it is anticipated that the cost of acquiring properties may increase +in the future. During 2005 the industry experienced increased demand for +drilling services and supplies. This is resulting in increasing costs, and in +some cases the demand for supplies and services exceeds the available supplies. +This can result in higher well costs and delays in the execution of planned +drilling operations. Factors affecting competition in the oil and natural gas +industry include price, location, availability, quality and volumes produced. +The Company's management believes that it can compete effectively in the oil +and natural gas industry on each of the foregoing factors. Nevertheless, the +Company's business, financial condition or results of operations could be +materially adversely affected by competition. +Employees +As of December 31, 2005, the Company had 150 employees, including 21 in finance and data +processing, 9 in administration, 15 in exploration and development, 99 in +production and 6 in natural gas marketing. The Company's engineers, supervisors +and well tenders are responsible for the day-to-day operation of wells and +pipeline systems. In addition, the Company retains subcontractors to perform +drilling, fracturing, logging, and pipeline construction functions at drilling +sites. The Company's employees act as supervisors of the subcontractors. The +Company added 36 new employees in 2005. +The Company's +employees are not covered by a collective bargaining agreement. The Company +considers relations with its employees to be excellent. +Item 1A. Risks Related to the Oil and +Natural Gas Industry and the Company +You should carefully consider the following +risk factors in addition to the other information included in this report. Each +of these risk factors could adversely affect our business, operating results +and financial condition, as well as adversely affect the value of an investment +in our common stock or other securities. +Oil and natural +gas prices fluctuate unpredictably and a decline in oil and natural gas prices +can significantly affect the Company's financial results and impede its growth. +The +Company's revenue, profitability and cash flow depend in large part upon the +prices and demand for oil and natural gas. The markets for these commodities +are very volatile and even relatively modest drops in prices can significantly +affect the Company's financial results and impede its growth. Changes in oil +and natural gas prices have a significant impact on the value of the Company's +reserves and on its cash flow. Prices for oil and natural gas may fluctuate +widely in response to relatively minor changes in the supply of and demand for +oil and natural gas, market uncertainty and a variety of additional factors +that are beyond the Company's control, including national and international +economic and political factors and federal and state legislation. +13 +Lower oil and natural gas prices may not +only decrease the Company's revenues, but also may reduce the amount of oil and +natural gas that the Company can produce economically. This may result in the +Company having to make substantial downward adjustments to its estimated proved +reserves. If this occurs or if the Company's estimates of development costs +increase, production data factors change or the Company's exploration results +deteriorate, accounting rules may require us to write down to fair value, as a +non-cash charge to earnings, the carrying value of our oil and natural gas +properties. The Company assesses impairment +of capitalized costs of proved oil and gas properties by comparing net +capitalized costs to estimated undiscounted future net cash flows on a +field-by-field basis using estimated production based upon prices at which +management reasonably estimates such products to be sold. If net capitalized +costs exceed undiscounted future net cash flows, the measurement of impairment +is based on estimated fair value which would consider future discounted cash +flows. The Company may incur impairment charges in the future, which +could have a material adverse effect on its results of operations. +The Company's +estimated oil and gas reserves are based on many assumptions that may turn out +to be inaccurate. Any material inaccuracies in these reserve estimates or +underlying assumptions will materially affect the quantities and present value +of the Company's reserves. +No +one can measure underground accumulations of oil and natural gas in an exact +way. Oil and natural gas reserve engineering requires subjective estimates of +underground accumulations of oil and natural gas and assumptions concerning +future oil and natural gas prices, production levels, and operating and +development costs. As a result, estimated quantities of proved reserves and +projections of future production rates and the timing of development +expenditures may be inaccurate. The Company's estimates of oil and gas reserves +are prepared by the independent petroleum engineers, using pricing, production, +cost, tax and other information provided by the Company. Over time, the +independent petroleum engineers may make material changes to reserve estimates +taking into account the results of actual drilling, testing, and production. The +reserve estimates are based on certain assumptions regarding future oil and +natural gas prices, production levels, and operating and development costs that +may prove incorrect. Any significant variance from these assumptions to actual +figures could greatly affect the estimates of reserves, the economically +recoverable quantities of oil and natural gas attributable to any particular +group of properties, future depreciation, depletion and amortization rates and +amounts, the classifications of reserves based on risk of recovery, and +estimates of the future net cash flows. Some of our reserve estimates are made +without the benefit of a lengthy production history, which renders these +reserve estimates less reliable than estimates based on a lengthy production +history. Numerous changes over time to the assumptions on which the reserve +estimates are based, as described above, often result in the actual quantities +of oil and gas recovered being different from earlier reserve estimates. +The +present value of future net cash flows from the proved reserves is not +necessarily the same as the current market value of the estimated oil and +natural gas reserves (the Securities and Exchange Commission requires the use +of year end prices). The estimated discounted future net cash flows from proved +reserves are based on selling prices in effect on the day of estimate (year +end) and future estimated costs. However, actual future net cash flows from our +oil and natural gas properties also will be affected by factors such as actual +prices we receive for oil and natural gas, the amount and timing of actual +production, amount and timing of future development costs, supply of and demand +for oil and natural gas, and changes in governmental regulations or taxation. +The +timing of both our production and our incurrence of expenses in connection with +the development and production of oil and natural gas properties will affect +the timing of actual future net cash flows from proved reserves, and thus their +actual present value. In addition, the 10% discount factor (rate required by +the Securities and Exchange Commission) we use when calculating discounted +future net cash flows may not be the most appropriate discount factor based on +interest rates currently in effect and risks associated with our oil and gas +properties or the oil and natural gas industry in general. +Unless oil and +natural gas reserves are replaced as they are produced, the Company's reserves +and production will decline, which would adversely affect the Company's +business, financial condition and results of operations. +Producing +oil and natural gas reservoirs generally are characterized by declining +production rates that vary depending upon reservoir characteristics and other +factors. The rate of decline will change if production from existing wells +declines in a different manner than we have estimated and can change due to +other circumstances. Thus, the Company's future oil and natural gas reserves +and production and, therefore, its cash flow and income are highly dependent on +efficiently developing and exploiting the Company's current reserves and +economically finding or acquiring additional recoverable reserves. The Company +may not be able to develop, discover or acquire additional reserves to replace +our current and future production at acceptable costs. As a result, the +Company's operations, financial condition and results of operations would be +adversely affected. +Prospects +drilled by the Company may not yield natural gas or oil in commercially viable +quantities. +A prospect is a property on which the Company's +geologists have identified what they believe, based on available information, +to be indications of natural gas or oil bearing rocks. However, the use of +available data and other technologies and the study of producing fields in the +same area will not enable the geologists to know conclusively prior to drilling +and testing whether natural gas or oil will be present or, if present, whether +natural gas or oil will be present in sufficient quantities to repay drilling +or completion costs and generate a profit. If a well is determined to be dry or +uneconomic, which can occur even though it contains some +14 +oil or gas, it is classified as a dry hole and must be +plugged and abandoned in accordance with applicable regulations. This +generally results in the loss of the entire cost of drilling and completion to +that point, the cost of plugging, and lease costs associated with the +prospect. Even wells that are completed and placed into production may not +produce sufficient oil and gas to be profitable. If the Company drills a dry +hole or non-profitable well on current and future prospects, the profitability +of its operations will decline and the value of the Company will be reduced. In +sum, the cost of drilling, completing and operating any well is often uncertain +and new wells may not be productive. +The Company may not be able to identify enough +attractive prospects on a timely basis to meet its own development needs and +those of the partnerships it forms for investors, which could limit the +Company's development opportunities and/or force it to reduce the partnership +activity. +Our geologists have identified a number of potential +drilling locations on our existing acreage. These drilling locations must be +replaced as they are drilled for the Company to continue to grow its reserves +and production, and for it to be able to continue its partnership drilling +activities. The Company's ability to identify and acquire new drilling +locations depends on a number of uncertainties, including the availability of +capital, regulatory approvals, oil and natural gas prices, competition, costs, +drilling results, and the ability of the Company's geologists to successfully +identify potentially successful new areas to develop. Because of these +uncertainties, the Company's profitability and growth opportunities may be +limited by the timely availability of new drilling locations, and it could be +forced to terminate or curtail its partnership activities because of a lack of +suitable prospects for the partnerships. As a result, the Company's operations and profitability would +be adversely affected. +Drilling for and producing oil and natural gas are +high risk activities with many uncertainties that could adversely affect the +Company's business, financial condition and results of operations. +Drilling activities are subject to many risks, +including the risk that we will not discover commercially productive +reservoirs. Drilling for oil and natural gas can be unprofitable, not only from +dry holes, but from productive wells that do not produce sufficient revenues to +return a profit. In addition, drilling and producing operations may be +curtailed, delayed or canceled as a result of other factors, including unusual +or unexpected geological formations, pressures, fires, blowouts, loss of +drilling fluid circulation, title problems, facility or equipment malfunctions, +unexpected operational events, shortages or delivery delays of equipment and services, +compliance with environmental and other governmental requirements, and adverse +weather conditions. +Any of these risks can cause substantial +losses, including personal injury or loss of life, damage to or destruction of +property, natural resources and equipment, pollution, environmental +contamination or loss of wells and regulatory penalties. The Company maintains +insurance against various losses and liabilities arising from operations; +however, insurance against all operational risks is not available. +Additionally, the Company management may elect not to obtain insurance if the +cost of available insurance is excessive relative to the perceived risks +presented. Thus, losses could occur for uninsurable or uninsured risks or in +amounts in excess of existing insurance coverage. The occurrence of an event +that is not fully covered by insurance could have a material adverse impact on +the Company's business activities, financial condition and results of +operations. +Increased +drilling activity, particularly in the Rocky Mountain Region, may create a +shortage of drilling rigs, service providers, or materials forcing the Company +to curtail its drilling operations for itself and its partnerships thereby +reducing revenue and profits from new oil and gas wells and from the Company's +drilling and completion activities. +With high levels of oil and gas prices +many oil and gas companies have increased their levels of drilling and +completing new wells and reworking old wells. At the same time there is a +limited supply of drilling rigs, completion equipment and qualified personnel +to provide the services necessary to drill, complete and rework new wells. In +particular, the Rocky Mountain Region has seen a great increase in activity +over the past few years. If the demand for these goods and services continues +to increase shortages may develop, which could result in increased prices for +these goods and services or the Company's inability to complete all of the +drilling it has planned. This could result in less drilling by the Company and +the temporary or permanent loss of part or all of its partnership drilling +activity and less profitability for the Company. +The +Company's drilling and development segment receives virtually all of its +revenue from the partnerships it sponsors, and a reduction or loss of that +business could reduce or eliminate the revenue and profits associated with +those activities. +15 +The Company's drilling activities are dependent upon +the capital raised by the Company as a sponsor of limited partnerships. The +Company sells oil and natural gas partnerships through a network of +non-affiliated NASD broker dealers. The largest of those broker dealers sold +about 13.8% of the partnership units in 2005. Investors in the partnerships +are interested in the tax deductions generated by the intangible drilling costs +and the cash flow generated by the partnerships. If the tax laws were changed +to reduce or eliminate the tax advantages, if the cash flow from the +partnerships were to decline due to weak wells or lower energy prices, or if +the brokers decide to stop offering our partnerships for some reason, the sales +of the partnership units would decline, reducing or eliminating the revenue and +profits associated with the drilling and development business segment. As a +result, the Company's operations and profitability would be adversely affected. +Under the Successful Efforts accounting method used by +the Company unsuccessful exploratory wells must be expensed in the period when +they are determined to be non-productive which results in a reduction of the +Company's net income and profitability and could have a negative impact on the +Company's stock price. +The Company increased its exploratory drilling in 2005 +and plans to further increase its exploratory drilling in 2006 in order to +identify additional opportunities for future development. However the cost of +unsuccessful exploratory wells must be charged to expense in the period when +they are determined to be unsuccessful under the successful efforts method of +accounting used by the Company. In addition lease costs for acreage condemned +by the unsuccessful well must also be expensed. In contrast unsuccessful +development wells are capitalized as a part of the investment in the field where +they are located. Because exploratory wells generally are more likely to be +unsuccessful than development wells, the Company anticipates that some or all +of its exploratory wells may not be productive. The costs of such unsuccessful +wells could result in a significant reduction in the Company's profitability in +periods when the costs are required to be expensed, which could have an adverse +effect on the Company's stock price. In addition unsuccessful wells will not +add to the Company's reserves or production. +We may incur substantial impairment write-downs, due +to revisions in our estimates of our reserves, if development costs exceed +estimates or if price of oil and natural gas declines. +If management's estimate of the recoverable reserves on a property is +revised downward, if development costs exceed previous estimates or if oil and +natural gas prices decline, we may be required to record additional non-cash +impairment writedowns in the future, which would result in a negative impact to +our financial position. We review our proved oil and gas properties for +impairment on a quarterly basis. To determine if a depletable unit is impaired, +we compare the carrying value of the depletable unit to the undiscounted future +net cash flows by applying management's estimates of future oil and gas prices +to the estimated future production of oil and gas reserves over the economic +life of the property. Future net cash flows are based upon our independent +reserve engineers' estimates of proved reserves. In addition, other factors +such as probable and possible reserves are taken into consideration when +justified by economic conditions. For each property determined to be impaired, +we recognize an impairment loss equal to the difference between the estimated +fair value and the carrying value of the property on a depletable unit basis. +Fair value is estimated to be the present value of the aforementioned expected +future net cash flows. Any impairment charge incurred is recorded as a +reduction to the asset value. Each part of this calculation is subject to a +large degree of judgment, including the determination of the depletable units' +estimated reserves, future cash flows and fair value. There were no +impairments during 2005, 2004 or 2003. +Rising +finding and development costs may impair our profitability. +In order to continue to grow and maintain +its profitability, the Company must annually add new reserves exceeding its +yearly production at a finding and development cost that yields an acceptable +operating margin and depreciation, depletion and amortization rate. Without +cost effective exploration, development or acquisition activities, production, +reserves and profitability will decline over time. Given the relative maturity +of most gas basins in North America the cost of finding new reserves through +exploration and development operations has been increasing. The acquisition +market for natural gas properties has become extremely competitive among +producers for additional production and expanded drilling opportunities in North America. Acquisition values climbed toward historic highs during 2005 on a per unit +basis, particularly in the Rocky Mountain Region, and the Company believes +these values may continue to increase in 2006. This increase in finding and +development costs is resulting in higher depreciation, depletion and +amortization rates. If the upward trend in finding and development costs +continues, the Company will be exposed to an increased likelihood of a +write-down in carrying value of its natural gas and oil properties in response +to falling prices, which would impair its profitability. +The Company's development and exploration operations +require substantial capital and it may be unable to obtain needed capital or +financing on satisfactory terms, which could lead to a loss of properties and a +decline in our natural gas and oil reserves and production. +16 +The oil and natural gas industry is capital intensive. +The Company makes and expects to continue to make substantial capital +expenditures in its business and operations for the exploration for and +development, production and acquisition of oil and natural gas reserves. To +date, the Company has financed capital expenditures primarily with cash +generated by operations, limited partnership offerings and proceeds from bank +borrowings. Currently the Company intends to finance its capital expenditures +with cash flows from operations, and its existing financing arrangements. Cash +flows from operations and access to capital are subject to a number of +variables, including the Company's proved reserves, the level of oil and +natural gas the Company is able to produce from existing wells, the prices at +which oil and natural gas are sold, and the Company's ability to acquire, +locate and produce new reserves. +If the Company's revenues or the borrowing base under +its revolving credit facility decrease as a result of lower oil and natural gas +prices, operating difficulties, declines in reserves or for any other reason, +it may have limited ability to obtain the capital necessary to sustain its +operations at planned levels. +If additional capital is needed, the Company may not +be able to obtain debt or equity financing on favorable terms, or at all. If +cash generated by operations or sale of limited partnerships or available under +our revolving credit facility is not sufficient to meet our capital +requirements, failure to obtain additional financing could result in a +curtailment of our operations relating to exploration and development of our +prospects, which in turn could lead to a possible loss of properties and a +decline in our natural gas and oil reserves and a decline in our profitability. +The Company's credit facility and other debt financing +have substantial restrictions and financial covenants and the Company may have +difficulty obtaining additional credit, which could adversely affect our +operations. +The Company will depend on its revolving credit +facility for future capital needs. We also are required to comply with certain +financial covenants and ratios. Our ability to comply with these restrictions +and covenants in the future is uncertain and will be affected by the levels of +cash flows from our operations and events or circumstances beyond our control. +Our failure to comply with any of the restrictions and covenants under the +revolving credit facility or other debt financing could result in a default +under those facilities, which could cause all of our existing indebtedness to +be immediately due and payable. +The revolving credit facility limits the amounts we +can borrow to a borrowing base amount, determined by the lenders in their sole +discretion, based upon projected revenues from the oil and natural gas +properties securing our loan. The lenders can unilaterally adjust the borrowing +base and the borrowings permitted to be outstanding under the revolving credit +facility. Outstanding borrowings in excess of the borrowing base must be repaid +immediately, or we must pledge other oil and natural gas properties as +additional collateral. We do not currently have any substantial unpledged +properties, and we may not have the financial resources in the future to make +any mandatory principal prepayments required under the revolving credit +facility. Our inability to borrow additional funds under our credit facility +could adversely affect our operations. +A substantial part of the Company's producing +properties is located in the Rocky Mountains, making it vulnerable to risks +associated with operating in one major geographic area. +The Company's operations are becoming increasingly +focused on the Rocky Mountain Region, which means its producing properties and +new drilling opportunities are geographically concentrated in that area. As a +result, the Company, the success of its operations, and its profitability may be +disproportionately exposed to the impact of delays or interruptions of +production from existing or planned new wells by significant governmental +regulation, transportation capacity constraints, curtailment of production, +interruption of transportation, or fluctuations in prices of oil and natural +gas produced from the wells in the region. +Seasonal weather conditions and lease stipulations +adversely affect the Company's ability to conduct drilling activities in some +of the areas where we operate. +Oil and natural gas operations in the Rocky Mountains are adversely affected by seasonal weather conditions and lease +stipulations designed to protect various wildlife. In certain areas, including +parts of the Sand Wash and Piceance Basins in Colorado, drilling and other oil +and natural gas activities are restricted or prohibited by lease stipulations, +or prevented by weather conditions, for up to 6 months out of the year. This +limits operations in those areas and can intensify competition during those +months for drilling rigs, oil field equipment, services, supplies and qualified +personnel, which may lead to periodic shortages. These constraints and the +resulting shortages or high costs could delay operations and materially +increase operating and capital costs and therefore adversely affect +profitability. +17 +Properties that the Company buys may not produce as +projected and the Company may be unable to determine reserve potential, +identify liabilities associated with the properties or obtain protection from +sellers against them. +One of the Company's growth strategies is to acquire +producing oil and natural gas reserves in its areas of operations and in new +areas to help establish a base of operations for further development. However, +reviews of potential acquisitions are inherently incomplete because it +generally is not feasible to review in depth every individual property. +Ordinarily, the Company focuses review efforts on the higher value properties +and will sample the remainder. However, even a detailed review of records and +properties may not necessarily reveal existing or potential problems, nor will +it permit a buyer to become sufficiently familiar with the properties to assess +fully their deficiencies and potential. Inspections may not always be performed +on every well, and environmental problems, such as ground water contamination, +are not necessarily observable or detectable even when an inspection is +undertaken. Even when problems are identified, the Company may choose to assume +certain environmental and other risks and liabilities in connection with +acquired properties. +We have limited control over activities on properties +we do not operate, which could reduce our production and revenues. +The Company operates most of the wells in which it +owns an interest. However there are some wells the Company does not operate +because it participates through joint operating agreements under which it owns +partial interests in oil and natural gas properties operated by other entities. +If the Company does not operate the properties in which it owns an interest, it +does not have control over normal operating procedures, expenditures or future +development of underlying properties. The failure of an operator to adequately +perform operations, or an operator's breach of the applicable agreements, could +reduce production and revenues and affect our profitability. The success and +timing of drilling and development activities on properties operated by others +therefore depends upon a number of factors outside of the Company's control, +including the operator's timing and amount of capital expenditures, expertise +and financial resources, inclusion of other participants in drilling wells, and +use of technology. +Market conditions or operational impediments hinder +access to oil and natural gas markets or delay production. +Market conditions or the unavailability of +satisfactory oil and natural gas transportation arrangements may hinder access +to oil and natural gas markets or delay production. The availability of a ready +market for oil and natural gas production depends on a number of factors, +including the demand for and supply of oil and natural gas and the proximity of +reserves to pipelines and terminal facilities. The Company's ability to market +its production depends in substantial part on the availability and capacity of +gathering systems, pipelines and processing facilities owned and operated by +third parties. Failure to obtain such services on acceptable terms could +materially harm the Company's business. We may be required to shut in wells for +lack of market or because of inadequacy or unavailability of natural gas +pipeline, gathering system capacity or processing facilities. If that were to +occur, the Company would be unable to realize revenue from those wells until +production arrangements were made to deliver the production to market and its +profitability would be adversely affected. +Our derivative activities could result in financial +losses or could reduce our income. +To achieve a more predictable cash flow, to reduce +exposure to adverse fluctuations in the prices of oil and natural gas and to +allow our gas marketing company to offer pricing options to gas sellers and +purchasers, the Company uses derivatives for a portion of its oil and natural +gas production from its own wells, and for gas purchases and sales by its +marketing subsidiary. These arrangements expose the Company to the risk of +financial loss in some circumstances, including when production, purchases or +sales are different than expected, the counter-party to the derivative contract +defaults on its contract obligations, or when there is a change in the expected +differential between the underlying price in the derivative agreement and +actual prices received. In addition, derivative hedging arrangements may +limit the benefit from changes in the prices for oil and natural gas and may +require the use of Company resources to meet cash margin requirements. Since +the Company does not use hedge accounting treatment for their derivatives, its +earnings are subject to greater volatility. +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 the Company's overall credit +risk in that these entities may be similarly affected by changes in economic +and other conditions. In addition, the Company's oil and natural gas derivatives +as well as the derivatives used by its marketing subsidiary expose the Company +to credit risk in the event of nonperformance by counterparties. +The Company +depends on a limited number of key personnel who would be difficult to replace. +The Company depends on the performance of +our executive officers and other key employees. The loss of any member of +senior management or other key employees could negatively impact the Company's +ability to execute its strategy. The Company does not maintain key person life +insurance policies on any of its employees. +18 +Terrorist +attacks or similar hostilities may adversely impact our results of operations. +The +terrorist attacks that took place in the United States on September 11, 2001 were unprecedented events that have created many economic and political +uncertainties, some of which may materially adversely impact our business. +Uncertainty surrounding military strikes or a sustained military campaign may affect +our operations in unpredictable ways, including disruptions of fuel supplies +and markets, particularly oil, and the possibility that infrastructure +facilities, including pipelines, production facilities, processing plants and +refineries, could be direct targets of, or indirect casualties of, an act of +terror or war. The continuation of these developments may subject our +operations to increased risks and depending on their ultimate magnitude, could +have a material adverse effect on our business, results of operations, +financial condition and prospects. +Our +insurance coverage may not be sufficient to cover some liabilities or losses +that we may incur. +The occurrence of a significant accident +or other event not fully covered by our insurance could have a material adverse +effect on our operations and financial condition. Our insurance does not +protect us against all operational risks. We do not carry business interruption +insurance at levels that would provide enough funds for us to continue +operating without access to other funds. For some risks, we may not obtain +insurance if we believe the cost of available insurance is excessive relative +to the risks presented. In addition, pollution and environmental risks +generally are not fully insurable. +We +may not be able to keep pace with technological developments in our industry. +The natural gas and oil industry is +characterized by rapid and significant technological advancements and +introductions of new products and services using new technologies. As others +use or develop new technologies, we may be placed at a competitive +disadvantage, and competitive pressures may force us to implement those new +technologies at substantial cost. In addition, other natural gas and oil +companies 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. We may not be able to respond to +these competitive pressures and implement new technologies on a timely basis or +at an acceptable cost. If one or more of the technologies we use now or in the +future were to become obsolete or if we are unable to use the most advanced +commercially available technology, our business, financial condition and results +of operations could be materially adversely affected. +Competition in +the oil and natural gas industry is intense, which may adversely affect the +Company's ability to succeed. +The +oil and natural gas industry is intensely competitive, and the Company competes +with other companies that have greater resources. Many of these companies not +only explore for and produce oil and natural gas, but also carry on refining +operations and market petroleum and other products on a regional, national or +worldwide basis. These companies may be able to pay more for productive oil and +natural gas properties and exploratory prospects or define, evaluate, bid for +and purchase a greater number of properties and prospects than our financial or +human resources permit. In addition, these companies may have a greater ability +to continue exploration activities during periods of low oil and natural gas +market prices. Larger competitors may be able to absorb the burden of present +and future federal, state, local and other laws and regulations more easily +than the Company can, which would adversely affect the Company's competitive +position. The Company's ability to acquire additional properties and to +discover reserves in the future will be dependent upon its ability to evaluate +and select suitable properties and to consummate transactions in a highly +competitive environment. In addition, because many companies in our industry +have greater financial and human resources, the Company may be at a +disadvantage in bidding for exploratory prospects and producing oil and natural +gas properties. These factors could adversely affect the success of the +Company's operations and its profitability. +The Company is +subject to complex federal, state, local and other laws and regulations that +could adversely affect the cost, manner or feasibility of doing business. +The +Company's exploration, development, production and marketing operations are +regulated extensively at the federal, state and local levels. Environmental and +other governmental laws and regulations have increased the costs to plan, +design, drill, install, operate and abandon oil and natural gas wells. Under +these laws and regulations, the Company could also be liable for personal +injuries, property damage and other damages. Failure to comply with these laws +and regulations may result in the suspension or termination of operations and +subject the Company to administrative, civil and criminal penalties. Moreover, +public interest in environmental protection has increased in recent years, and environmental +organizations have opposed, with some success, certain drilling projects. +19 +Part of the regulatory environment +includes, in some cases, federal requirements for obtaining environmental +assessments, environmental impact studies and/or plans of development before +commencing exploration and production activities. In addition, the Company's +activities are subject to the regulation by oil and natural gas-producing +states of conservation practices and protection of correlative rights. These +regulations affect operations and limit the quantity of oil and natural gas +that can be produced and sold. A major risk inherent in our drilling plans is +the need to obtain drilling permits from state and local authorities. Delays in +obtaining regulatory approvals, drilling permits, 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 the Company's +ability to explore on or develop its properties. Additionally, the oil and +natural gas regulatory environment could change in ways that might +substantially increase the financial and managerial costs to comply with the +requirements of these laws and regulations and, consequently, adversely affect +profitability. Furthermore, the Company may be put at a competitive +disadvantage to larger companies in the industry who can spread these +additional costs over a greater number of wells and larger operating staff. See +"Business - Governmental Regulation - Regulation of Oil and Natural Gas +Exploration and Production" and "Business - Governmental Regulation - +Environmental Regulations" for a description of the laws and regulations that +affect us. +Item 2. Properties +Summary of Productive Wells +The table below shows the number of the Company's +productive gross and net wells at December 31, 2005. +Productive Wells +Gas +Oil +Location +Gross +Net +Gross +Net +Colorado +1,187 +644.34 +4 +0.79 +Kansas +25 +22.00 +- +- +Michigan +198 +110.17 +7 +2.66 +North Dakota +- +- +4 +2.50 +Pennsylvania +420 +92.21 +- +- +Tennessee +1 +0.71 +35 +13.73 +West Virginia +905 +514.01 +4 +1.72 +Total +2,736 +1,383.44 +54 +21.40 +Oil and Gas Reserves +All of the Company's +oil and natural gas reserves are located in the United States. The Company's +approximate net proved reserves were estimated by independent petroleum +engineers, to be 247,288,000 Mcf of natural gas and 4,538,000 Bbls of oil at December 31, 2005, 197,549,000 Mcf of natural gas and 3,316,000 Bbls of oil at December 31, 2004, and 180,998,000 Mcf of natural gas and 3,029,000 Bbls of oil at December 31, 2003. +The Company's +approximate net proved developed reserves were estimated, by independent +petroleum engineers, to be 155,354,000 Mcf of natural gas and 3,860,000 Bbls of +oil at December 31, 2005, 146,152,000 Mcf of natural gas and 3,190,000 Bbls of +oil at December 31, 2004, and 134,936,000 Mcf of natural gas and 2,889,000 Bbls +of oil at December 31, 2003. +The Company utilized +the services of two independent petroleum engineers for its 2005 independent +reserve report. Wright & Company prepared the reserve report for the +Appalachian and Michigan Basins and Colorado wells. Ryder Scott Company, LLP +prepared the reserve report for the North Dakota Bakken Shale wells. Wright +& Company prepared all of the reserve reports for the Company for 2004 and +2003. +The Company's oil +and natural gas reserves by region are as follows as of December 31, 2005: +20 +Natural Gas +Oil +Gas +Equivalent +(Mbbl) +(Mmcf) +(Mmcfe) +% +Proved +Developed Reserves +Appalachian +Basin +42 +37,843 +38,095 +21.34 +Michigan +Basin +53 +25,094 +25,412 +14.24 +Rocky +Mountain Region +3,765 +92,417 +115,007 +64.42 +Total +Proved Developed Reserves +3,860 +155,354 +178,514 +100.00 +Proved +Undeveloped Reserves +Appalachian +Basin +- +- +- +- +Michigan +Basin +- +544 +544 +0.57 +Rocky +Mountain Region +678 +91,390 +95,458 +99.43 +Total +Proved Undeveloped +678 +91,934 +96,002 +100.00 +Total +Proved Reserves +Appalachian +Basin +42 +37,843 +38,095 +13.88 +Michigan +Basin +53 +25,638 +25,956 +9.46 +Rocky +Mountain Region +4,443 +183,807 +210,465 +76.66 +Total +Proved Reserves +4,538 +247,288 +274,516 +100.00 +No major discovery +or other favorable or adverse event that would cause a significant change in +estimated reserves is believed by the Company to have occurred since December 31, 2005. Reserves cannot be measured exactly, because reserve estimates involve +subjective judgment. The estimates must be reviewed periodically and adjusted +to reflect additional information gained from reservoir performance, new +geological and geophysical data and economic changes. +The standardized +measure of discounted future estimated net cash flows attributable to the +Company's proved oil and gas reserves, giving effect to future estimated income +tax expenses, was estimated by our independent petroleum engineers to be $405.4 +million as of December 31, 2005, $229.4 million as of December 31, 2004, and $202.4 million as of December 31, 2003. These amounts are based on December 31 prices in the respective years. The values expressed are estimates only, +and may not reflect realizable values or fair market values of the natural gas +and oil ultimately extracted and recovered. The standardized measure of +discounted future net cash flows may not accurately reflect proceeds of +production to be received in the future from the sale of natural gas and oil +currently owned and does not necessarily reflect the actual costs that would be +incurred to acquire equivalent natural gas and oil reserves. +Net Proved Natural Gas and Oil Reserves +The proved reserves +of natural gas and oil of the Company as estimated by our independent petroleum +engineers at December 31, 2005 are set forth below. These reserves have been +prepared in compliance with the rules of the Securities and Exchange Commission +(the "SEC") based on December 31, 2005 prices. These reserve estimates were not filed with another Federal authority or agency since the +Company filed its Form 10-K/A as of December 31, 2004. An analysis of the +change in estimated quantities of natural gas and oil reserves from January 1, 2005 to December 31, 2005, all of which are located within the United States, +is shown below: +21 +Natural Gas (Mcf) +Oil (Bbl) +Proved +developed and undeveloped reserves: +Beginning +of year +197,549,000 +3,316,000 +Revisions +of previous estimates +(15,850,000) +80,000 +Beginning +of year as revised +181,699,000 +3,396,000 +New +discoveries and extensions +Rocky +Mountain region +85,624,000 +1,576,000 +Dispositions +to partnerships +(9,556,000) +- +Acquisitions +Michigan +Basin +47,000 +- +Rocky +Mountain region +71,000 +5,000 +Appalachian +basin +434,000 +- +Production +(11,031,000) +(439,000) +End +of year +247,288,000 +4,538,000 +Proved +developed reserves: +Beginning +of year +146,152,000 +3,190,000 +End +of year +155,354,000 +3,860,000 +Standardized Measure of Discounted Future Net Cash Flows +and Changes Therein Relating to Proved Natural Gas and Oil Reserves +Summarized in the +following table is information for the Company with respect to the standardized +measure of discounted future net cash flows relating to proved natural gas and +oil reserves. Future cash inflows are computed by applying year-end prices of +natural gas and oil relating to the Company's proved reserves to year-end +quantities of those reserves. Future production, development, site restoration +and abandonment costs are derived based on current costs, assuming continuation +of existing economic conditions. Future income tax expenses are computed by +applying the statutory rate in effect at December 31, 2005 to the future pretax net cash flows, less the tax basis of the properties, and gives effect to +permanent differences, tax credits and allowances related to the properties. +Future +Estimated Cash Flows +$ +2,381,238,000 +Future +Estimated Production Costs +(545,683,000) +Future Estimated +Development Costs +(207,164,000) +Future +Estimated Income Tax Expense +(633,444,000) +Future Net +Cash Flows +994,947,000 +10% Annual +Discount for Estimated +Timing +of Cash Flows +(589,517,000) +Standardized +Measure of Discounted +Future +Estimated Net Cash Flows +$ +405,430,000 +22 +The following table summarizes the principal sources of change in the +standardized measure of discounted future estimated net cash flows from January 1, 2005 through December 31, 2005: +2005 +Sales of oil +and gas production +net +of production costs +$ +(86,366,000) +Net changes in +prices and production costs +208,353,000 +Extensions, +discoveries, and improved +recovery, +less related costs +150,654,000 +Sales of +reserves +(14,456,000) +Purchase of +reserves +1,266,000 +Development +costs incurred during the period +24,035,000 +Revisions of +previous quantity estimates +(24,130,000) +Changes in +estimated income taxes +(112,054,000) +Accretion of +discount +38,241,000 +Timing and +other +(9,541,000) +Total +$ +176,002,000 +It is necessary to +emphasize that the data presented should not be viewed as representing the +expected cash flow from, or current value of, existing proved reserves, because +the computations are based on a large number of estimates and arbitrary +assumptions. Reserve quantities cannot be measured with precision, and their +estimation requires many judgmental determinations and frequent revisions. The +required projection of production and related expenditures over time requires +further estimates with respect to pipeline availability, rates of demand and +governmental control. Actual future prices and costs are likely to be +substantially different from the current prices and costs utilized in the +computation of reported amounts. Any analysis or evaluation of the reported +amounts should give specific recognition to the computational methods and their +inherent limitations. +Substantially all of +the Company's natural gas and oil reserves have been mortgaged or pledged as +security for the Company's credit agreement. See Note 3 to the notes to the +Company's financial statements. +Oil and Natural Gas Leases +The following table +sets forth, as of December 31, 2005, the acres available for development of oil +and natural gas available to the Company, listed alphabetically by state. +Colorado +115,200 +Kansas +22,800 +Michigan +3,000 +New York +North Dakota +10,000 +80,000 +Wyoming +27,250 +Total +258,250 +Title to Properties +The Company's management +believes that it holds good and indefeasible title to its properties, in +accordance with standards generally accepted in the natural gas industry, +subject to such exceptions stated in the opinion of counsel employed in the +various areas in which the Company conducts its exploration activities. Those +exceptions, in the Company's judgment, do not detract substantially from the +use of such property. As is customary in the natural gas industry, only a +perfunctory title examination is conducted at the time the properties believed +to be suitable for drilling operations are acquired by the Company. Prior to +the commencement of drilling operations, an extensive title examination is +conducted and curative work is performed with respect to defects which the +Company deems to be significant. A title examination has been performed with +respect to substantially all of the Company's producing properties. No single +property owned by the Company represents a material portion of the Company's +holdings. +23 +The properties owned +by the Company are subject to royalty, overriding royalty and other outstanding +interests customary in the industry. The properties are also subject to burdens +such as liens incident to operating agreements, current taxes, development +obligations under natural gas and oil leases, farm-out arrangements and other +encumbrances, easements and restrictions. The Company does not believe that any +of these burdens will materially interfere with the use of the properties. +Facilities +The Company owns and +occupies three buildings in Bridgeport, West Virginia, two of which serve as +the Company's headquarters and one that serves as a field operating facility. The +Company is currently building a new corporate office in Bridgeport, WV which it will occupy in late 2006. The Company also owns a field operating building in Weld County, Colorado and Gilmer County, West Virginia. The Company has operating leases for +field offices in Colorado, Michigan and Pennsylvania. +Item 3. Legal Proceedings +From time to time +the Company is a party to various legal proceedings in the ordinary course of +business. The Company is not currently a party to any litigation that it +believes would have a materially adverse affect on the Company's business, +financial condition, results of operations, or liquidity. +Item 4. Submission of Matters to a Vote of +Security Holders +No matters were +submitted to a vote of security holders during the fourth quarter of the fiscal +year covered by this report. +PART II +Item 5. Market for the Registrant's Common Equity and +Related Stockholders Matters and Issuer Purchases of Equity Securities. +The common stock of +the Company is traded in the NASDAQ National Market under the symbol PETD. The +following table sets forth, for the periods indicated, the high and low bid +quotations per share of the Company's common stock in the over-the-counter +market, as reported by NASDAQ. These quotations represent inter-dealer prices +without retail markups, markdowns, commissions or other adjustments and may not +represent actual transactions. +High +Low +2005 +First +Quarter +$44.19 +$35.72 +Second +Quarter +37.28 +22.65 +Third +Quarter +40.00 +32.54 +Fourth +Quarter +39.55 +30.53 +2004 +First +Quarter +33.93 +16.70 +Second +Quarter +32.63 +21.01 +Third +Quarter +44.80 +24.50 +Fourth +Quarter +49.26 +32.06 +As of May 11, 2006, +there were approximately 874 record holders of the Company's common stock. +The +Company has not paid any dividends on its common stock and currently intends to +retain earnings for use in its business. Therefore, it does not expect to +declare cash dividends in the foreseeable future. Further, the Company's +Credit Agreement restricts the payment of dividends. +24 +Item 6. Selected +Financial Data +Year Ended December 31, +2005 +2004 (1) +2003 (1) +2002 (2) +2001 (2) +(Restated) +(Restated) +(Restated) +(Restated) +Revenues: +Oil +and gas well drilling operations +$ 99,962,900 +$ 94,076,000 +$ 57,509,600 +$ 45,842,000 +$ 60,756,300 +Gas +sales from marketing activities +121,104,100 +94,626,800 +73,131,700 +43,536,400 +67,070,900 +Oil +and gas sales +102,559,200 +69,492,100 +48,393,800 +22,688,100 +29,199,100 +Well +operations and pipeline income +8,759,600 +7,676,900 +6,907,100 +5,771,200 +5,349,200 +Other +income +10,747,300 +1,880,700 +3,528,500 +2,796,800 +3,132,400 +Total revenues +343,133,100 +267,752,500 +189,470,700 +120,634,500 +165,507,900 +Costs and +expenses: +Cost +of oil and gas well drilling operations +88,184,900 +77,696,200 +46,945,900 +37,859,100 +50,465,000 +Cost +of gas marketing activities +119,643,700 +92,881,200 +72,361,400 +43,167,700 +66,545,100 +Oil and gas +production and well operations costs +19,934,700 +17,277,200 +13,251,300 +8,672,400 +8,327,700 +Exploratory +dry hole costs +11,115,100 +- +- +- +- +General +and administrative expenses +6,960,300 +4,505,600 +4,974,400 +4,391,900 +4,145,700 +Depreciation, +depletion and amortization +21,116,200 +18,155,900 +15,312,800 +12,601,500 +11,582,100 +Impairment +of oil and gas properties +- +- +- +- +10,541,900 +Total costs and expenses +266,954,900 +210,516,100 +152,845,800 +106,692,600 +151,607,500 +Income +from operations +76,178,200 +57,236,400 +36,624,900 +13,941,900 +13,900,400 +Interest +expense +682,300 +673,700 +1,195,300 +1,504,800 +1,898,700 +Oil and gas +price risk management loss, net +9,368,100 +3,084,600 +812,400 +369,800 +3,311,200 +Income +before income taxes and cumulative effect +of change +in accounting principle +66,127,800 +53,478,100 +34,617,200 +12,067,300 +8,690,500 +Income taxes +24,676,100 +20,250,500 +11,933,500 +3,186,200 +1,803,100 +Net +income before cumulative effect of change in +accounting principle +41,451,700 +33,227,600 +22,683,700 +8,881,100 +6,887,400 +Cumulative +effect of change in accounting +principle (net +of taxes of $1,392,000) +- +- +(2,271,300) +- +- +Net income +$ 41,451,700 +$ 33,227,600 +$ 20,412,400 +$ 8,881,100 +$ 6,887,400 +Basic earnings +per common share +$2.53 +$2.05 +$1.30 +$0.56 +$0.42 +Diluted +earnings per share +$2.52 +$2.00 +$1.25 +$0.55 +$0.41 +December 31, +2005 +2004 +2003 +2002 +2001 +Total Assets +$ 449,084,900 +$ 335,028,300 +$ 297,541,600 +$ 201,022,200 +$ 186,255,700 +Working +Capital (Deficit) +$ (25,831,200) +$ 231,100 +$ 7,287,800 +$ 3,173,300 +$ 3,310,800 +Long-Term Debt +$ 24,000,000 +$ 21,000,000 +$ 53,000,000 +$ 25,000,000 +$ 28,000,000 +Stockholders' +Equity +$ 188,265,300 +$ 154,020,600 +$ 112,559,200 +$ 92,886,600 +$ 87,616,300 +(1) See Note 22 on page +F-36 for the effect of the restatement on the above data. +(2) See Explanatory Note +regarding restatement on Page 2. +25 +Item 7. Management's +Discussion and Analysis of Financial Condition and Results of Operations +Safe Harbor Statement Under the Private Securities Litigation Reform +Act of 1995 +Statements, other +than historical facts, contained in this Annual Report on Form 10-K, including +statements of estimated oil and gas production and reserves, drilling plans, +future cash flows, anticipated capital expenditures and Management's +strategies, plans and objectives, are "forward looking statements" +within the meaning of Section 27A of the Securities Act of 1933, as amended, +and Section 21E of the Securities Exchange Act of 1934, as amended. Although +the Company's management believes that its forward looking statements are based +on reasonable assumptions, it cautions that such statements are subject to a +wide range of risks and uncertainties incidental to the exploration for, +acquisition, development and marketing of oil and gas, and it can give no +assurance that its estimates and expectations will be realized. Important +factors that could cause actual results to differ materially from the forward +looking statements include, but are not limited to, changes in production +volumes, worldwide demand, and commodity prices for petroleum natural +resources; the timing and extent of the Company's success in discovering, +acquiring, developing and producing oil and gas reserves; the Company's ability +to acquire leases, drilling rigs, supplies and services at reasonable prices; the +availability of capital to the Company; the Company's ability to raise funds +through its Partnership Drilling Programs; risks incident to the drilling and +operation of oil and gas wells; future production and development costs; the +effect of existing and future laws, governmental regulations and the political +and economic climate of the United States; the effect of oil and gas +derivatives activities; and conditions in the capital markets. Other risk +factors are discussed elsewhere in this Form 10-K. +2005 Restatement +As previously +mentioned under "Explanatory Note Regarding Restatement" on Page 2 +and Note 22 on F-35, the Company is amending and restating its prior +consolidated statements of income for the years ended December 31, 2004 and +2003, for the quarterly periods ended March 31, 2005, June 30, 2005 and +September 30, 2005 and for each of the quarters ended in the years 2004 and +2003. The selected financial data for the years ended December 31, 2002 and +2001 has also been restated. The restatement is being made to correct errors in +the reporting of certain revenues and expenses to properly reflect the +elimination of transactions between the Company and the Company sponsored +limited partnerships. The corrections resulted in the elimination of revenues +and expenses of equal amounts. The restatement had no effect on net income, +earnings per share, cash flows, proved oil and gas reserves, or the Company's +financial position. +Results of Operations +Management Overview +The Company has recorded historically +strong revenues, income and cash flow for 2005. High oil and natural gas prices +in combination with record Company production were the largest contributors to +both income and cash flow. The high energy prices increased the Company's +revenues both for sales of Company-owned production and for gas purchased and +sold by RNG, our natural gas marketing subsidiary. Management also believes +that high energy prices made the Company's partnership investment programs more +attractive to investors resulting in a significant increase in the sale of +program interests. This resulted in an increase of drilling activity, volume +of production revenues, and gross profit for the Company's drilling and +development segment. The new wells drilled for the partnerships also led to an +increase in revenues for the Company to operate wells for the partnerships and +others. +The increased level of activities also +increased the costs associated with the drilling and development and well +operations activities because goods, services and other costs were incurred as +a result of the higher levels of activities and prices have increased in +response to higher demand. +Profitability in 2005 was reduced by +losses in derivative transactions relating to the Company's oil and gas sales +in the amount of $9.4 million as recorded in the "Oil and gas price risk +management" line item in the income statement. These consisted of both realized +and unrealized losses. Realized losses are cash losses incurred at the maturity +of derivatives positions which amounted to $6.4 million during 2005. Unrealized +losses are charges that reflect possible losses on derivative positions +maturing in future periods, and may increase or decrease depending on the level +of gas or oil prices at the date the derivatives mature or on the date they are +closed, whichever occurs first, which amounted to $3.0 million during 2005. +The increased profitability and cash flow +from operations allowed the Company to continue to invest in capital projects. +The majority of capital investment was for oil and gas drilling and development +activities. +26 +Year Ended December 31, 2005 Compared with December 31, 2004 +Revenues +Total revenues for +the year ended December 31, 2005 were $343.1 million compared to a restated $267.8 +million for the year ended December 31, 2004, an increase of approximately $75.3 million, or 28.1 percent. The increase was a +result of increased drilling revenues, gas sales from natural gas marketing +activities, oil and gas sales, well operations and pipeline income, and other +income. +Costs and Expenses +Total costs and +expenses for the year ended December 31, 2005 were $267.0 million compared to a restated $210.5 million for the year ended December 31, 2004, an increase of approximately $56.5 million or 26.8 percent. The increase was primarily the +result of increased cost of oil and gas well drilling operations, cost of gas +marketing activities, oil and gas production and well operations cost, +exploratory dry hole costs, general and administrative expenses and depreciation, +depletion and amortization. +Drilling Operations +Drilling revenues +for the year ended December 31, 2005 were $100.0 million compared to a restated +$94.1 million for the year ended December 31, 2004, an increase of approximately $5.9 million or 6.3 percent. Such increase was due to the increased +drilling funds raised and drilled during the year through the Company's drilling +programs. The two public and one private drilling program of 2005 raised $116 million +compared to $100 million in 2004. We believe higher oil and natural gas prices +and the resulting improved performance of our prior programs are the reasons +for the increase in our drilling program sales. +Oil and gas well +drilling operations costs for the year ended December 31, 2005 were $88.2 million compared to a restated $77.7 million for the year ended December 31, 2004, an increase of approximately $10.5 million or 13.5 percent. The increase was due +to the higher levels of drilling activity from our public drilling programs +referred to above and increased costs from higher charges for services and +materials provided to the Company. The gross margin on the drilling activities +for the year ended December 31, 2005 was 11.8 percent compared with 17.4 +percent for the year ended December 31, 2004, a decrease in gross margin of approximately 5.6 percent. The decrease was due to significantly increasing well +drilling and completion costs, particularly the costs of fracturing and rising +steel costs for casing and other well equipment and oil field services. The +private drilling partnership funded on December 30, 2005 with wells to be drilled during the first quarter 2006 and future partnerships will be drilled on a +"cost plus basis"; that should reduce these fluctuations in drilling +gross margins. +This new cost-plus drilling arrangement +eliminates the Company's risk of loss, thus the drilling revenues and +corresponding costs will be netted to a one-lined income statement item +representing only the gross profit portion of the drilling arrangement. This +would have a significant effect on the Company's 2006 gross drilling revenues +and corresponding drilling expenses, but would not change the gross profit. +Natural Gas Marketing Activities +Natural gas sales +from the marketing activities of RNG, the Company's marketing subsidiary for +the year ended December 31, 2005 were $121.1 million compared to $94.6 million +for the year ended December 31, 2004, an increase of approximately $26.5 million +or 28.0 percent. The increase was the result of significantly higher average +natural gas sales prices and higher volumes sold offset in part by an increase +in unrealized losses on derivative transactions which amounted to approximately +$9.2 million and $700,000 for the years ended December 31, 2005 and 2004, respectively. +The costs of gas +marketing activities for the year ended December 31, 2005 were $119.6 million compared to $92.9 million for the year ended December 31, 2004, an increase of $26.7 million or 28.7 percent. The increase was due to higher average volumes +of natural gas purchased for resale and significantly higher average purchase +prices offset in part by an increase in unrealized gains on derivative +transactions which amounted to approximately $9.7 million and $1.4 million for +the years ended December 31, 2005 and 2004, respectively. Income before income +taxes for the Company's natural gas marketing subsidiary decreased from $1.8 +million for the year ended December 31, 2004 to $1.7 million for the year ended December 31, 2005. Based on the nature of the Company's gas marketing +activities, derivatives did not have a significant impact on the Company's net +margins from marketing activities during either period. +27 +Oil and Gas Sales +Oil and gas sales +from the Company's producing properties for the year ended December 31, 2005 were $102.6 million compared to $69.5 million for the year ended December 31, 2004, an increase of $33.1 million or 47.6 percent. The increase was due to +higher volumes sold at significantly higher average sales prices of oil and +natural gas. The volume of natural gas sold for the year ended December 31, 2005 was 11.0 million Mcf at an average price of $7.29 per Mcf compared to 10.4 +million Mcf at an average sales price of $5.30 per Mcf for the year ended December 31 , 2004. Oil sales for the year ended December 31, 2005 were 439,000 barrels at an average sales price of $50.56 per barrel compared to 381,000 barrels at an +average sales price of $38.00 per barrel for the year ended December 31, 2004. The increase in natural gas and oil volumes was the result of the Company's +increased investment in oil and gas properties, primarily recompletions of +existing wells, wells drilled in our NECO, Colorado area of operation, and the +investment in oil and gas properties we own in our public drilling program +partnerships. +Oil and Gas Production +The Company's oil +and gas production by area of operations along with average sales price +(excluding derivative losses) is presented below: +Year Ended December 31, 2005 +Year Ended December 31, 2004 +Natural Gas +Natural Gas +Oil +Natural Gas +Equivalents +Oil +Natural Gas +Equivalents +(Bbl) +(Mcf) +(Mcfe) +(Bbl) +(Mcf) +(Mcfe) +Appalachian +Basin +3,973 +1,631,552 +1,655,390 +4,893 +1,812,407 +1,841,765 +Michigan Basin +4,732 +1,555,958 +1,584,350 +5,786 +1,728,435 +1,763,151 +Rocky +Mountains +430,266 +7,843,250 +10,424,846 +370,482 +6,831,032 +9,053,924 +Total +438,971 +11,030,760 +13,664,586 +381,161 +10,371,874 +12,658,840 +Average +Sales Price +$50.56 +$7.29 +$7.51 +$38.00 +$5.30 +$5.49 +Financial results depend upon many +factors, particularly the price of natural gas and our ability to market our +production effectively. In recent years, natural gas and oil prices have been +among the most volatile of all commodity prices. These price variations can +have a material impact on our financial results. Natural gas prices in the +Rocky Mountain Region continue to trail prices which we receive for our +Appalachian and Michigan gas. The Company's management believes the lower +prices in the Rocky Mountain Region, including Colorado, reflect the higher +costs to move gas to major market areas compared to Michigan and the +Appalachian Basin resulting in a lower price compared to the eastern areas. In +May, 2003 a pipeline expansion project was completed, leading to improved +natural gas prices in the region which reduced the local surplus. There is currently +a substantial amount of drilling activity in the Rockies, and if future +additions to the pipeline system are not made in a timely fashion it is +possible that pipeline constraints could create a local oversupply situation in +the future which could mean lower natural gas prices. Like most other +producers in the area we rely on major interstate pipeline companies to +construct these facilities, so their timing and construction is not within our +control. +Oil and Gas Derivative Activities +Because of +uncertainty surrounding natural gas prices we have used various derivative instruments +to manage some of the impact of fluctuations in prices. Through October 2007 we +have in place a series of floors and ceilings on part of our natural gas +production. Under the arrangements, if the applicable index rises above the +ceiling price, we pay the counterparty, however if the index drops below the +floor the counterparty pays us. During the three months ended December 31, 2005 the Company averaged natural gas volumes sold of 973,700 Mcf per month +and oil sales of 36,050 barrels per month. The positions in effect as of April +30, 2006 on the Company's share of production (The table below does not include positions related to Riley +Marketing activities or derivative contracts entered into by the Company on +behalf of the affiliate Partnerships as the Managing General Partner) by +area are shown in the following table. +28 +Floors +Ceilings +Monthly +Monthly +Quantity +Contract +Quantity +Contract +Mmbtu +Price +Mmbtu +Price +Month +Set +Month +Colorado +Interstate Gas (CIG) Based Derivatives (Piceance Basin) +Jan-05 +Jan +2006 - Mar 2006 +60,000 +$4.50 +30,000 +$7.15 +Jul-05 +Jan +2006 - Mar 2006 +27,500 +$6.50 +13,750 +$8.27 +Sep-05 +Jan +2006 - Mar 2006 +78,700 +$9.00 +- +- +Mar-05 +Apr +2006 - Oct 2006 +42,000 +$4.50 +21,000 +$7.25 +Jul-05 +Apr +2006 - Oct 2006 +27,500 +$5.50 +13,750 +$7.63 +Jul-05 +Nov +2006 - Mar 2007 +27,500 +$6.00 +13,750 +$8.40 +Feb-06 +Nov +2006 - Mar 2007 +60,000 +$6.50 +- +- +Feb-06 +Apr +2007 - Oct 2007 +44,000 +$5.50 +- +- +NYMEX +Based Derivatives - (Appalachian and Michigan Basins) +Jan-05 +Jan +2006 - Mar 2006 +156,000 +$5.00 +78,000 +$8.50 +Sep-05 +Jan +2006 - Mar 2006 +156,000 +$10.50 +- +- +Mar-05 +Apr +2006 - Oct 2006 +78,000 +$5.50 +39,000 +$7.40 +Jul-05 +Apr +2006 - Oct 2006 +61,000 +$6.25 +30,000 +$8.98 +Jul-05 +Nov +2006 - Mar 2007 +68,000 +$7.00 +34,000 +$9.27 +Feb-06 +Nov +2006 - Mar 2007 +34,000 +$8.00 +- +- +Feb-06 +Nov +2006 - Mar 2007 +34,000 +$8.50 +34,000 +$13.73 +Feb-06 +Apr +2007 - Oct 2007 +34,000 +$7.00 +- +- +Feb-06 +Apr +2007 - Oct 2007 +34,000 +$7.50 +34,000 +$10.83 +NYMEX +Based Derivatives (NECO) +Jan-05 +Jan +2006 - Mar 2006 +150,000 +$5.00 +75,000 +$8.45 +Panhandle +Based Derivatives (NECO) +Sep-05 +Jan +2006 - Mar 2006 +100,000 +$10.00 +- +- +Mar-05 +Apr +2006 - Oct 2006 +150,000 +$5.00 +75,000 +$8.62 +Jul-05 +Nov +2006 - Mar 2007 +150,000 +$6.50 +75,000 +$8.56 +Feb-06 +Apr +2007 - Oct 2007 +60,000 +$6.00 +- +- +Feb-06 +Apr +2007 - Oct 2007 +60,000 +$6.50 +60,000 +$9.80 +Well Operations and Pipeline Income +Well operations and +pipeline income for the year ended December 31, 2005 were $8.8 million compared +to a restated $7.7 million for the year ended December 31, 2004, an increase of approximately $1.1 million or 14.3 percent. The +increase was due to an increase in the number of wells and pipeline systems +operated by the Company for our public drilling programs as well as for third +parties. +Other Income +Other income for the year ended December 31, 2005 was $10.7 million compared to a restated $1.9 million for the year ended +December 31, 2004, an increase of $8.8 million. The increase is a result of a +sale of a portion of one of our undeveloped leases in Garfield County, +Colorado, which we sold to an unaffiliated entity in the first quarter of 2005 +for a pre-tax gain of $6.2 million, a second quarter gain on sale to an +unaffiliated party of some Pennsylvania wells in the amount of $1.7 million, +management fees collected from the funding of three drilling partnerships, and +interest earned on higher average cash balances and higher interest rates. +29 +Oil and Gas Production and Well Operations Costs +Oil and gas production and well +operations costs from the Company's producing properties for the year ended December 31, 2005 were $19.9 million compared to a restated $17.3 million for the year +ended December 31, 2004, an increase of approximately $2.6 million or 15.0 +percent. The increase was due to the increased production costs and severance +and property taxes on the increased volumes and higher average sales prices of +natural gas and oil sold, along with the increased number of wells and +pipelines operated by the Company. Lifting costs per Mcfe increased from a +restated $1.12 per Mcf for the year ended December 31, 2004 to $1.19 per Mcfe for the year ended December 31, 2005 due to increased severance and property taxes on the significantly increased oil and gas sales prices along with +additional well workovers and production enhancements work performed. +Exploratory Dry Hole Costs +The Company drilled +eight exploratory wells in 2005 of which five were deemed to be dry holes. In +the fourth quarter of 2005 four Kansas wells were drilled and plugged and +abandoned for a total combined cost of $314,200, which included lease acreage +with cost of $70,600 which was deemed impaired. Also in the fourth quarter the +Coffeepot Springs #24-34 well in Colorado was determined to be uneconomical at +a total dry hole cost of approximately $5.42 million, which included lease +acreage with a cost of $90,000 which was deemed impaired. In the second quarter +of 2005, it was determined the Fox Federal #1-13 well which was drilled in 2004 +in Colorado was also an uneconomic well and total costs of approximately $5.39 +million were expensed, which included lease acreage with a cost of $384,000 +which was deemed impaired. These exploratory dry hole expenses were expensed in +the period in which it was determined that the well was unsuccessful in +accordance with the successful efforts method of accounting. All costs were +incurred 100% by the Company because the drilling fund partnerships did not +participate in these exploratory wells. +General and Administrative Costs +General and administrative expenses for +the year ended December 31, 2005 increased to $7.0 million compared to $4.5 +million for the year ended December 31, 2004 an increase of approximately $2.5 million or 55.6 percent. The increase was primarily due to increased costs of +complying with the various provisions of Sarbanes-Oxley, in particular Section +404 (Internal Controls), the cost of the Company's financial statement +restatements and increased personnel costs for the increased number of +employees. +Depreciation, Depletion, and Amortization +Depreciation, depletion, and amortization +costs for the year ended December 31, 2005 increased to $21.1 million from approximately $18.2 million for the year ended December 31, 2004, an increase of approximately $2.9 million or 15.9 percent. Such increase was due to the significantly +increased production and investment in oil and gas properties by the Company as +referred to above. +Interest Expense +Interest expense for +the year ended December 31, 2005 was $682,000 compared to $674,000 for the year +ended December 31, 2004, an increase of $8,000 or 1.2 percent. Such increase is +due to increased accretion of the Company's asset retirement obligation and +rising interest rates offset in part by lower average outstanding balance of +our credit facility. The Company utilizes its daily cash balances to reduce +its line of credit to lower its cost of interest expense. The average +outstanding debt balances for the year ended December 31, 2005 was $4.1 million compared to $11.3 million for the year ended December 31, 2004. +Oil and Gas Price Risk Management Loss, Net +Oil and gas price risk management loss, +net for the year ended December 31, 2005 was $9.4 million compared to approximately $3.1 million for the year ended December 31, 2004, an increase of $6.3 million. For the year ended December 31, 2005, the Company recorded unrealized losses of $3.0 million and realized losses of $6.4 million compared to the year +ended December 31, 2004, which is comprised of unrealized losses of $1.5 +million and realized losses of $1.6 million. The Company's strategy in its +derivative policy is to provide protection on declining oil and natural gas +prices. During 2005 the Company experienced rising oil and natural gas pricing +environment, this trend caused the Company to record losses in its derivative +transactions. In a declining oil and natural gas pricing environment the +Company would in theory record gains in its derivative transaction activities. +Oil and gas price risk management (gain) loss, net is comprised of the change +in fair value of oil and natural gas derivatives related to our oil and gas +production (this line item does not include commodity based derivative +transactions related to transactions from marketing activities). +Provision for Income Taxes +The effective income +tax rate for the Company's provision for income taxes decreased from 37.9% for +the year ended December 31, 2004 to 37.3% for the year ended December 31, 2005 primarily as a result of the domestic production activities deduction. +30 +Net Income and Earnings Per Share +Net income for the +year ended December 31, 2005 was $41.5 million compared to a net income of $33.2 +million for the year ended December 31, 2004, an increase of approximately $8.3 million or 25.0 percent. +Diluted earnings per +share for the year ended December 31, 2005 was $2.52 per share compared to $2.00 per share for the year ended December 31, 2004, an increase of $0.52 per share or 26.0 percent. +Year Ended December 31, 2004 Compared with December 31, 2003 +Revenues +Total revenues for +the year ended December 31, 2004 were a restated $267.8 million compared to a +restated $189.5 million for the year ended December 31, 2003, an increase of approximately $78.3 million, or 41.3 percent. +The increase was a result of increased drilling revenues, gas sales from +natural gas marketing activities, oil and gas sales and well operations and +pipeline income. +Oil and Gas Well Drilling Revenue +Drilling revenues +for the year ended December 31, 2004 were a restated $94.1 million compared to +a restated $57.5 million for the year ended December 31, 2003, an increase of approximately $36.6 million or 63.7 percent. Such increase was due to the +increased drilling funds raised through the Company's Public Drilling Programs. +The four drilling programs of 2004 raised $100 million compared to $78.3 +million in 2003. We believe higher oil and natural gas prices and the resulting +improved performance of our prior programs are the reasons for the increase in our +drilling program sales. +Natural Gas Marketing Activities +Natural gas sales +from the marketing activities of Riley Natural Gas (RNG), the Company's +marketing subsidiary for the year ended December 31, 2004 were $94.6 million compared to $73.1 million for the year ended December 31, 2003, an increase of approximately $21.5 million or 29.4 percent. The increase was the result of +significantly higher average natural gas sales prices and higher volumes sold. +Oil and Gas Sales +Oil and gas sales +from the Company's producing properties for the year ended December 31, 2004 were $69.5 million compared to $48.4 million for the year ended December 31, 2003, an increase of $21.1 million or 43.6 percent. The increase was due to +significantly higher volumes sold at substantially higher average sales prices +of oil and natural gas. The volume of natural gas sold for the year ended December 31, 2004 was 10.4 million Mcf at an average price of $5.30 per Mcf compared to +8.7 million Mcf at an average sales price of $4.58 per Mcf for the year ended December 31, 2003. Oil sales for the year ended December 31, 2004 were 381,000 barrels at an average restated sales price of $38.00 per barrel compared to 289,000 +barrels at an average sales price of $29.43 per barrel for the year ended December 31, 2003. +Since no +acquisitions were made in 2004, the increase in production resulted primarily +from the new wells drilled by the Company in 2004, recompletions of Wattenberg +Field wells, and completion of behind pipe zones in the Appalachian Basin. Also +the three acquisitions made in 2003 contributed to the increase to the extent +they were not owned for the full year of 2003, but were in 2004. +Oil and Gas Production +The Company's oil +and gas production by area of operations along with average sales price +(excluding derivative gains/losses) is presented below: +31 +Year Ended December 31, 2004 +Year Ended December 31, 2003 +Natural Gas +Natural Gas +Oil +Natural Gas +Equivalents +Oil +Natural Gas +Equivalents +(Bbl) +(Mcf) +(Mcfe) +(Bbl) +(Mcf) +(Mcfe) +Appalachian +Basin +4,893 +1,812,407 +1,841,765 +3,992 +1,921,200 +1,945,152 +Michigan Basin +5,786 +1,728,435 +1,763,151 +6,627 +1,832,737 +1,872,499 +Rocky +Mountains +370,482 +6,831,032 +9,053,924 +278,874 +4,958,245 +6,631,489 +Total +381,161 +10,371,874 +12,658,840 +289,493 +8,712,182 +10,449,140 +Average Price +$38.00 +$5.30 +$5.49 +$29.43 +$4.58 +$4.63 +Financial results depend upon many +factors, particularly the price of natural gas and our ability to market our +production effectively. In recent years natural gas and oil prices have been +among the most volatile of all commodity prices. These price variations can +have a material impact on our financial results. Natural gas prices in Colorado continue to trail prices which we receive for our Appalachian and Michigan gas which are based upon NYMEX. The Company's management believes the lower +prices in the Rocky Mountain Region, including Colorado, resulted from +increasing local supplies that exceeded the local demand and pipeline capacity +available to move gas from the region. In May, 2003 a pipeline expansion +project was completed, leading to improved natural gas prices in the region +which reduced the local surplus. There is currently a substantial amount of +drilling activity in the Rockies, and if future additions to the pipeline +system are not made in a timely fashion it is possible that pipeline +constraints could create a local oversupply situation in the future which could +mean lower natural gas prices. Like most other producers in the area we rely +on major interstate pipeline companies to construct these facilities, so their +timing and construction is not within our control. +Oil and Gas Derivative Activities +Because of +uncertainty surrounding natural gas prices we have used various derivative instruments +to manage some of the impact of fluctuations in prices. Through October of 2006 +we have in place a series of floors and ceilings on part of our natural gas +production. Under the arrangements, if the applicable index rises above the +ceiling price, we pay the counterparty, however if the index drops below the +floor the counterparty pays us. During the three months ended December 31, 2004 the Company averaged natural gas volumes sold of 872,000 Mcf per month +and oil sales of 31,000 barrels per month. The positions in effect as of March +31, 2005 on the Company's share of production (The table below does not include +positions related to Riley Marketing activities or derivative contracts entered +into by the Company on behalf of the affiliate Partnerships as the Managing +General Partner) by area are shown in the following table. +Floors +Ceilings +Monthly +Monthly +Quantity +Contract +Quantity +Contract +Month Set +Month +Mmbtu +Price +Mmbtu +Price +NYMEX Based +Derivatives - (Appalachian and Michigan Basin) +5/04 +Jan 2005 - Mar +2005 +180,000 +$5.67 +90,000 +$7.00 +2/04 +Apr 2005 - Oct +2005 +122,000 +$4.28 +61,000 +$5.00 +3/05 +Apr 2005 - Oct +2005 +39,000 +$5.75 +19,500 +$8.37 +1/05 +Nov 2005 - Mar +2006 +156,000 +$5.00 +78,000 +$8.50 +3/05 +Apr 2006 -Oct +2006 +78,000 +$5.50 +39,000 +$7.40 +Colorado +Interstate Gas (CIG) Based Derivatives (Piceance Basin) +5/04 +Jan 2005 - Mar +2005 +60,000 +$5.04 +30,000 +$6.00 +2/04 +Apr 2005- Oct +2005 +33,000 +$3.10 +16,000 +$4.43 +3/05 +Apr 2005 - Oct +2005 +38,000 +$4.75 +19,000 +$8.12 +1/05 +Nov 2005 - Mar +2006 +60,000 +$4.50 +30,000 +$7.15 +3/05 +Apr 2006 - Oct +2006 +42,000 +$4.50 +21,000 +$7.25 +32 +Colorado +Interstate Gas (CIG) Based Derivatives (Wattenberg) +7/04 +Jan 2005 - Mar +2005 +80,000 +$5.00 +40,000 +$6.20 +NYMEX Based +Derivatives (NECO) +7/04 +Jan 2005 - Mar +2005 +150,000 +$5.32 +- +- +2/04 +Apr 2005 - Oct +2005 +150,000 +$4.26 +75,000 +$5.00 +1/05 +Nov 2005 - Mar +2006 +150,000 +$5.00 +75,000 +$8.45 +Oil - NYMEX +Based Derivatives (Wattenberg) +Bbls +Bbls +8/04 +Jan 2005 - Dec +2005 +15,000 +$32.30 +7,500 +$40.00 +Well Operations, Pipeline & Other Income +Well operations and +pipeline income for the year ended December 31, 2004 were a restated $7.7 million compared to a restated $6.9 million for the year ended December 31, 2003, an increase of approximately $800,000 or 11.6 percent. +The increase was due to an increase in the number of wells and pipeline systems +operated by the Company for our public drilling programs as well as for third +parties. Other income for the year ended December 31, 2004 was a restated $1.9 million compared to a restated $3.5 million for the year ended December 31, 2003, a decrease of $1.6 million or 45.7 percent. Other income in 2003 +included $1.0 million of life insurance proceeds. In 2004 the Company, for +competitive reasons, lowered the management fee it charges to its drilling +partnerships to 1-1/2% of subscriptions, from 2-1/2% of subscriptions. +Costs and Expenses +Costs and expenses +for the year ended December 31, 2004 were a restated $210.5 million compared to +a restated $152.9 million for the year ended December 31, 2003, an increase of approximately $57.6 million or 37.7 percent. The increase was primarily the +result of increased cost of oil and gas well drilling operations, gas purchased +for gas marketing activities, oil and gas production costs and depreciation, +depletion and amortization. +Oil and Gas Well Drilling Costs +Oil and gas well +drilling operations costs for the year ended December 31, 2004 were a restated $77.7 million compared to a restated $46.9 million for the year ended December 31, 2003, an increase of approximately $30.8 million or 65.7 percent. The +increase was due to the higher levels of drilling activity from our public drilling +programs referred to above. In addition, the gross margin on the drilling +activities for the year ended December 31, 2004 was 17.4 percent compared with 18.4 percent for the year ended December 31, 2003, a decrease in gross margin of approximately 1.0 percent. Such decrease was due to significantly +increasing well drilling and completion costs, particularly the costs of +fracturing and rising steel costs for casing and other well equipment. For the +first two partnerships in 2005, the Company raised its turnkey rates charged to +its Public Drilling Partnerships to reverse this declining trend in gross +margins. +Cost of Gas Marketing Activities +The costs of gas +marketing activities for the year ended December 31, 2004 were $92.9 million compared to $72.4 million for the year ended December 31, 2003, an increase of $20.5 million or 28.3 percent. The increase was due to the significantly higher average +prices of natural gas purchased and higher volumes purchased for resale. Income +before income taxes for the Company's natural gas marketing subsidiary improved +from $762,000 for the year ended December 31, 2003 to $1,737,000 for the year ended December 31, 2004. Based on the nature of the Company's gas marketing +activities, derivatives did not have a significant impact on the Company's net +margins from marketing activities during either period. +Oil and Gas Production and Well Operations Costs +Oil and gas +production and well operations costs from the Company's producing properties +for the year ended December 31, 2004 were a restated $17.3 million compared to +a restated $13.3 million for the year ended December 31, 2003, an increase of approximately $4.0 million or 30.0% percent. Such increase was due to the +increased production costs and severance and property taxes on the increased +volumes and higher sales prices of natural gas and oil sold, along with the +increased number of wells and pipelines operated by the Company. Lifting cost +per Mcfe increased from $0.93 per Mcfe to $1.12 per Mcfe due to increased +severance and property taxes on the significantly increased oil and gas sales +prices along with additional well workovers and production enhancements work +performed. +33 +General and Administrative Costs +General and +administrative expenses for the year ended December 31, 2004 decreased to $4.5 million compared with $5.0 million for the year ended December 31, 2003 a decrease of approximately $469,000 or 9.4 percent. +The decrease was primarily due to lower executive compensation costs partially +offset by approximately $477,000 of costs of complying with the various +provisions of Sarbanes-Oxley, in particular with Section 404 (Internal Controls). +Depreciation, Depletion, and Amortization +Depreciation, +depletion, and amortization costs for the year ended December 31, 2004 increased to $18.2 million from approximately $15.3 million for the year ended December 31, 2003, an increase of approximately $2.9 million or 19.0 percent. Such increase was due to the significantly +increased production and investment in oil and gas properties by the Company as +referred to above. +Interest Expense +Interest expense for +the year ended December 31, 2004 was $674,000 compared to $1.2 million for the +year ended December 31, 2003, a decrease of $526,000 or 43.8 percent. The +impact of the derivative on interest expense was a reduction of $592,700 and +$477,600 for the years ended December 31, 2004 and 2003, respectively. Such decrease is due to a lower average outstanding balance of our credit +facility offset in part by rising interest rates. The Company utilizes its +daily cash balances to reduce its line of credit to lower its cost of interest. +The average outstanding debt balances for the year ended December 31, 2004 was $11.3 million compared to $24.1 million for the year ended December 31, 2003. +Oil and Gas Price Risk Management Loss, Net +Oil and gas price risk management loss, +net for the year ended December 31, 2004 was $3.1 million compared +to approximately $800,000 for the year ended December 31, 2003, an increase of $2.3 million. Oil and gas price risk management, net is comprised of +both the realized and unrealized portions of the Company's commodity based +derivative transactions for its oil and gas production (this line item does not +include commodity based derivative transactions related to transactions from +marketing activities). The Company views these transactions as financial +instruments and not a part of our oil and gas sales. The 2004 change is the +result of increasing oil and natural gas prices. +Provision for Income Taxes +The effective income +tax rate for the Company's provision for income taxes increased from 34.5% for +the year ended December 31, 2003 to 37.9% for +the year ended December 31, 2004 primarily as a result of significantly +increased earnings of the Company during 2004, lower percentage depletion for +tax purposes, the benefit in 2003 of officers' life insurance proceeds, and +non-conventional source fuel tax credit. +Net Income and +Earnings Per Share +Net income for the +year ended December 31, 2004 was $33.2 million compared to a net income of $20.4 +million for the year ended December 31, 2003, an increase of approximately $12.8 million or 62.7 percent. +Diluted earnings per +share for the year ended December 31, 2004 was $2.00 per share compared to $1.25 per share for the year ended December 31, 2003, an increase of $0.75 per share or 60.0 percent. +Liquidity and Capital Resources +The +Company funds its operations through a combination of cash flow from operations +and use of the Company's credit facility. Operating cash flow is generated by +sales of natural gas and oil from the Company's well interests, natural gas +marketing, profits from well drilling and operating activities from the +Company's public drilling programs and others, and natural gas gathering and +transportation. Cash payments from Company-sponsored partnerships are used to +drill and complete wells for the partnerships, with operating cash flow +accruing to the Company to the extent payments exceed drilling costs. The +Company utilizes its revolving credit arrangement to meet the cash flow +requirements of its operating and investment activities. Such credit arrangements +were adequate to meet all cash and liquidity requirements. +34 +Natural +Gas Pricing and Pipeline Capacity +The Company sells natural gas under +contracts that are priced based on spot prices or price indexes that reflect +current market prices for the commodity. As a result variations in the market +are reflected in the revenue we receive. The price of natural gas has varied +substantially over short periods of time in the past, and there is every reason +to expect a continuation of that variability in the future. During 2005 prices +for natural gas were close to or above record levels, and future expectations +as reflected in the NYMEX futures market are for continuing high price levels +for 2006 and beyond. Strong domestic and international demand for energy and +inadequate short term supplies are believed to be key causes of the strong +prices. High prices could encourage the development of new energy sources and +reduced consumption as users find more efficient ways to use energy or +substitute other energy forms. High energy prices could also slow global +economic growth, further reducing demand. As a result the energy price outlook +could change rapidly from current expectations. Reduced natural gas prices +would reduce the profitability and cash flow from the Company's gas production +operations. +Natural gas prices throughout the country +tend to be fairly closely related after allowing for differences in the quality +and energy content of the gas, the location and distance to market, and other +factors. Sometimes prices in a particular area may vary from historical +relationships. This can occur when a local condition restricts the +marketability of the natural gas. For example limits on pipeline delivery +capacity for natural gas can result in lower than normal prices for wells that +use the system to deliver gas to market. This situation occurred in 2002 to +2003 in the Rocky Mountains, when the productive capacity of wells in the +region exceeded the amount of gas that could be used by local markets or +shipped out of the area. In order to access the available capacity producers +were forced to sell their gas at lower than normal prices with the alternative +being to shut wells in. Since that time, additional pipeline capacity has been +added, and further additions are planned in the future, so prices have returned +to the historical relationship to other producing regions. However future +delivery constraints could result in lower than anticipated prices or +production in any of the Company's producing areas. +Oil Pricing +Oil +prices were near or above record levels for most of 2005. The Company's oil +prices are largely determined by oil prices in the world market. Global supply +and demand and geopolitical factors are the key determinants of oil prices. +The rapid growth of energy use in developing countries, most notably China, is driving a rapid increase in worldwide oil consumption. Higher prices could +result in reduced consumption and/or increasing supplies that could moderate +the current high price levels. Over the past several years oil has been an +increasing part of the Company's production mix. As a result higher oil prices +have contributed to the Company's increased revenue from oil and gas sales more +than in the past, and the Company would suffer a greater impact if oil prices +were to decrease. +Oil and Gas Derivative Activities +Because of the uncertainty surrounding natural gas and oil +prices we have used various derivative instruments to manage some of the impact +of fluctuations in prices. Through October 2007 we have in place a series of +floors and ceilings on part of our natural gas production. Under the +arrangements, if the applicable index rises above the ceiling price, we pay the +counterparty, however if the index drops below the floor the counterparty pays +us. See previous pages in this Management's Discussion and Analysis for a +schedule of derivative positions. +The Company uses derivative investments to protect prices +for its partners' share of production as well as its own production. Actual +wellhead prices will vary based on local contract conditions, gathering and +other costs and factors. The Company records the fair value of its partners' +share of outstanding derivatives and the partners corresponding obligation or +benefit in accounts receivable or other liabilities as appropriate. +Drilling Programs +During January, 2005, the Company commenced +sales and funded its first 2005 Partnership (PDC +2005-A) at its maximum subscriptions of $40 million, the largest Company +sponsored partnership at that time. The Company commenced the drilling +operations of the partnership late in the first quarter and continued to drill +for the partnership into the second and third quarters of 2005. +In April, 2005, the Company commenced sales +and funded its second 2005 Partnership (PDC +2005-B) at its maximum allowable subscriptions of $40 million. The Company +commenced drilling operations of this partnership late in the second quarter +and drilled for the partnership during the third and fourth quarters of 2005. +In December, 2005, +the Company commenced sales and funded its third 2005 partnership, a private +limited partnership, Rockies Region Private Limited Partnership with +subscriptions of approximately $36 million. Drilling operations commenced in +the first quarter of 2006. +35 +The Company invests, +as its equity contribution to each drilling partnership, a sum equal to approximately +22%-32% of the aggregate subscriptions received for that particular drilling +partnership. As a result, the Company is subject to substantial cash +commitments at the closing of each drilling partnership. During 2005 this +amounted to an investment of approximately $29.0 million in our drilling +partnerships. No assurance can be made that the Company will continue to +receive this level of funding from these or future programs. The Company posts, +during the subscription period of a partnership, daily the amount of +subscriptions that have been sold in the partnership at its website, www.petd.com +under the heading of "Drilling Program". +Substantially all of +the Company's drilling programs contain a repurchase provision allowing +Investors to request that the Company repurchase their partnership units. This +repurchase provision is in effect any time beginning with the third anniversary +of the first cash distribution. The provision provides that the Company is +obligated to purchase an aggregate of 10% of the initial subscriptions per +calendar year (at a minimum price of four times the most recent 12 months' cash +distributions), if investors request that the Company repurchase the units and +subject to the Company's financial ability to do so. The maximum annual 10% +repurchase obligation, if requested by the investors, is currently +approximately $9.2 million. The Company has adequate liquidity to meet this +obligation. During 2005 the Company spent $352,000 under this provision. As of December 31, 2005, outstanding repurchase offers to investing partners totaled $256,400. +In 2006, $70,700 of such outstanding offers were consummated prior to their +expiration on or before February 28, 2006. +Drilling +Activity +During 2005 the Company and its drilling fund partnerships +drilled a total of 132 wells with 2 developmental dry holes. The Company +drilled 99 successful wells in its Wattenberg field in the Denver-Julesburg Basin and 33 successful wells in the Piceance Basin in western Colorado. The Company plans to conduct its 2006 partnership drilling activity in these two +areas, as well as in the Red Desert Basin in Wyoming. +During 2005 the Company drilled several development wells +outside of the public drilling fund partnerships. The Company drilled 57 wells +on its northeast Colorado properties and participated in 24 additional wells +which were drilled by joint venture partners. Of these 81 wells, 79 were +successful. The Company also drilled 20 Wattenberg Field wells for its own +account, all 20 were successful. The Company also drilled a developmental gas +well in the Michigan Basin. +The +total dry hole costs of $11.1 million associated with the six wells described below +(five drilled in 2005, one in 2004) were expensed in accordance with the +successful efforts method of accounting. All costs for the six wells were +incurred 100% by the Company, as no costs were incurred by the drilling fund +partnerships. The Company drilled eight new exploratory wells in 2005. In +addition, one well, which was drilled in 2004, was determined to be a dry hole +in 2005. Three of the eight wells drilled in 2005 were successful and five were +dry holes. +Three +of the wells were drilled in North Dakota (two in the Bakken Shale and one non-operated +in the Nessen Shale). One Bakken Shale well was successful and the other two +wells were in the process of being drilled and completed and had combined +expenditures of $1.9 million as of December 31, 2005. If either or both of these wells are determined to be dry holes, those costs will be expensed in the +period when the determination is made as required by the successful efforts +method of accounting. +During +the fourth quarter of 2005 the Coffeepot Springs #24-34 well located in Colorado was determined to be uneconomic and had a total dry hole cost of $5.42 million +along with four unsuccessful shallow exploratory wells were drilled in Kansas for a total dry hole cost of $314,200. +During +the second quarter of 2005, the Fox Federal #1-13 located in Colorado (for which +drilling was begun 2004), was determined to be a dry hole at a cost of +approximately $5.38 million. +Purchase of Oil +and Gas Properties +Although the Company +made several offers to purchase producing oil and gas properties from other +companies during 2005, it was not successful in purchasing any of those +properties. The Company did purchase a number of small interests in its +partnerships from investors wishing to liquidate their holdings under the +repurchase provision of the partnerships. +36 +Costs incurred by the Company in oil and gas property acquisition, +exploration and development for the year ended December 31, 2005 are presented below: +Acquisition of properties: +Unproved properties +$16,910,200 +Proved properties +1,608,300 +Development costs +68,605,000 +Exploration costs +12,942,700 +$ 100,066,200 +Common Stock +Repurchase +On March 18, 2005 the Company publicly announced the authorization by its Board of Directors to repurchase up to +2% of the Company's outstanding common stock (331,796 shares) at fair market +value at the date of purchase. At a meeting held June 10, 2005, the Board of Directors of Petroleum Development Corporation approved an amendment of the size of +the stock repurchase from 2% to 10% (1,658,980 shares) of the Company's then +outstanding common stock. Under the program, management has discretion as to +the dates of purchase and amounts of stock to be purchased and whether or not +to make purchases. This program expired on December 31, 2005. The following activity has occurred from inception of the plan on March 18, 2005 until December 31, 2005. +Month of Purchase +May, 2005 +Average Price Paid per Share +$23.75 +Broker/Dealer +McDonald Investments +Number of Shares Purchased +331,796 +Remaining Number of Shares to Purchase +1,327,184 +On January 13, 2006 the Company publicly announced that its +Board of Directors has authorized the repurchase of up to 10% (1,627,500 +shares) of the Company's common stock during 2006. Stock repurchases under this +program may be made in the open market or in private transactions, at times and +in amounts that management deems appropriate. The Company may terminate or +limit the stock repurchase program at any time. The following activity has +occurred since inception of the plan on January 13, 2006 until May 10, 2006. +Month of Purchase +January, 2006 +Average Price Paid per Share +$39.33 +Broker/Dealer +McDonald Investments +Number of Shares Purchased +258,169 +Remaining Number of Shares to Purchase +1,369,331 +Working +Capital +Although +the working capital of the Company as of December 31, 2005 is a negative $25.8 million this amount included a net current liability of $7.9 million +related to the fair value of derivatives. The amount may or may not be realized +depending on the change in the fair value of derivatives upon settlement, and +if realized will be funded with proceeds from future oil and gas sales. The +Company manages its working capital needs by only drawing from its credit +facility of $200 million as liabilities come due and cash is required. At December 31, 2005, the Company has adequate liquidity with the credit facility to meet +both its working capital and needs for continued investment in oil and gas well +drilling over the next year. +Long-Term +Debt +The Company has a credit facility with J. +P. Morgan Chase Bank, NA (formerly Bank One, NA) and BNP Paribas of $200 +million subject to and secured by required levels of oil and gas reserves. The +current borrowing base, based upon current oil and gas reserves, is $125 +million of which the Company has activated $80 million of the facility. The +Company is required to pay a commitment fee of 0.25 to 0.375 percent per annum +on the unused portion of the activated credit facility. Interest accrues at +prime, with LIBOR (London Interbank Market Rate) alternatives available at the +discretion of the Company. No principal payments are required until the credit +agreement expires on November 4, 2010. +37 +As of December 31, 2005 the outstanding balance was $24,000,000. Any amounts outstanding under the credit facility +are secured by substantially all properties of the Company. The credit +agreement requires, among other things, the existence of satisfactory levels of +natural gas reserves, maintenance of certain working capital and tangible net +worth ratios along with a restriction on the payment of dividends. At December 31, 2005, the outstanding balance was subject to a prime rate of 7.25%. As of the +filing of this Form 10-K, the Company was in compliance with all covenants in +the credit agreement, except for timely filing of this December 31, 2005 Form +10-K. The Company has received bank waivers to extend the due date of the December 31, 2005 consolidated financial statements until May 31, 2006, and the filing of +the March 31, 2006 consolidated financial statements until June 15, 2006.. +Contractual Obligations +and Contingent Commitments +Contractual obligations +and contingent commitments and due dates are as follows: +Payments due by period +Contractual +Obligations +Less than +1-3 +3-5 +More than +and +Contingent Commitments +Total +1 year +years +years +5 years +Long-Term +Debt +$ 24,000,000 +$ - +$ - +$24,000,000 +$ - +Operating +Leases +1,432,200 +356,300 +589,100 +458,800 +28,000 +Asset +Retirement Obligations +8,333,200 +50,000 +100,000 +100,000 +8,083,200 +Drilling +Rig Commitment +59,627,400 +20,221,000 +31,922,000 +7,484,400 +- +Derivative +Agreements (1) +22,062,500 +18,424,400 +3,638,100 +- +- +Partnership +Performance Supplement (2) +4,808,400 +1,256,700 +3,099,500 +409,800 +42,400 +Other +Liabilities +3,722,600 +40,000 +250,000 +250,000 +3,182,600 +Total +$ 123,986,300 +$ 40,348,400 +$ 39,598,700 +$ 32,703,000 +$ 11,336,200 +(1) +Amount +represents gross liability related to fair value of derivatives. Includes fair +value of derivatives for Riley Natural Gas, Petroleum Development Corporation's +share of oil and gas production and derivatives contracts entered into by the +Company on behalf of the affiliate Partnerships as the Managing General +Partner. The Company has a corresponding receivable from the Partnerships of +$5,351,500 as of December 31, 2005. +(2) +Represents +maximum amount the Company would be required to pay to investing partners if +certain levels of Partnership performance are not met as of December 31, 2005. +See Note 10 to the consolidated financial statements. +Long-term debt in the above table does not include interest +as interest rates are variable and principal balances fluctuate significantly +from period to period. The Company continues to pursue capital investment +opportunities in producing natural gas properties as well as its plan to +participate in its sponsored natural gas drilling partnerships, while pursuing +opportunities for operating improvements and cost efficiencies. Management +believes that the Company has adequate capital to meet its operating +requirements. +Commitments +and Contingencies +As Managing General Partner of 75 +partnerships (See Item 1. Business - Drilling and Development) the Company has +liability for any potential casualty losses in excess of the partnership assets +and insurance. The Company's management believes its and its subcontractors' +casualty insurance coverage is adequate to meet this potential liability. +Critical +Accounting Policies and Estimates +We have identified the following policies as critical +to our business operations and the understanding of our results of operations. +This is not a comprehensive list of all of our accounting policies. In many +cases, the accounting treatment of a particular transaction is specifically +dictated by accounting principles generally accepted in the United States, with no need for management's judgment in their application. There are also areas in +which management's judgment in selecting any available alternative would not +produce a materially different result. However, certain of our accounting +policies are particularly important to the portrayal of our financial position +and results of operations and may require the application of significant +judgment by our management; as a result, they are subject to an inherent degree +of uncertainty. In applying those policies, our management uses its judgment to +determine the appropriate assumptions to be used in the determination of +certain estimates. Those estimates are based on our historical experience, our +observation of trends in the industry, and information available from other +outside sources, as appropriate. For a more detailed discussion on the +application of these and other accounting policies, see "Note 1 - Summary of +significant accounting policies" in our financial statements and related notes. +Our critical accounting policies and estimates are as follows: +38 +Principles of Consolidation +The accompanying +consolidated financial statements include the accounts of Petroleum Development +Corporation (PDC) and its wholly owned +subsidiaries, Riley Natural Gas (RNG) and PDC +Securities Incorporated. All material intercompany accounts and transactions +have been eliminated in consolidation. The Company accounts for its investment +in interests in oil and gas limited partnerships under the proportionate +consolidation method. Under this method, the Company's financial statements +include its pro rata share of assets, liabilities and revenues and expenses +respectively of the Company sponsored limited partnerships in which it +participates. The Company's proportionate share of all significant transactions +between the Company and the Company sponsored limited partnerships is +eliminated. +Revenue Recognition +The Company's +drilling segment recognizes revenue from our drilling contracts with our +sponsored drilling programs using the percentage of completion method. These +contracts include the sale of equipment and the providing of services at +footage rates and are completed within nine to twelve months after the +commencement of drilling. The Company provides geological, engineering, and +drilling supervision for the drilling and completion process and uses +subcontractors to perform drilling and completion services. Revenues are +recognized under the percentage of completion method based upon the percentage +of contract costs incurred to date to the estimated total contract costs for +each contract. The Company utilizes this method because reasonably dependable +estimates of the total estimated costs can be made. Because the revenue +recognized depends on estimates of the final contract costs, which are assessed +periodically during the term of the contract, recognized revenues are subject +to revisions as the contract progresses. Anticipated losses, if any, on +uncompleted contracts are recorded at the time that our estimated costs exceed +the estimated contract revenue. In 2005, the Company recorded a loss of +$800,000 on uncompleted drilling contracts as part of Cost of Oil and Gas Well +Drilling Operations. The Company did not experience any contract losses in 2004 +or 2003. +Natural gas marketing is recorded on the +gross accounting method. RNG, our marketing subsidiary, purchases gas from +many small producers and bundles the gas together to sell in larger amounts to +purchasers of natural gas for a price advantage. RNG has latitude in +establishing price and discretion in supplier and purchaser selection. Natural +gas marketing revenues and expenses reflect the full cost and revenue of those +transactions because RNG takes title to the gas it purchases from the various +producers and bears the risks and rewards of that ownership. Both the realized +and unrealized portions of the RNG commodity based derivative transactions for +natural gas marketing activities are included in gas sales from marketing +activities or cost of gas marketing activities, as applicable. +Sales of natural gas are recognized when +natural gas has been delivered to a custody transfer point, persuasive evidence +of a sales arrangement exists, the rights and responsibility of ownership pass +to the purchaser upon delivery, collection of revenue from the sale is +reasonably assured and the sales price is fixed or determinable. Natural gas +is sold by the Company under contracts with terms ranging from one month to +three years. Virtually all of the Company's contracts pricing provisions are +tied to a market index, with certain adjustments based on, among other factors, +whether a well delivers to a gathering or transmission line, quality of natural +gas and prevailing supply and demand conditions, so that the price of the +natural gas fluctuates to remain competitive with other available natural gas +supplies. As a result, the Company's revenues from the sale of natural gas +suffer if market prices decline and benefit if they increase. The Company +believes that the pricing provisions of its natural gas contracts are customary +in the industry. +The Company currently uses the "Net-Back" +method of accounting for transportation arrangements of our natural gas sales. +The Company sells gas at the wellhead and collects a price and recognizes +revenues based on the wellhead sales price since transportation costs +downstream of the wellhead are incurred by our customers and reflected in the +wellhead price. +Sales of oil are recognized when +persuasive evidence of a sales arrangement exists, the oil is verified as +produced and is delivered in a stock tank, collection of revenue from the sale +is reasonably assured and the sales price is determinable. The Company is +currently able to sell all the oil that it can produce under existing sales +contracts with petroleum refiners and marketers. The Company does not refine +any of its oil production. The Company's crude oil production is sold to +purchasers at or near the Company's wells under short-term purchase contracts +at prices and in accordance with arrangements that are customary in the oil +industry. +Well operations and pipeline income is +recognized when persuasive evidence of an arrangement exists, services have been +rendered, collection of revenues is reasonably assured and the sales price is +fixed or determinable. The Company is paid a monthly operating fee for each +well it operates for outside owners, including the limited partnerships +sponsored by the Company. The fee covers monthly operating and accounting +costs, insurance and other recurring costs. The Company may also receive +additional compensation for special non-recurring activities, such as reworks +and recompletions. +39 +Valuation +of Accounts Receivable +Management reviews accounts receivable to +determine which are doubtful of collection. In making the determination of the +appropriate allowance for doubtful accounts, management considers the Company's +history of write-offs, relationships and overall credit worthiness of its +customers, and well production data for receivables related to well operations. +Accounting for Derivatives Contracts at Fair Value +The Company uses +derivative instruments to manage its commodity and financial market risks. Accounting +requirements for derivatives and hedging activities are complex; interpretation +of these requirements by standard-setting bodies is ongoing. The Company +currently does not use hedge accounting treatment for its derivatives. +Derivatives are reported +on the Consolidated Balance Sheets at fair value. Changes in fair value of +derivatives are recorded in earnings in the consolidated statements of income +as none of the Company's derivatives qualified for hedge accounting under the +provisions of FAS No. 133. +The measurement of +fair value is based on actively quoted market prices, if available. Otherwise, +the Company seeks indicative price information from external sources, including +broker quotes and industry publications. If pricing information from external +sources is not available, measurement involves judgment and estimates. These +estimates are based on valuation methodologies considered appropriate by the +Company's management. For individual contracts, the use of different +assumptions could have a material effect on the contract's estimated fair +value. +Use of Estimates in Long-Lived Asset Impairment Testing +Impairment testing +for long-lived assets and intangible assets with definite lives is required +when circumstances indicate those assets may be impaired. In performing an impairment +test, the Company estimates the future cash flows associated with individual +assets or groups of assets. Impairment is recognized when the undiscounted +estimated future cash flows are less than the related asset's carrying amount. +In those circumstances, the asset must be written down to its fair value, +which, in the absence of market price information, may be estimated as the +present value of its expected future net cash flows, using an appropriate +discount rate. Although cash flow estimates used by the Company are based on +the relevant information available at the time the estimates are made, +estimates of future cash flows are, by nature, highly uncertain and may vary +significantly from actual results. +Oil and Gas Properties +The +Company accounts for its oil and gas properties under the successful efforts +method of accounting. Costs of proved developed producing properties, +successful exploratory wells and development dry hole costs are depreciated or +depleted by the unit-of-production method based on estimated proved developed +producing oil and gas reserves. Property acquisition costs are depreciated or +depleted on the unit-of-production method based on estimated proved oil and gas +reserves. The Company obtains new reserve reports from independent petroleum +engineers annually as of December 31st of each year. The Company adjusts oil +and gas reserves for any major acquisitions, new drilling and divestitures +during the year as needed. +Exploration +costs, including geological and geophysical expenses and delay rentals, are +charged to expense as incurred. Exploratory well drilling costs, including the +cost of stratigraphic test wells, are initially capitalized but charged to +expense if the well is determined to be nonproductive. The status of each +in-progress well is reviewed quarterly to determine the proper accounting +treatment under the successful efforts method of accounting. Exploratory well +costs continue to be capitalized as long as the well has found a sufficient quantity +of reserves to justify its completion as a producing well and the Company is +making sufficient progress assessing its reserves and economic and operating +viability. If an in-progress exploratory well is found to be unsuccessful +(referred to as a dry hole) prior to the issuance of our financial statements, +the costs are expensed to exploratory dry hole costs. If we are unable to make +a final determination about the productive status of a well prior to issuance +of our financial statements, the well is classified as "Suspended Well Costs" +until we have had sufficient time to conduct additional completion or testing +operations to evaluate the pertinent geological and engineering data obtained. +At the time when we are able to make a final determination of a well's +productive status, the well is removed from the suspended well status and the +proper accounting treatment is recorded. The determination of an exploratory +well's ability to produce is made within one year from the completion of +drilling activities. +40 +The +acquisition costs of unproved properties are capitalized when incurred, until +such properties are transferred to proved properties or charged to expense when +expired, impaired or amortized. Unproved oil and gas properties with individually +significant acquisition costs are periodically assessed, and any impairment in +value is charged to expense. The amount of impairment recognized on unproved +properties which are not individually significant is determined by amortizing +the costs of such properties within appropriate fields based on the Company's +historical experience, acquisition dates and average lease terms. Amortization +of remaining lease costs for all other insignificant properties is recorded +over the average remaining lives of the leases. The valuation of unproved +properties is subjective and requires management of the Company to make +estimates and assumptions which, with the passage of time, may prove to be +materially different from actual realizable values. +Upon +sale or retirement of significant portions of or complete fields of depreciable +or depletable property, the book value thereof, less proceeds or salvage value, +is credited or charged to income. Upon sale of individual wells, the proceeds +are credited to property costs. +The +Company assesses impairment of capitalized costs of proved oil and gas +properties by comparing net capitalized costs to estimated undiscounted future +net cash flows on a field-by-field basis using estimated production based upon +prices at which management reasonably estimates such products to be sold. These +estimates of future product prices may differ from current market prices of oil +and gas. Any downward revisions to management's estimates of future production +or product prices could result in an impairment of the Company's oil and gas +properties in subsequent periods. If net capitalized costs exceed undiscounted +future net cash flows, the measurement of impairment is based on estimated fair +value which would consider future discounted cash flows. +Deferred Tax Asset Valuation Allowance +Deferred tax assets are recognized for +deductible temporary differences, net operating loss carry-forwards, and credit +carry-forwards if it is more likely than not that the tax benefits will be +realized. To the extent a deferred tax asset is not expected to be realized under +the preceding criteria, a valuation allowance has been established. +The judgments used in applying the above +policies are based on management's evaluation of the relevant facts and +circumstances as of the date of the financial statements. Actual results may +differ from those estimates. +Recently Adopted Accounting Standards +The FASB issued FIN +46R, "Consolidation of Variable Interest Entities", in January 2003 +and amended the interpretation in December 2003. A variable interest entity +(VIE) is an entity in which voting equity investors lack the characteristics of +having a controlling financial interest or where the existing capital at risk +is insufficient to permit the entity to finance its activities without +receiving additional financial support from other parties. FIN 46R requires +the consolidation of entities which are determined to be VIEs where the +reporting company determines itself to be the primary beneficiary (the entity +that will absorb a majority of the VIE's expected losses, receive a majority of +the VIE's residual return, or both). The amended interpretation was effective +for the first interim annual reporting period ending after March 15, 2004, with the exception of special purpose entities for which the statement was effective +for periods ending after December 15, 2003. We have completed a review of our partnership investments and have determined that the partnerships are not +VIEs. +In June 2005, the EITF reached a consensus +on EITF Issue No. 04-5, "Determining Whether a General Partner, or the +General Partners as a Group, Controls a Limited Partnership or Similar Entity +When the Limited Partners Have Certain Rights". This consensus applies to +voting right entities not within the scope of FASB Interpretation No. 46R, "Consolidation +of Variable Interest Entities", in which the investor is the general partner in +a limited partnership or functional equivalent. The EITF consensus is that the +general partner in a limited partnership is presumed to control that limited +partnership regardless of the extent of the general partner's ownership +interest and, therefore, should include the limited partnership in its +consolidated financial statements unless the limited partners have substantive +participating or kick-out rights. Pursuant to the partnership agreements the +presumption of control by the Company, the general partner, is overcome because +the investor partners have substantive ability to dissolve (liquidate) the +limited partnership or otherwise remove the general partner through substantive +kick-out rights that can be exercised by a vote of simple majority of the +investor partner units not held by the general partners without having to show +cause. On the basis of this assessment, the partnership interests of the +Company continue to be proportionately consolidated as disclosed above. +41 +On April 4, 2005, the FASB issued FASB Staff Position (FSP) FAS 19-1 "Accounting for +Suspended Well Costs." This staff position amends FASB Statement No. 19 +"Financial Accounting and Reporting by Oil and Gas Producing Companies" and +provides guidance about exploratory well costs to companies which use the +successful efforts method of accounting. The position states that exploratory +well costs should continue to be capitalized if: 1) a sufficient quantity of +reserves are discovered in the well to justify its completion as a producing +well and 2) sufficient progress is made in assessing the reserves and the +well's economic and operating feasibility. If the exploratory well costs do +not meet both of these criteria, these costs should be expensed, net of any +salvage value. Additional annual disclosures are required to provide +information about management's evaluation of capitalized exploratory well +costs. In addition, the FSP requires annual disclosure of: 1) net changes from +period to period of capitalized exploratory well costs for wells that are +pending the determination of proved reserves, 2) the amount of exploratory well +costs that have been capitalized for a period greater than one year after the +completion of drilling and 3) an aging of exploratory well costs suspended for +greater than one year with the number of wells it related to. Further, the +disclosures should describe the activities undertaken to evaluate the reserves +and the projects, the information still required to classify the associated +reserves as proved and the estimated timing for completing the evaluation. The +Company adopted (FSP) FAS 19-1 during the third quarter of 2005. The +application of this FSP did not have a significant impact on the Company's +financial position or results of operations. +Recently Issued Accounting Standards +On December 16, 2004, the FASB +issued SFAS No. 123(R) "Accounting for Share-Based Payments" and +has issued several subsequent Staff Positions clarifying this guidance. +This guidance replaced previously existing requirements under SFAS No. 123 +and APB No. 25. Under SFAS No. 123(R), an entity must recognize +the compensation cost related to employee services received in exchange for all +forms of share-based payments to employees, including employee stock options, +as an expense in its income statement. The compensation cost of awards +will generally be measured based on the grant-date fair value of the +award. The Company will be required to adopt SFAS No. 123(R) in the +first quarter of 2006. The Company intends to use the modified +prospective method for adoption of SFAS No. 123(R) as permitted by the +guidance. +The Company has determined that the +impact of SFAS No. 123(R) and related guidance will not be material to its +financial statements. In accordance with SFAS No. 123, the Company +has historically disclosed the impact on the Company's net income and earnings +per share had the fair value based method been adopted. Had the Company +adopted SFAS No. 123(R) in prior periods, the impact of that standard on +periods presented in these Consolidated Financial Statements would have +approximated the impact of SFAS No. 123 as described in the disclosure of +pro forma net income and earnings per share presented in Note 1. +In December +2004, the FASB issued FAS 153, "Exchange of Nonmonetary Assets", an +amendment of APB Opinion 29, "Accounting for Nonmonetary Transactions". +This amendment eliminates the exception for nonmonetary exchanges of similar +productive assets and replaces it with a general exception for exchanges of +nonmonetary assets that do not have commercial substance. Under FAS 153, if a +nonmonetary exchange of similar productive assets meets a commercial-substance +criterion and fair value is determinable, the transaction must be accounted for +at fair value resulting in recognition of any gain or loss. This statement is +effective for nonmonetary transactions in fiscal periods that begin after June 15, 2005. The adoption of this statement will not have a material impact on our +results of operations or financial position. +In June 2005, the +FASB issued SFAS No. 154, "Accounting Changes and Error Corrections" +- a replacement of APB Opinion No. 20 and FASB Statement No. 3, which replaces +Accounting Principles Board Opinion No. 20, "Accounting Changes", and +SFAS No. 3, "Reporting Accounting Changes in Interim Financial Statements", +and changes the requirements for the accounting for and reporting of a change +in accounting principle. SFAS No. 154 requires retrospective application for +voluntary changes in accounting principle unless it is impracticable to do so, +and it applies to all voluntary changes in accounting principle. It also +applies to changes required by an accounting pronouncement in the unusual +instance that the pronouncement does not include specific transition +provisions. When a pronouncement includes specific transition provisions, those +provisions should be followed. SFAS No. 154 is effective for accounting changes +and corrections of errors made in fiscal years beginning after December 15, 2005. Consequently, we will adopt the provisions of SFAS 154 for our fiscal +year beginning January 1, 2006. We currently believe that adoption of the +provisions of SFAS No. 154 in 2006 will not have a material impact on our +consolidated financial statements. +Item 7A. Quantitative and Qualitative Disclosure About +Market Risk . +Market-Sensitive Instruments and Risk Management +The Company's +primary market risk exposures are interest rate risk and commodity price risk. +These exposures are discussed in detail below: +42 +Interest Rate Risk +The Company's +exposure to market risk for changes in interest rates relates primarily to the +Company's interest-bearing cash and cash equivalents and long-term debt. +Interest-bearing cash and cash equivalents includes money market funds, +certificates of deposit and checking and savings accounts with various banks. +The amount of interest-bearing cash and cash equivalents as of December 31, 2005 is $68.5 million with an average interest rate of 3.5%. As of December 31, 2005, the Company had long-term debt of $24,000,000 subject to a prime interest +rate of 7.25%. +Commodity Price Risk +The Company utilizes commodity based +derivative instruments to manage a portion of its exposure to price risk from +its oil and natural gas sales and marketing activities. These instruments +consist of NYMEX-traded natural gas futures contracts and option contracts for +Appalachian and Michigan production, Panhandle-based contracts traded by BNP +Paribas and NYMEX-traded contracts for NECO production and CIG-based contracts +traded by JP Morgan for other Colorado production. These derivative instruments +have the effect of locking in for specified periods (at predetermined prices or +ranges of prices) the prices the Company will receive for the volume to which +the derivative relates and, in the case of RNG, the cost of gas supplies +purchased for marketing activities. As a result, while these derivatives are +structured to reduce the Company's exposure to changes in price associated with +the derivative commodity, they also limit the benefit the Company might +otherwise have received from price changes associated with the derivative commodity. +Riley Natural Gas also enters into fixed-price physical purchase and sale +agreements that are derivative contracts. The Company's policy prohibits the +use of oil and natural gas future and option contracts for speculative +purposes. +The +following tables summarize the open derivative and fixed-price purchase and +sale contracts for Riley Natural Gas and Petroleum Development Corporation as +of December 31, 2005 and 2004. +Riley Natural Gas +Open Derivative Positions +Quantity +Weighted +Total Contract +Commodity +Type +Gas-Mmbtu +Average Price +Amount +Fair Value +Total +Positions as of December 31, 2005 +Natural Gas +Cash Settled +Futures/Swaps Purchases +1,025,500 +$ 9.05 +$9,283,010 +$ 1,983,352 +Natural Gas +Cash Settled +Futures/Swaps Sales +3,149,000 +$ 7.95 +$25,018,610 +$ (8,688,840) +Natural Gas +Cash Settled +Basis Swap Purchases +450,000 +$ 0.91 +$409,500 +$ (157,663) +Natural Gas +Cash Settled +Basis Swap Sales +240,000 +$ 0.50 +$120,000 +$ 3,700 +Natural Gas +Physical +Purchases +2,819,000 +$ 8.32 +$23,456,726 +$ 7,858,489 +Natural Gas +Physical Sales +585,222 +$ 10.72 +$6,272,822 +$ (670,419) +Natural Gas +Physical Basis +Purchases +240,000 +$ 0.45 +$108,000 +$ 8,300 +Natural Gas +Physical Basis +Sales +450,000 +$ 0.94 +$420,750 +$ 168,913 +43 +Positions +maturing in 12 months following December 31, 2005 +Natural Gas +Cash Settled +Futures/Swaps Purchases +1,025,500 +$ 9.05 +$9,283,010 +$ 1,983,352 +Natural Gas +Cash Settled +Futures/Swaps Sales +2,709,000 +$ 8.12 +$21,991,390 +$ (7,185,253) +Natural Gas +Cash Settled +Basis Swap Purchases +450,000 +$ 0.91 +$409,500 +$ (157,663) +Natural Gas +Cash Settled +Basis Swap Sales +220,000 +$ 0.50 +$110,000 +$ 4,900 +Natural Gas +Physical +Purchases +2,379,000 +$ 8.71 +$20,717,126 +$ 5,966,998 +Natural Gas +Physical Sales +585,222 +$ 10.72 +$6,272,822 +$ (670,419) +Natural Gas +Physical Basis +Purchases +220,000 +$ 0.45 +$99,000 +$ 6,100 +Natural Gas +Physical Basis +Sales +450,000 +$ 0.94 +$420,750 +$ 168,913 +Prior Year +Total Positions as of December 31, 2004 +Natural Gas +Cash Settled +Sale +3,260,000 +$ 5.60 +$18,249,250 +$ (1,982,964) +Natural Gas +Cash Settled +Purchase +1,130,000 +$ 6.77 +$7,644,540 +$ (486,490) +Natural Gas +Cash Settled +Sale Option +530,000 +$ 5.30 +- +$ 134,242 +Natural Gas +Cash Settled +Purchase Option +265,000 +$ 7.00 +- +$ (85,541) +Natural Gas +Physical +Contract Sale +1,136,230 +$ 6.96 +$7,908,865 +$ 1,268,721 +Natural Gas +Physical +Contract Purchase +3,223,000 +$ 5.82 +$18,747,564 +$ 1,882,984 +The maximum +term for the derivative contracts listed above is 34 months. +Petroleum Development Corporation +Open Derivative Positions +Quantity +Gas-Mmbtu +Weighted +Total Contract +Commodity +Type +Oil-Barrels +Average Price +Amount +Fair Value +Total +Positions as of December 31, 2005 +Natural Gas +Cash Settled +Option Sales +5,665,000 +$8.17 +$46,273,550 +$ (12,531,796) +Natural Gas +Cash Settled +Option Purchases +14,030,000 +$6.36 +$89,210,000 +$ 2,660,289 +Positions +maturing in 12 months following December 31, 2005 +Natural Gas +Cash Settled +Option Sales +4,930,000 +$8.07 +$39,802,550 +$ (10,411,106) +Natural Gas +Cash Settled +Option Purchases +12,560,000 +$6.38 +$80,165,000 +$ 2,251,533 +Prior Year +Total Positions as of December 31, 2004 +Natural Gas +Purchase +120,000 +$6.63 +$796,150 +$ (45,680) +Natural Gas +Sale Option +7,400,000 +$4.46 +- +$ 917,553 +Natural Gas +Purchase +Option +3,475,000 +$5.42 +- +$ (3,138,210) +Crude Oil +Sale Option +360,000 +$32.30 +- +$ 306,702 +Crude Oil +Purchase +Option +180,000 +$40.00 +- +$ (973,638) +The maximum +term for the derivative contracts listed above is 15 months. +In addition to including the gross assets +and liabilities related to the Company's share of oil and gas production, the +above tables and the accompanying consolidated balance sheets include the gross +assets and liabilities related to derivative contracts entered into by the +Company on behalf of the affiliate Partnerships as the Managing General +Partner. The accompanying consolidated balance sheets include the negative fair +value of derivatives and a corresponding receivable from the Partnerships of +$5,351,500 as of December 31, 2005 and $1,418,000 as of December 31, 2004. In +addition to the short-term fair value of derivatives shown on the accompanying +consolidated balance sheets there are long-term assets and long-term +liabilities which total to a net long-term liability of approximately +$1,323,100 as of December 31, 2005 and which total a net long-term asset of +approximately $1,248,000 as of December 2004, respectively related to the fair +value of derivatives included in accompanying balance sheets. +By using derivative financial +instruments to manage exposures to changes in interest rates and commodity +prices, the Company exposes itself to credit risk and market risk. Credit risk +is the failure of the counterparty to perform under the terms of the derivative +contract. When the fair value of a derivative contract is positive, the +counterparty owes the Company, which creates repayment risk. The Company +minimizes the credit or repayment risk in derivative instruments by entering +into transactions with high-quality counterparties. There were no counterparty +defaults during the years ended December 31, 2005, 2004 and 2003. +44 +The average NYMEX closing prices for +natural gas for the years 2005, 2004, and 2003 were $8.62 Mmbtu, $6.14 Mmbtu, +and $5.39 Mmbtu. The average NYMEX closing prices for oil for the years 2005, +2004 and 2003 were $55.34 bbl, $41.44 bbl and $30.98 bbl. Future near-term gas +prices will be affected by various supply and demand factors such as weather, +government and environmental regulation and new drilling activities within the +industry. +Disclosure of Limitations +Because the +information above incorporates only those exposures that exist at December 31, 2005, it does not consider those exposures or positions which could arise +after that date. As a result, the Company's ultimate realized gain or loss with +respect to interest rate and commodity price fluctuations will depend on the +exposures that arise during the period, the Company's hedging strategies at the +time, and interest rates and commodity prices at the time. +Item 8. Financial Statements and Supplementary Data +The response to this +Item is set forth herein in a separate section of this Report, beginning on +Page F-1. +Item +9. Changes in and Disagreements with Accountants on Accounting and +Financial Disclosure. +None. +Item 9A. Controls and Procedures +(a) +Evaluation +of Disclosure Controls and Procedures +The Company has evaluated, +under the supervision and with the participation of the Company's management, +including the Company's Chief Executive Officer, President and Chief Financial +Officer, the effectiveness of the design and operations of the Company's +disclosure controls and procedures pursuant to Securities Exchange Act of 1934, +as amended (the Exchange Act) Rules 13a-15(e) and 15-d-15(e) as of December 31, 2005. In the course of the evaluation, the Company considered the material +weaknesses in the Company's internal control over financial reporting and other +internal control matters discussed below and has concluded that the Company did +not maintain effective disclosure controls and procedures as of December 31, 2005. +(b) +Changes +and Remediation in the Company's Internal Control Over Financial Reporting +There have not been any changes in the +Company's internal control over financial reporting (as such term is defined in +Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934) during +the most recent fiscal quarter that have materially affected or are reasonably +likely to materially affect the Company's internal control over financial +reporting, except for changes in the fourth quarter of 2005 as noted below. +• +The +Company has increased the Company's technical expertise through development of +training programs and acquiring accounting research software during the fourth +quarter of 2005. Training will be on-going, however programs provided during +2005 included oil and gas accounting, general accounting and SEC financial +reporting. +• +The +Company has enhanced the documentation of the Company's policies and procedures +and related templates and analyses that support the Company's application of +accounting principles in the several areas, including derivative accounting, +oil and gas properties, and asset retirement obligations during the fourth +quarter of 2005. +In addition, during the third +quarter of fiscal 2005 and subsequently in 2006 the Company made the following +changes and remediation: +At the direction of the +Company's board of directors and audit committee, the Company has spent and +continues to spend a significant amount of time and resources to improve the +Company's control environment. The Company is committed to instilling strong +internal control policies and procedures and ensuring that the "tone at the +top" fully supports accuracy and completeness in all financial reporting. In +support of this position, the Company's progress toward improving internal +control over financial reporting has been openly communicated with the +Company's Audit Committee, and the Company has undertaken to improve the design +and effectiveness of the Company's internal control over financial reporting. +The initiatives developed by the Company were both organizational and process +focused. Organizational changes made during 2005 and through the date of this +filing include, among others: +45 +• +The +Company has enhanced the corporate accounting and reporting functions in the +third quarter of 2005 by creating and filling several new positions with +professionals highly experienced in oil and gas accounting. Two new +professionals hold degrees in accounting and are Certified Public Accountants. +One additional Certified Public Accountant was hired in early 2006, and a financial +reporting director will be hired during 2006. +• +The +Company engaged a team of highly experienced advisors in early 2006 to assist +with various accounting research, projects and monitoring activities. They +assist the Company with accounting and reporting issues including, but not +limited to, derivatives, oil and gas activities, new accounting standards or +rules, SEC reporting and on-going monitoring of changes that may impact the +Company's application of accounting principles. +• +The +Company has strengthened its Sarbanes-Oxley Act Section 404 compliance department through the addition of a +leadership position and other experienced resources in the third quarter of +2005. The Company believes the strengthening of this department will +significantly improve the design, effectiveness and monitoring of internal +control over financial reporting. +The Company has also +implemented or is planning to implement several process changes to improve the +documentation supporting certain accounting and reporting activities as well as +to improve the documentation of the Company's application of accounting +principles. +• +The +Company has evaluated and selected a third-party integrated oil and gas +accounting software system, which the Company plans to implement during 2006. +The Company believes the +measures taken to date and planned for the future will address the reported +material weaknesses and intends to complete the remediation efforts during +2006. In addition, the Company will continue to develop and implement other initiatives +during 2006 that will further improve both the effectiveness and efficiency of +the Company's internal control over financial reporting. +(c) +Management's +Report on Internal Control Over Financial Reporting +The Company's management is +responsible for establishing and maintaining adequate internal control over +financial reporting, as that term is defined under Rule 13a-15(f) promulgated +under the Exchange Act. In order to evaluate the effectiveness of the +Company's internal control over financial reporting as of December 31, 2005, as required by Section 404 of the Sarbanes-Oxley Act of 2002, management conducted +an assessment, including testing, using the criteria set forth in Internal +Control - Integrated Framework issued by the committee of Sponsoring +Organization of the Treadway Commission (the "COSO Framework"). Because of +inherent limitations, internal control over financial reporting may not prevent +or detect misstatements. In addition, 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 the degree of compliance +with policies or procedures may deteriorate. +A material weakness is a +control deficiency, or combination of control deficiencies, that results in +more than a remote likelihood that a material misstatement of the annual or +interim financial statements will not be prevented or detected. The Company's +assessment as of December 31, 2005, identified the following material +weaknesses: +The Company did not have +effective policies and procedures, and was not adequately staffed with +accounting personnel possessing an appropriate level of technical expertise in +U.S. generally accepted accounting principles, as further described below: +• +The Company +did not have effective policies and procedures, or personnel with sufficient +technical expertise, to properly account for derivative transactions in +accordance with generally accepted accounting principles. Specifically, the +Company's policies and procedures relating to derivatives transactions were not +designed effectively to ensure that each of the requirements for hedge +accounting was evaluated appropriately with respect to the Company's commodity +based derivatives. Additionally, the Company's policies and procedures relating +to the derivative transactions entered into on behalf of affiliated +partnerships were not adequate to ensure these transactions were recorded +properly in the financial statements. +As a result, a misstatement was identified in the fair value of derivatives and +the oil and gas price risk management loss accounts that was corrected prior to +the issuance of the Company's 2005 consolidated financial statements. This deficiency results in more than a remote likelihood +that a material misstatement of the Company's annual or interim consolidated +financial statements would not be prevented or detected. +46 +• +The +Company did not have effective policies and procedures, or personnel with +sufficient technical expertise, to ensure compliance with appropriate +accounting principles for its oil and gas properties. Specifically, the +Company's policies and procedures were not designed effectively to ensure that +the calculation of depreciation and depletion and the determination of impairments +were performed in accordance with the applicable authoritative accounting +guidance. As a result, +misstatements were identified in the accumulated depreciation, depletion and +amortization and the depreciation, depletion and amortization expense accounts +that were corrected prior to the issuance of the Company's 2005 consolidated +financial statements. This deficiency results in more +than a remote likelihood that a material misstatement of the Company's annual +or interim consolidated financial statements would not be prevented or +detected. +• +The +Company did not have effective policies and procedures, or personnel with +sufficient technical expertise, to ensure proper accounting and disclosure for +income taxes. Specifically, the Company's policies and procedures did not +provide for appropriate control documentation or supervisory review of +permanent and temporary differences, or assessment of tax reserves to ensure +that they were properly reflected and disclosed in the Company's financial +statements. As a result, +misstatements were identified in the deferred income tax liability and income +tax expense accounts that were corrected prior to the issuance of the Company's +2005 consolidated financial statements. This +deficiency results in more than a remote likelihood that a material +misstatement of the Company's annual or interim consolidated financial +statements would not be prevented or detected. +• +The +Company did not have effective policies and procedures, or personnel with +sufficient technical expertise, to ensure that its accounting for asset +retirement obligations complied with generally accepted accounting principles. +Specifically, the Company's policies and procedures regarding the estimate of +the fair value of the asset retirement obligations were not designed +effectively to ensure that it was estimated in accordance with FAS No. 143, Asset +Retirement Obligations . This deficiency results in more than a remote +likelihood that a material misstatement of the Company's annual or interim +consolidated financial statements would not be prevented or detected. +• +The +Company did not have effective policies and procedures, or personnel with +sufficient technical expertise, to provide for adequate monitoring and +assessment of the application of accounting principles, standards or rules as it +relates to proportionate consolidation in a timely manner. As a result of this +control deficiency, the Company did not appropriately eliminate its proportionate share of transactions with +the Company sponsored limited partnerships, which resulted in the restatement +of the Company's financial statements for the first three quarters of 2005, the +years ended December 31, 2004, 2003, 2002, and 2001 and each of the quarters in +2004 and 2003. +Management has concluded +that, as a result of the material weaknesses noted above, the Company did not +maintain effective internal control over financial reporting as of December 31, 2005 based on criteria set forth in the COSO Framework. +The Company's independent +registered public accounting firm, KPMG LLP, has issued an audit report on +management's assessment of the Company's internal control over financial +reporting as of December 31, 2005. Their report follows this section of the +Form 10-K. +47 +Report of +Independent Registered Public Accounting Firm +The Board of Directors and Stockholders +Petroleum Development Corporation: +We have audited management's assessment, included in +the accompanying Management's Report on Internal Control Over Financial +Reporting (Item 9A(c)), that Petroleum Development Corporation (the Company) +did not maintain effective internal control over financial reporting as of December 31, 2005 because of the effect of the material weaknesses identified in +management's assessment based on criteria established in Internal +Control-Integrated Framework issued by the Committee of Sponsoring +Organizations of the Treadway Commission (COSO). 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 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. +A +material weakness is a control deficiency, or combination of control +deficiencies, that results in more than a remote likelihood that a material +misstatement of the annual or interim financial statements will not be +prevented or detected. Management has identified and included in its assessment +the following material weaknesses as of December 31, 2005: +The +Company did not have effective policies and procedures, and was not adequately +staffed with accounting personnel possessing an appropriate level of technical +expertise in U.S. generally accepted accounting principles, as further +described below: +The Company +did not have effective policies and procedures, or personnel with +sufficient technical expertise, to properly account for derivative +transactions in accordance with generally accepted accounting principles. +Specifically, the Company's policies and procedures relating to +derivatives transactions were not designed effectively to ensure that each +of the requirements for hedge accounting was evaluated appropriately with +respect to the Company's commodity based derivatives. Additionally, the +Company's policies and procedures relating to the derivative transactions +entered into on behalf of affiliated partnerships were not adequate to ensure +these transactions were recorded properly in the financial statements. As +a result, a misstatement was identified in the fair value of derivatives +and the oil and gas price risk management loss accounts in the Company's +2005 preliminary consolidated financial statements. This deficiency results in more than a remote +likelihood that a material misstatement of the Company's annual or interim +consolidated financial statements would not be prevented or detected. +48 +The +Company did not have effective policies and procedures, or personnel with +sufficient technical expertise, to ensure compliance with appropriate +accounting principles for its oil and gas properties. Specifically, the +Company's policies and procedures were not designed effectively to ensure +that the calculation of depreciation and depletion and the determination +of impairments were performed in accordance with the applicable authoritative +accounting guidance. As a result, misstatements were identified in the +accumulated depreciation, depletion and amortization and the depreciation, +depletion and amortization expense accounts in the Company's preliminary 2005 +consolidated financial statements. This +deficiency results in more than a remote likelihood that a material +misstatement of the Company's annual or interim consolidated financial +statements would not be prevented or detected. +The +Company did not have effective policies and procedures, or personnel with +sufficient technical expertise, to ensure proper accounting and disclosure +for income taxes. Specifically, the Company's policies and procedures did +not provide for appropriate control documentation or supervisory review of +permanent and temporary differences, or assessment of tax reserves to +ensure that they were properly reflected and disclosed in the Company's +financial statements. As a result, misstatements were identified in the +deferred income tax liability and income tax expense accounts in the +Company's preliminary 2005 consolidated financial statements. This deficiency results in more than a remote +likelihood that a material misstatement of the Company's annual or interim +consolidated financial statements would not be prevented or +detected. +The +Company did not have effective policies and procedures, or personnel with +sufficient technical expertise, to ensure that its accounting for asset +retirement obligations complied with generally accepted accounting +principles. Specifically, the Company's policies and procedures regarding +the estimate of the fair value of the asset retirement obligations were +not designed effectively to ensure that it was estimated in accordance +with FAS No. 143, Asset Retirement Obligations. This deficiency results in more than a remote +likelihood that a material misstatement of the Company's annual or interim +consolidated financial statements would not be prevented or detected. +The +Company did not have effective policies and procedures, or personnel with sufficient +technical expertise, to provide for adequate monitoring and assessment of +the application of accounting principles, standards or rules as it relates +to proportionate consolidation in a timely manner. As a result of this control deficiency, the Company did not +appropriately eliminate its proportionate share of transactions +with the Company sponsored limited partnerships, which resulted in the +restatement of the Company's financial statements for the first three +quarters of 2005, the years ended December 31, 2004, 2003, 2002, and 2001 and each of the quarters in 2004 and 2003. +We also have audited, in accordance with the standards +of the Public Company Accounting Oversight Board (United States), the +consolidated balance sheets of Petroleum Development Corporation and +subsidiaries as of December 31, 2005 and 2004, and the related consolidated +statements of income, stockholders' equity and cash flows for each of the years +in the three-year period ended December 31, 2005. The aforementioned material weaknesses were considered in determining the nature, timing and extent of +audit tests applied in our audit of the 2005 consolidated financial statements, and this report does not affect our report dated +May 24, 2006, which expressed an unqualified opinion on those consolidated +financial statements. +In our opinion, management's assessment that Petroleum +Development Corporation did not maintain 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 (COSO). Also, in our opinion, because of the effect of the +material weaknesses described above on the achievement of the objectives of the +control criteria, Petroleum Development Corporation did not maintain 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 (COSO). +KPMG LLP +Pittsburgh, Pennsylvania +May 24, 2006 +49 +Item +9B. Other Information +None. +PART III +Item +10. Directors and Executive Officers of the Company +Directors and Executive Officers of the Company +The executive officers and directors of the +Company, their principal occupations for the past five years and additional +information are set forth below: +Name +Age +Positions and Offices Held +Held Current +Position Since +Steven R. Williams +55 +Chairman and Chief Executive Officer, +and Director +January 2004 +March 1983 +Thomas E. Riley +53 +President +Director +December 2004 +January 2004 +Darwin L. Stump +51 +Chief Financial Officer and Treasurer +November 2003 +Eric R. Stearns +48 +Executive Vice President Exploration and Production +December 2005 +Gregory A. Morgan +47 +Secretary +September 2004 +Vincent F. D'Annunzio +54 +Director +February 1989 +Jeffrey C. Swoveland +51 +Director +March 1991 +Donald B. Nestor +57 +Director +March 2000 +Kimberly Luff Wakim +47 +Director +January 2003 +David C. Parke +39 +Director +November 2003 +Steven R. Williams was elected Chairman and Chief +Executive Officer in January 2004. Mr. Williams served as President from March +1983 until December 2004 and has been a Director of the Company since March +1983. +Thomas E. Riley was elected Director in January 2004 by +the Board of Directors and assumed the position of President in December 2004. +Previously Mr. Riley was appointed Executive Vice President of Production, +Natural Gas Marketing and Business Development in November 2003. Prior thereto, +Mr. Riley served as Vice President Gas Marketing and Acquisitions of the +Company since April 1996. Prior to joining the Company, Mr. Riley was president +of Riley Natural Gas Company, a natural gas marketing company which the Company acquired in April 1996. +Darwin L. Stump was appointed Chief Financial Officer and +Treasurer in November 2003. Mr. Stump has been an officer of the Company since +April 1995 and held the position of Corporate Controller since 1980. Mr. Stump, +a CPA, was a senior accountant with Main Hurdman, Certified Public Accountants +prior to joining the Company. +Eric R. Stearns was appointed Executive Vice President of +Exploration and Production in December 2005. Prior to that he was Executive +Vice President of Exploration and Development since November 2003, having +previously served as Vice President of Exploration and Development since April +1995. Mr. Stearns joined the Company as a geologist in 1985 after working for Hywell, +Incorporated and for Petroleum Consultants. +Gregory A. Morgan has been a member of the law firm of +Young, Morgan & Cann, Clarksburg, West Virginia since 1986. Mr. Morgan is +not active in the day-to-day business of the Company, but his law firm provides +legal services to the Company. +Vincent F. D'Annunzio has served as president of Beverage +Distributors, Inc. located in Clarksburg, West Virginia since 1985. +Jeffrey C. Swoveland has served as Chief Financial +Officer of Body Media since September, 2000. Prior thereto, Mr. Swoveland was +Vice President-Finance and Treasurer of Equitable Resources, Inc. since 1994. +Donald B. Nestor is a Certified Public Accountant and a +Partner in the CPA firm of Toothman Rice, P.L.L.C. and is in charge of the +firm's Buckhannon, West Virginia office. Mr. Nestor has served in that +capacity since 1975. +50 +Kimberly Luff Wakim, an Attorney and Certified Public +Accountant, is a Partner with the law firm Thorp, Reed & Armstrong LLP. +Ms. Wakim joined Thorp Reed & Armstrong LLP in 1990. +David C. Parke was elected Director by the Board of +Directors in November 2003. In 2003, Mr. +Parke joined Mufson/Howe/Hunter & Company LLC, an investment banking firm +as a founder and Director. From 1992-2003, Mr. Parke was with the corporate +finance department of Investec, Inc. and its predecessor Pennsylvania Merchant +Group Ltd., investment banking companies. Prior to joining Pennsylvania +Merchant Group, Mr. Parke served in the corporate finance departments of Wheat +First Butcher & Singer, now part of Wachovia Securities, and Legg Mason, +Inc. +The Company's By-Laws +provide that the directors of the Company shall be divided into three classes +and that, at each annual meeting of stockholders of the Company, successors to +the class of directors whose term expires at the annual meeting will be elected +for a three-year term. The classes are staggered so that the term of one class +expires each year. Mr. Williams, Mr. Nestor and Ms. Wakim are members of the +class whose term expires in 2006. Mr. D'Annunzio and Mr. Riley are members of +the class whose term expires in 2007. Mr. Swoveland and Mr. Parke are members +of the class whose term expires in 2008. There is no family relationship between +any director or executive officer and any other director or executive officer +of the Company. There are no arrangements or understandings between any +director or officer and any other person pursuant to which the person was +selected as an officer. +On January 24, 2003, the Company adopted a Code of Business Conduct and Ethics Policy meeting the +specified standards applicable to the Chief Executive Officer and Chief +Financial Officer. The policy also covers all the corporate officers. The +policy is posted on the Company's website at www.petd.com. The Company will provide a copy of the +Code to any person, without charge, upon request to the Company's Secretary at +the Company's principal executive offices or by telephone at 800-624-3821. +The Company has determined that all of +its directors, other than Messrs. Williams and Riley are independent under +NASDAQ rule 4200. +The Audit Committee +of the Board of Directors is comprised entirely of independent directors as +defined by the NASDAQ rule 4200(a)(15). Donald B. Nestor, CPA, a partner in +the certified public accounting firm of Toothman Rice PLLC, chairs the +committee; other audit committee members are Mr. Jeffrey C. Swoveland and Ms. +Kimberly Luff Wakim. The Board of Directors has determined that Mr. Nestor and +the other Audit Committee members qualify as audit committee financial experts +and are independent of management. +The Nominating and +Governance and Compensation Committees are also comprised entirely of +independent directors of the Company. Vincent F. D'Annunzio chairs the +Nominating and Governance Committee, and David C. Parke chairs the Compensation +Committee. +The independent +directors conduct meetings without the presence of management at each scheduled +Board meeting. Kimberly Luff Wakim serves as Chairperson of these meetings +having been selected as lead independent director by the Board. +Shareholders wishing +to communicate with the Board of Directors or a committee may do so by writing +to the attention of the Board or Committee at the corporate headquarters or by +emailing the Board at board@petd.com, with "Board" or appropriate +committee in the subject line. +51 +Item 11. Executive Compensation +Summary +Compensation Table +The following table sets forth in summary form the compensation +received during each of the Company's last three fiscal years by the Chief +Executive Officer and by each other executive officer of the Company whose +salary and bonus exceeded $100,000 in 2005 (the "Named Executives"). +Annual Compensation +Long +Term Compensation +Other +Restricted +Securities +Annual +Stock +underlying +All +Other +Name +and +Bonus +Compen- +Awards +Options +Compen- +Principal +Position +Year +Salary($) +(1)($) +sation($)(2) +($)(3) +(#)(4) +sation($)(5) +Steven +R. Williams +2005 +318,000 +271,597 +11,886 +- +- +146,666 +Chief +Executive Officer +2004 +300,000 +300,000 +37,567 +302,030 +5,870 +135,834 +and Director +2003 +166,485 +1,312,385 +6,241 +- +- +101,726 +Thomas +E. Riley +2005 +252,000 +141,135 +4,638 +- +- +106,666 +President +2004 +240,000 +140,000 +5,624 +200,239 +3,890 +100,834 +and Director +2003 +153,400(6) +121,370 +1,565 +- +- +21,726 +Eric +R. Stearns +2005 +231,000 +129,374 +11,406 +- +- +102,666 +Executive +Vice President +2004 +220,000 +140,000 +9,678 +188,796 +3,670 +97,834 +2003 +132,567(6) +121,370 +1,084 +- +- +20,726 +Darwin +L. Stump +2005 +210,000 +98,713 +9,398 +- +- +106,666 +Chief +Financial Officer +2004 +200,000 +140,000 +12,773 +177,577 +3,450 +97,834 +and Treasurer +2003 +112,733(6) +121,370 +1,074 +- +- +12,777 +(1) Includes bonuses earned in the reported fiscal year and paid +in the following fiscal year. +(2) Amounts disclosed in this column consist of use of a company +vehicle, life insurance, disability insurance, and medical reimbursement as +provided for in the Named Executive's employment contract. +(3) Amounts disclosed in this column consist of the value of +restricted stock awards based upon the closing price of our common stock on the +date of grant which was $37.15 on December 13, 2004. During 2004 the number of +shares awarded to Messrs. Williams, Riley, Stearns and Stump amounted to 8,130, +5,390, 5,080 and 4,780 shares, respectively. These shares vest in four equal +installments on the first, second, third and fourth anniversaries of the grant +date. +(4) Amounts in this column represent the number of options granted +on December 13, 2004 to the named individuals. The fair value of these options +at date of grant was $16.75 using the Black-Scholes option pricing model with +an exercise price of $37.15. These options vest in four equal installments on +the first, second, third and fourth anniversaries of the grant date. +52 +(5) This amount includes contributions made by the Company under +the Company's Employee Profit Sharing Plan and 401(k) plan. In 2005, 2004 and +2003 the Company contributed $420,000, $300,000 and $250,000, respectively, to +the Employee Profit Sharing Plan. Of the contributions for 2005 and 2004, +Messrs. Williams, Riley, Stearns and Stump were each credited $13,666 and +$9,834, respectively. Of the contributions for 2003, Messrs., Williams, Riley +and Stearns were each credited $9,726 and Mr. Stump was credited $8,634. The +Company provided a matching of 401(k) contribution based upon all employees +respective contributions. The total Company matching contributions were +$450,653, $382,700 and $305,515 in 2005, 2004 and 2003. For 2005, Messrs. +Williams, Riley and Stump were each credited with matching contributions of +$18,000, Mr. Stearns was credited with a matching contribution of $14,000. For +2004, Messrs. Williams and Riley were each credited with matching contributions +of $16,000, Messrs. Stearns and Stump were credited with matching contributions +of $13,000. For 2003, Messrs. Williams and Riley were each credited with +matching contributions of $12,000, Messrs. Stearns and Stump were credited with +matching contributions of $11,000 and $4,143, respectively. This amount also +includes retirement compensation for the named individuals which provides for +an amount per year worked under their employment agreements for 10 years +following their termination of service. The total amounts earned during 2005 +and 2004 to be paid over the ten-year period following such individuals' +termination amounted to $115,000 and $110,000, respectively for Mr. Williams, +and $75,000 for Messrs. Riley, Stearns and Stump for each year. For 2003 such +amount was $80,000 for Mr. Williams. See "Retirement Arrangements" +discussed below for a description of these arrangements. +(6) +This amount includes +compensation for Messrs. Riley, Stearns and Stump earned during 2003 while each +was an officer of the Company prior to becoming an Executive Officer in +November 2003. +Aggregated +Option Exercises in Last Fiscal Year and Fiscal Year-End Option Values +The following +table provides certain information with respect to options exercised during +2005 by the persons named in the Summary Compensation Table under the Company's +stock option plans, the number of options outstanding as of December 31, 2005 +and the year-end value of such options, with respect to options granted +pursuant to the Company's employee stock compensation plans. +Value of Unexercised +Number +Number of Options +In-The-Money Options +of Shares +Value +at Year-end +at Year-End(1)($) +Exercised +Realized ($)* +Exercisable +Unexercisable +Exercisable +Unexercisable* +Steven R. Williams +- +- +1,467 +4,403 +- +- +Thomas E. Riley +- +- +972 +2,918 +- +- +Eric R. Stearns +- +- +917 +2,753 +- +- +Darwin L. Stump +- +- +862 +2,588 +- +- +*Market value of +the underlying securities at exercise or year-end, as applicable, minus the +exercise price. +(1) On December +31, 2005, the closing sales price of the Common Stock was $33.34 per share; the +exercise price of these options is $37.15 per share. +Employment and Other Agreements and +Arrangements +The +Company entered into employment agreements with Messrs. Williams, Riley, +Stearns and Stump effective January 1, 2004. The initial term of the agreements +is for two years and they are automatically extended for an additional 12 +months beginning on the first anniversary of the effective date and on each +successive anniversary unless either party cancels. The employment agreements +provided for a base annual salary for Mr. Williams, Mr. Riley, Mr. Stearns and +Mr. Stump in the amounts of $300,000, $240,000, $220,000 and $200,000, +respectively for 2004. For 2005 the Compensation Committee established base +salaries for Mr. Williams, Mr. Riley, Mr. Stearns and Mr. Stump in the amounts +of $318,000, $252,000, $231,000 and $210,000, respectively. Each employment +agreement provides for an annual performance bonus, based upon a combination of +written objective criteria approved by the Compensation Committee, determined +prior to the beginning of each calendar year and upon the discretion of the +Compensation Committee. The maximum amounts of the entire annual performance +bonus were $300,000 for Mr. Williams and $140,000 for Messrs. Riley, Stearns +and Stump in 2004. Each of the executives earned the maximum bonus in 2004. For +2005 the Compensation Committee set maximum annual performance amounts for Mr. +Williams, Mr. Riley, Mr. Stearns and Mr. Stump of $413,400, $201,600, $184,800 +and $168,000, respectively. Bonus earned in 2005 was $271,597 for Mr. Williams, +$141,135 for Mr. Riley, $129,374 for Mr. Stearns and $98,713 for Mr. Stump. +In +the event of a change in control of the Company, each Named Executive has the +right to elect to terminate his employment under his employment agreement and +receive severance compensation equal to three times the sum of 1) his highest +base salary in the previous two years of employment plus 2) highest bonus paid +to the named Executive during the same two year period. +Each +employment agreement contains a standard non-disclosure covenant. Each +employment agreement also provides that the Named Executive is prohibited +during the term of his employment and for a period of one year following his +termination from engaging in any business that is competitive with the +Company's oil and gas drilling business. +Retirement Arrangements +The +Company provides supplemental retirement benefits under terms of the various +employment agreements with the Company's executive officers. The January 1, +2004 agreements provide for retirement benefits for each executive officer for +a ten year period following the date of termination of service. During the life +of each respective agreement, $110,000 for Mr. Williams and $75,000 for each of +Messrs. Riley, Stearns and Stump are allocated yearly to their respective +retirement account. The allocated amounts are accumulated over the life of the +respective agreements. Following termination of service the aggregate fund will +be disbursed to the individual officer in equal installments over ten years. +Mr. Williams' agreement has an escalator provision which provides an increase +in the annual contribution allocated to his retirement amount equal to $5,000 +per year. In 2004, the allocation to Mr. Williams supplemental retirement +account was $110,000; in 2005, the allocation increased to $115,000 for his +account; in 2006, the allocation will increase to $120,000. At December 31, +2005, the executive officers had accumulated the following amounts in their +respective retirement accounts, Mr. Williams $225,000; Mr. Riley $150,000; Mr. +Stearns $150,000 and Mr. Stump $150,000. These accounts will continue to +accumulate retirement funds during the terms of the respective employment +agreements. +53 +Under +his previous employment agreement, Mr. Williams also earned supplemental +retirement benefits. The prior agreement requires the Company to pay Mr. +Williams an annual sum of $40,000 per year for the ten year period following +his retirement from the Company (an aggregate of $400,000), in addition to +benefit discussed above. This benefit was fully vested on December 31, 2003. +Stock Option Plans +Under +the Company's incentive stock option plans, options to purchase shares of +Common Stock of the Company may be granted to certain officers and key +employees of the Company, which options are intended to qualify as incentive +stock options under the provisions of the Internal Revenue Code. The options +may be exercised six months after the date of grant. Options will expire ten +years from the date of grant if not exercised. A dissolution or liquidation of +the Company or a merger or consolidation in which the Company is not the +surviving corporation will cause each outstanding option to terminate, provided +that each optionee, in such event, will have the right immediately prior to +said dissolution or liquidation or merger or consolidation to exercise his +option in whole or in part without regard to any installment vesting provisions +with respect to such options. No additional options may be granted under these +earlier plans. +As +approved by the shareholders at the annual meeting in 2004, the Company has a +Long-Term Equity Compensation Plan which allows for the awarding of +Non-qualified stock options, Incentive Stock Options, Stock Appreciation +Rights, Restricted Stock, Performance shares and Performance units. The number +of shares allocated to this plan is 750,000 shares. During 2004, a total of +23,380 shares of restricted stock and 16,880 options were granted to the +executives named previously. As of April 30, 2006, 664,075 shares remain in the +plan, for future grants. +Key-Man Life Insurance +The +Company maintains key-man life insurance policies on the life of Mr. Williams +in the amount of $4.0 million, and in the amount of $1.0 million for Messrs. +Riley, Stearns and Stump. The Company is the beneficiary of each policy. +Employee 401(k) and Profit Sharing Plan +In +1987, the Company established a retirement plan qualified under Section 401(k) +of the Internal Revenue Code. The plan is funded by employee contributions and +a company matching contribution. Administrative costs of the plan are borne by +the Company. The employees choose from eight investment programs and, +therefore, the amount of an individual's plan assets depends on the amount of +their contributions and the performance by their chosen investments. +In +1992, the Company began a Profit Sharing Retirement plan to supplement the +401(k) Plan. Contributions are dependent on corporate profitability and are at +the discretion of the Board of Directors of the Company. The Company filed and +qualified the plan with the Internal Revenue Service. +Item 12. Security Ownership of Certain Beneficial +Owners and Management and Related Stockholder Matters +The following table sets forth certain information +regarding ownership of the Company's Common Stock as of April 30, 2006 by (a) +each person known by the Company to own beneficially more than 5% of the +outstanding shares of Common Stock; (b) each director of the Company; (c) each +Named Executive; (d) all directors and executive officers as a group. +54 +Beneficial Ownership (1) +Name +and Address +Number +Percent +Barclays +Global Investors, NA +45 +Fremont Street +San +Francisco, CA 94105 +2,477,121 +(2) +15.40% +Fidelity +Management +82 +Devonshire Street +Boston, MA 02109 +2,415,600 +(3) +15.00% +Kayne Anderson Rudnick +Investment Management LLC +1800 Avenue of the Stars 2nd Floor +Los Angeles, CA 90067 +1,281,289 +(4) +8.00% +Steinberg Asset Management LLC +12 East 49th Street +New York, NY 10017 +1,104,781 +(5) +6.90% +Steven +R. Williams +103 +East Main Street +Bridgeport, WV 26330 +421,101 +(6) +2.60% +Thomas +E. Riley +103 +E. Main Street +Bridgeport, WV 26330 +109,700 +(7) +* +Eric +R. Stearns +103 +E. Main Street +Bridgeport, WV 26330 +61,438 +(8) +* +Darwin +L. Stump +103 +E. Main Street +Bridgeport, WV 26330 +30,473 +(9) +* +Vincent F. D'Annunzio +18,646 +* +Jeffrey C. Swoveland +13,721 +* +Donald B. Nestor +2,522 +* +Kimberly Luff Wakim +2,965 +* +David C. Parke +2,450 +* +All +directors and executive officers as a +663,016 +4.10% +group (9 persons) +55 +* Less than 1% +(1) +Includes shares over which the +person currently holds or shares voting or investment power. Unless otherwise +indicated in the footnotes to this table, the persons named in this table have +sole voting and investment power with respect to the shares beneficially owned. +(2) +According to the Schedule 13G +filed by Barclay Global Investors, NA with the Securities and Exchange +Commission on January 26, 2006. +(3) +According to the Schedule 13G +filed by Fidelity Management with the Securities and Exchange Commission on +January 10, 2006. +(4) According to +Schedule 13G filed by Kayne Anderson Rudnick Investment Management, LLC with +the Securities and Exchange Commission on February 6, 2006. +(5) According to the +Schedule 13F-HR filed by Steinberg Asset Management, LLC with the Securities +and Exchange Commission on April 17, 2006. +(6) Mr. Williams: +includes 1,467 shares subject to options exercisable within 60 days of April +30, 2006. +(7) Mr. Riley: includes +972 shares subject to options exercisable within 60 days of April 30, 2006. +(8) Mr. Stearns: +includes 917 shares subject to options exercisable within 60 days of April 30, +2006. +(9) Mr. Stump: includes +862 shares subject to options exercisable within 60 days of April 30, 2006. +Section +16(a) Beneficial Ownership Reporting Compliance +Section 16(a) of the Exchange Act requires the +Company's officers and directors, and persons who own more than 10% of a +Company's equity securities, to file reports of ownership and changes in +ownership with the Securities and Exchange Commission. Officers, directors and +holders of more than 10% of the Common Stock are required by regulations +promulgated by the Commission pursuant to the Exchange Act to furnish the +Company with copies of all Section 16(a) forms they file. The Company assists +officers and directors, and will assist beneficial owners, if any, of more than +10% of the Common Stock, in complying with the reporting requirements of +Section 16(a) of the Exchange Act. +Based solely on its review of the copies of such +forms received by it, the Company believes that since January 1, 2005, all +Section 16(a) filing requirements applicable to its directors, officers and +greater than 10% beneficial owners were met. +The Company has the +following common stock options outstanding under the stock option plans authorized +for issuance: +Equity +Compensation Plan Information +April 30, 2006 +Plan Category +Number of securities to +be issued upon exercise +of outstanding options, +warrants and rights +(a) +Weighted-average +exercise price of +outstanding options, +warrants and rights +(b) +Number of securities +remaining available for +future issuance under +equity compensation +plans (excluding +securities reflected in +column (a)) +(c) +Equity compensation plans +approved by security holders +94,234 +$18.82 +664,075 +Equity compensation plans not +approved by security holders +0 +0 +0 +Total +94,234 +$18.82 +664,075 +Item 13. Certain Relationships and Related Transactions +During the year ended December 31, 2005, there was no transaction or +series of transactions to which we were or are a party in which the amount +involved exceeded or exceeds $60,000 and in which any director, executive +officer, holder of more than 5% of our common stock or any member of the +immediate family of any of the foregoing persons had or will have a direct or +indirect material interest. +Item 14. Principal +Accountant Fees and Services +KPMG Fees +The following +table presents the aggregate fees billed to the Company by KPMG LLP (KPMG) for +services in 2005 and 2004 as of March 31, 2006: +56 +2005 +2004 +Audit Fees +$ 1,743,010 +$ 708,524 +Audit Related +Fees +140,977 +309,127 +Total Audit +and Audit Related Fees +$1,883,987 +$1,017,651 +Tax Fees +0 +4,000 +All Other Fees +0 +0 +Total Fees +$ 1,883,987 +$ 1,021,651 +Audit +Fees +The aggregate +audit fees billed for professional services rendered by KPMG LLP for the audit +of our annual financial statements and the audit of the Company's internal +controls over financial reporting for the fiscal years ended December 31, 2005 +and 2004, including reviews of the condensed financial statements included in +our quarterly reports on Form 10-Q for the fiscal years ended December 31, 2005 +and 2004, were $1,743,010 and $708,524. +Audit Related +Fees +The aggregate of +audit related fees relating to registration statements filed with the +Securities and Exchange Commission amounted to $24,900 for the year ended +December 31, 2004. Also included as audit related fees are the annual audits of +the financial statements for the fiscal years ended December 31, 2005 and 2004 +of sixty-five and sixty-two limited partnerships, respectively, for which the +Company acts as managing general partner. The aggregate billings for those +professional services was $284,227 for the year ended December 31, 2004, the +services for the year ended December 31, 2005 have not been billed as of March +31, 2006. The total of audit related fees for the year ended December 31, 2005 +was for due diligence services provided for a contemplated transaction. +Tax Fees +Tax Fees include +tax compliance services for the fiscal year ended December 31, 2004 provided +for the partnerships formed in such year for which the Company acts as managing +general partner, in the amount of $4,000. +Pre-Approval +Policies and Procedures +The Sarbanes-Oxley +Act of 2002 requires that all services provided to the Company by its Independent +Registered Public Accounting Firm be subject to pre-approval by the Audit +Committee or authorized members of the Committee. The Audit Committee has +adopted policies and procedures for pre-approval of all audit services and +non-audit services to be provided by the Company's Independent Registered +Public Accounting Firm. Services necessary to conduct the annual audit must be +pre-approved by the Audit Committee annually at a meeting. Permissible +non-audit services to be performed by the independent accountant may also be +approved on an annual basis by the Audit Committee if they are of a recurring +nature. Permissible non-audit services to be conducted by the independent +accountant which are not eligible for annual pre-approval must be pre-approved +individually by the full Audit Committee or by an authorized Audit Committee +member. Actual fees incurred for all services performed by the independent +accountant will be reported to the Audit Committee after the services are fully +performed. The duties of the Committee are described in the Audit Committee +Charter, which is available at the Company's website under Corporate +Governance. +Item 15. Exhibits and Financial Statement Schedules +(a) (1) Financial +Statements: +See +Index to Financial Statements and Schedules on page F-1. +(2) Financial +Statement Schedules: +See +Index to Financial Statements and Schedules on page F-1. +Schedules +and Financial Statements Omitted +All other financial +statement schedules are omitted because they are not required, inapplicable, or +the information is included in the Financial Statements or Notes thereto. +(3) Exhibits: +See +Exhibits Index on page E-1. +57 +CONFORMED COPY +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. +PETROLEUM +DEVELOPMENT CORPORATION +By /s/ +Steven R. Williams +Steven R. +Williams, Chairman +May 31, 2006 +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/ Steven R. Williams +Steven R. Williams +Chairman, Chief Executive Officer and Director +May 31, 2006 +/s/ Darwin L. Stump +Darwin L. Stump +Chief Financial Officer and Treasurer +(principal financial and accounting officer) +May 31, 2006 +/s/ Thomas E. Riley +Thomas E. Riley +President and Director +May 31, 2006 +/s/ Donald B. Nestor +Donald B. Nestor +Director, Chairman of Audit Committee +May 31, 2006 +/s/ Vincent F. D'Annunzio +Vincent F. D'Annunzio +Director +May 31, 2006 +/s/ Jeffrey C. Swoveland +Jeffrey C. Swoveland +Director +May 31, 2006 +/s/ Kimberly Luff Wakim +Kimberly Luff Wakim +Director +May 31, 2006 +/s/ David C. Parke +David C. Parke +Director +May 31, 2006 +58 +Exhibits Index +(a) Exhibits +Exhibit Name +Exhibit +Number +Location +Articles of Incorporation +3.1 +Incorporated by reference to Exhibit 3.1 to Form S-2 +SEC File No. 333-36369 filed on September 25, 1997 +By Laws +3.2 +Incorporated by reference to Exhibit 3.2 to Form 8-K +SEC File No. 0-07246 filed on September 8, 2003 +Amended +and restated Credit Agreement, dated as of November 4, 2005, Petroleum Development Corporation, as borrower, and JPMorgan Chase Bank, N.A. and BNP Paribas, +as lenders. +10.1 +Incorporated by reference to Exhibit 10.2 to Form 8-K +dated November 4, 2005. +Employment Agreement with Steven R. Williams, Chief +Executive Officer and Chairman, dated as of March 7, 2003 and amended December 29, 2005 +10.2 +Incorporated by reference in Exhibit 10.2 to Form 10-K +filed on March 7, 2003 and amended by reference of Form 8-K filed January 4, 2006 +Employment Agreement with Darwin L. Stump, Chief +Financial Officer, dated as of January 5, 2004 and amended December 29, 2005 +10.3 +Incorporated by reference to Exhibit 99.4 Form 8-K +dated January 5, 2004 and Exhibit 99.4 to Form 8-K dated January 4, 2006 +Employment Agreement with Thomas E. Riley, President, +dated as of January 5, 2004 and amended December 29, 2005 +10.4 +Incorporated by reference to Exhibit 99.6 Form 8-K +dated January 5, 2004 and Exhibit 99.2 to Form 8-K dated January 4, 2006 +Employment Agreement with Eric R. Stearns, Executive +Vice President, dated as of January 5, 2004 and amended December 29, 2005 +2005 Non-Employee Director Restricted Stock Plan +10.5 +10.6 +Incorporated by reference to Exhibit 99.5 Form 8-K +dated January 5, 2004 and Exhibit 99.3 to Form 8-K dated January 4, 2006. +Incorporated by reference to Exhibit 99.1 to Form S-8, +SEC file No. 333-126444 filed on July 7, 2005 +2004 Long-Term Equity Compensation Plan +10.7 +Incorporated by reference to Exhibit 99.1 to Form S-8, +SEC File No. 333-118215, filed on August 13, 2004 +Non-Employee Director Deferred Compensation Plan +10.8 +Incorporated by reference Exhibit 99.1 to Form S-8, SEC +File No. 333-118222, filed on August 13, 2004 +1999 Incentive Stock Option and Non-Qualified Stock +10.9 +Incorporated by reference to Exhibit 99.1 to form S-8, +SEC File No. 333-111825, filed on January 9, 2004 +1997 Employee Incentive Stock Option Plan +10.10 +Incorporated by reference to Exhibit 99.1 to Form S-8, +SEC File No. 333-111824, filed on January 9, 2004 +Tom Carpenter Employment Agreement Stock Option Plan +10.11 +Incorporated by reference to Exhibit 99.1 to Form S-8, +SEC File No. 333-111823, filed on January 9, 2004 +Code of Business Conduct and Ethics +14 +Incorporated by reference to Exhibit 3.1 to +Form 10-K for the year ended December 31, 2002, SEC File No. 0-07246 filed on March 7, 2003 +Subsidiaries +21 +Riley Natural Gas Company, a West Virginia Corporation +21 +PDC Securities Incorporated, a West Virginia Corporation +Consent of Independent Registered Public Accounting +Firm +23.1 +Filed herewith. +Consent of Independent Petroleum Engineers +Consent of Independent Petroleum Engineers +23.2 +23.3 +Filed herewith. +Filed herewith +Rule 13a-14(a)/15d-14(a) Certification by Chief +Executive Officer +31.1 +Filed herewith. +Rule 13a-14(a)/15d-14(a) Certification by Chief +Financial Officer +31.2 +Filed herewith. +Title 18 U.S.C. Section 1350 (Section 906 of +Sarbanes-Oxley Act of 2002) Certifications by Chief Executive Officer and +Chief Financial Officer +32.1 +Filed herewith. +59 +GLOSSARY OF TERMS +The following +are abbreviations and definitions of terms commonly used in the oil and gas +industry and this Form 10-K. +Bbl . One barrel, or 42 U.S. gallons of liquid volume. +Bcf . One billion cubic feet. +Bcfe . One billion cubic feet of natural +gas equivalents. +Completion . The installation of permanent +equipment for the production of oil or gas. +Credit +Facility. A line +of credit provided by a group of banks, secured by oil and gas properties. +DD&A. Refers to depreciation, depletion +and amortization of the Company's property and equipment. +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 hydrocarbons in sufficient quantities to justify +completion as an oil or gas well. +Exploratory +well . A well +drilled to find and produce oil or natural gas reserves not classified as +proved, to find a new productive reservoir in a field previously found to be +productive of oil or natural gas in another reservoir or to extend a known +reservoir. +Extensions +and discoveries . +As to any period, the increases to proved reserves from all sources other than +the acquisition of proved properties or revisions of previous estimates. +Gross +acres or wells . +Refers to the total acres or wells in which the Company has a working interest. +Horizontal +drilling . A +drilling technique that permits the operator to contact and intersect a larger +portion of the producing horizon than conventional vertical drilling techniques +and may, depending on the horizon, result in increased production rates and +greater ultimate recoveries of hydrocarbons. +MBbls . One thousand barrels. +Mcf . One thousand cubic feet. +Mcfe . One thousand cubic feet of +natural gas equivalents, based on a ratio of 6 Mcf for each barrel of oil, +which reflects the relative energy content. +MMbtu. One million British thermal +units. One British thermal unit is the heat required to raise the +temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit. +MMcf . One million cubic feet. +MMcfe. One million cubic feet of natural +gas equivalents. +Natural +gas liquids . +Liquid hydrocarbons that have been extracted from natural gas, such as ethane, +propane, butane and natural gasoline. +Net +acres or wells . +Refers to gross acres or wells multiplied, in each case, by the percentage +working interest owned by the Company. +Net +production . Oil +and gas production that is owned by the Company, less royalties and production +due others. +NYMEX . New York Mercantile Exchange, the +exchange on which commodities, including crude oil and natural gas futures +contracts, are traded. +60 +Oil . Crude oil or condensate. +Operator . The individual or company +responsible for the exploration, development and production of an oil or gas +well or lease. +Present +value of proved reserves . +The present value of estimated future revenues, discounted at 10% annually, to +be generated from the production of proved reserves determined in accordance +with Securities and Exchange Commission guidelines, net of estimated production +and future development costs, using prices and costs as of the date of +estimation without future escalation, without giving effect to +(i) estimated future abandonment costs, net of the estimated salvage value +of related equipment, (ii) nonproperty related expenses such as general +and administrative expenses, debt service and future income tax expense, or +(iii) depreciation, depletion and amortization. +Proved +developed nonproducing reserves . +Reserves that consist of (i) proved reserves from wells which have been +completed and tested but are not producing due to lack of market or minor +completion problems which are expected to be corrected and (ii) proved reserves +currently behind the pipe in existing wells and which are expected to be +productive due to both the well log characteristics and analogous production in +the immediate vicinity of the wells. +Proved +developed producing reserves. +Proved reserves that can be expected to be recovered from currently producing +zones under the continuation of present operating methods. +Proved +developed reserves. +The combination of proved developed producing and proved developed nonproducing +reserves. +Proved +reserves . 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, i.e., prices and costs as of the date the estimate is +made. Prices include consideration of changes in existing prices provided +only by contractual arrangements, but not on escalations based upon future +conditions. +Proved +undeveloped reserves (PUD) . +Proved 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. +Royalty . An interest in an oil and gas +lease that gives the owner of the interest the right to receive a portion of +the production from the leased acreage (or of the proceeds of the sale +thereof), but generally does not require the owner to pay any portion of the +costs of drilling or operating the wells on the leased acreage. Royalties +may be either landowner's royalties, which are reserved by the owner of the +leased acreage at the time the lease is granted, or overriding royalties, which +are usually reserved by an owner of the leasehold in connection with a transfer +to a subsequent owner. +SEC . The United States Securities and +Exchange Commission. +Standardized +measure of discounted future net cash flows . Present value of proved reserves, as adjusted to +give effect to (i) estimated future abandonment costs, net of the +estimated salvage value of related equipment, and (ii) estimated future +income taxes. +Undeveloped +acreage . Leased +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 proved reserves. +Working +interest . An +interest in an oil and gas lease that gives the owner of the interest the right +to drill for and produce oil and gas on the leased acreage and requires the +owner to pay a share of the costs of drilling and production operations. +The share of production to which a working interest is entitled will be smaller +than the share of costs that the working interest owner is required to bear to +the extent of any royalty burden. +Workover . Operations on a producing well to +restore or increase production. +61 +PETROLEUM +DEVELOPMENT CORPORATION AND SUBSIDIARIES +Index to Financial +Statements and Financial Statement Schedule +1. +Financial Statements: +Report of Independent +Registered Public Accounting Firm +F-2 +Consolidated Balance +Sheets - December 31, 2005 and 2004 +F-3 & 4 +Consolidated Statements +of Income - +Years Ended December 31, 2005, 2004 and 2003 +F-5 +Consolidated Statements +of Stockholders' Equity - +Years Ended December 31, 2005, 2004 and 2003 +F-6 +Consolidated Statements +of Cash Flows - +Years Ended December 31, 2005, 2004 and 2003 +F-7 +Notes to Consolidated +Financial Statements +F-8 -F-37 +2. +Financial Statement Schedule: +Schedule II - Valuation and Qualifying Accounts and +Reserves +F-38 +F-1 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Report of +Independent Registered Public Accounting Firm +The Board of Directors and Stockholders +Petroleum Development Corporation: +We have audited the accompanying consolidated balance +sheets of Petroleum Development Corporation and subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of income, +stockholders' equity, and cash flows for each of the years in the three-year +period ended December 31, 2005. In connection with our audits of the +consolidated financial statements, we also have audited the related financial +statement schedule II. These consolidated financial statements and financial +statement schedule are the responsibility of the Company's management. Our +responsibility is to express an opinion on these consolidated financial +statements and financial statement schedule 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, the consolidated financial statements +referred to above present fairly, in all material respects, the financial +position of Petroleum Development Corporation and subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for +each of the years in the three-year period ended December 31, 2005, in conformity with U. S. generally accepted accounting principles. Also in our opinion, the +related financial statement schedule, when considered in relation to the basic +consolidated financial statements taken as a whole, presents fairly, in all +material respects, the information set forth therein. +As discussed in Note 22 to the consolidated financial +statements, the Company restated its 2004 and 2003 consolidated financial +statements. +As discussed in Note 1 to the consolidated financial +statements, the Company adopted the provisions of Statement of Financial +Accounting Standards No. 143, Accounting for Asset Retirement Obligations, in +2003. +We also have audited, in accordance with the standards of +Public Company Accounting Oversight Board (United States), the effectiveness of +Petroleum Development Corporation's 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 (COSO) and our report dated May 15, 2006, expressed an +unqualified opinion on management's assessment of, and an adverse opinion on +the effective operation of, internal control over financial reporting as of December 31, 2005. +KPMG LLP +Pittsburgh, Pennsylvania +May 24, 2006 +F-2 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Consolidated Balance +Sheets +December 31, 2005 and 2004 +Assets +2005 +2004 +Current +assets: +Cash +and cash equivalents +$ +90,110,100 +$ 77,070,400 +Restricted +cash +1,500,600 +664,900 +Accounts +receivable +49,779,500 +33,834,700 +Accounts receivable affiliates +7,233,800 +2,230,600 +Inventories +5,054,900 +1,657,300 +Fair value of derivatives +10,381,800 +3,266,100 +Other +current assets +4,640,500 +6,612,800 +Total +current assets +168,701,200 +125,336,800 +Properties +and equipment: +Oil +and gas properties (successful +efforts +accounting method) +365,379,600 +282,837,200 +Pipelines +11,511,600 +9,515,000 +Transportation +and other equipment +6,382,800 +4,453,700 +Land +and buildings +3,980,800 +2,942,800 +Construction in progress +1,509,300 +- +388,764,100 +299,748,700 +Less +accumulated depreciation, +depletion +and amortization +111,605,900 +92,165,400 +277,158,200 +207,583,300 +Other +assets +3,225,500 +2,108,200 +Total +Assets +$ +449,084,900 +$ 335,028,300 +(Continued) +F-3 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Consolidated +Balance Sheets +December 31, 2005 and 2004 +Liabilities +and Stockholders' Equity +2005 +2004 +Current +liabilities: +Accounts +payable +$ +65,004,100 +$ +43,182,900 +Production +tax liability +30,144,500 +17,510,500 +Fair value +of derivatives +18,424,400 +6,716,400 +Other +accrued expenses +4,140,500 +2,286,800 +Advances +for future drilling contracts +49,999,400 +42,497,300 +Federal and +state income taxes payable +8,473,200 +- +Funds +held for future distribution +18,346,300 +12,911,800 +Total +current liabilities +194,532,400 +125,105,700 +Long-term debt +24,000,000 +21,000,000 +Other +liabilities +7,115,500 +3,927,500 +Deferred +income taxes +26,888,500 +22,976,300 +Asset +retirement obligation +8,283,200 +7,998,200 +Total +liabilities +260,819,600 +181,007,700 +Commitments +and contingencies (Note 10) +Stockholders' +equity: +Common +stock, par value $.01 per share; +authorized +50,000,000 shares; issued and +outstanding +16,281,923 and 16,589,824 shares +162,800 +165,800 +Additional +paid-in capital +30,422,900 +37,684,300 +Retained +earnings +158,504,200 +117,052,500 +Unamortized +stock award +(824,600) +(882,000) +Total +stockholders' equity +188,265,300 +154,020,600 +Total +Liabilities and Stockholders' Equity +$ +449,084,900 +$ 335,028,300 +See accompanying Notes to Consolidated +Financial Statements. +F-4 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Consolidated Balance +Sheets +December 31, 2005 and 2004 +2005 +2004 +2003 +(Restated) +(Restated) +Revenues: +Oil +and gas well drilling operations +$ 99,962,900 +$ 94,076,000 +$ 57,509,600 +Gas +sales from marketing activities +121,104,100 +94,626,800 +73,131,700 +Oil +and gas sales +102,559,200 +69,492,100 +48,393,800 +Well +operations and pipeline income +8,759,600 +7,676,900 +6,907,100 +Other +income +10,747,300 +1,880,700 +3,528,500 +Total +revenues +343,133,100 +267,752,500 +189,470,700 +Costs and +expenses: +Cost +of oil and gas well drilling operations +88,184,900 +77,696,200 +46,945,900 +Cost +of gas marketing activities +119,643,700 +92,881,200 +72,361,400 +Oil +and gas production and well operations costs +19,934,700 +17,277,200 +13,251,300 +Exploratory +dry hole costs +11,115,100 +- +- +General +and administrative expenses +6,960,300 +4,505,600 +4,974,400 +Depreciation, +depletion and amortization +21,116,200 +18,155,900 +15,312,800 +Total +costs and expenses +266,954,900 +210,516,100 +152,845,800 +Income +from operations +76,178,200 +57,236,400 +36,624,900 +Interest +expense +682,300 +673,700 +1,195,300 +Oil +and gas price risk management loss, net +9,368,100 +3,084,600 +812,400 +Income +before income taxes and cumulative +effect +of change in accounting principle +66,127,800 +53,478,100 +34,617,200 +Income taxes +24,676,100 +20,250,500 +11,933,500 +Net +income before cumulative effect of +change +in accounting principle +41,451,700 +33,227,600 +22,683,700 +Cumulative +effect of change in accounting +principle (net +of taxes of $1,392,000) +- +- +(2,271,300) +Net income +$ 41,451,700 +$ 33,227,600 +$ 20,412,400 +Basic earnings +per common share before +accounting +change +$ +2.53 +$ +2.05 +$ +1.45 +Cumulative +effect of change in accounting +principle +- +- +$ +(0.15) +Basic earnings +per common share +$ +2.53 +$ +2.05 +$ +1.30 +Diluted +earnings per share before accounting +change +$ +2.52 +$ +2.00 +$ +1.39 +Cumulative +effect of change in accounting +principle +- +- +$ +(0.14) +Diluted +earnings per common and common +equivalent +share +$ +2.52 +$ +2.00 +$ +1.25 +See accompanying Notes to Consolidated Financial Statements. +F-5 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Consolidated +Statements of Stockholders' Equity +Years Ended December 31, 2005, 2004, and 2003 +Common Stock Issued +Treasury Stock +Number of +Additional +Retained +at Cost +Unamortized +Shares +Amount +Paid-In-Capital +Earnings +(Restated) +Stock Award +Total +Balance, December 31, 2002 +15,734,767 +$ 157,300 +$ 29,340,500 +$ 63,412,500 +$ - +$ (23,700) +$ 92,886,600 +Amortization of stock award +- +- +- +- +- +8,900 +8,900 +Repurchase of treasury stock +- +- +- +- +(748,700) +- +(748,700) +Treasury stock retirement +(106,334) +(1,100) +(747,600) +- +748,700 +- +- +Net income +- +- +- +20,412,400 +- +- +20,412,400 +Balance, December 31, 2003 +15,628,433 +156,200 +28,592,900 +83,824,900 +- +(14,800) +112,559,200 +Issuance of common stock +Exercise of employee stock +options +1,100,000 +11,000 +4,981,700 +- +- +- +4,992,700 +Stock award +23,380 +200 +870,700 +- +- +(870,900) +- +Amortization of stock award +- +- +- +- +- +3,700 +3,700 +Repurchase of treasury stock +- +- +- +- +(4,157,400) +- +(4,157,400) +Treasury stock retirement +(161,989) +(1,600) +(4,155,800) +- +4,157,400 +- +- +Income tax benefit from the exercise of stock +options +- +- +7,394,800 +- +- +- +7,394,800 +Net income +- +- +- +33,227,600 +- +- +33,227,600 +Balance, December 31, 2004 +16,589,824 +165,800 +37,684,300 +117,052,500 +- +(882,000) +154,020,600 +Issuance of common stock +Exercise of employee stock +options +3,000 +100 +11,500 +- +- +- +11,600 +Stock award +20,895 +200 +602,600 +- +- +(602,800) +- +Amortization of stock award +- +- +- +- +- +660,200 +660,200 +Repurchase of treasury stock +- +- +- +- +(7,878,800) +- +(7,878,800) +Treasury stock retirement +(331,796) +(3,300) +(7,875,500) +- +7,878,800 +Net income +- +- +- +41,451,700 +- +- +41,451,700 +Balance, December 31, 2005 +16,281,923 +$ 162,800 +$ 30,422,900 +$ 158,504,200 +$ - +$ (824,600) +$188,265,300 +See accompanying +Notes to Consolidated Financial Statements. +F-6 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Consolidated +Statements of Cash Flows +Years Ended December 31, 2005, 2004, and 2003 +Cash flows +from operating activities: +2005 +2004 +2003 +Net +income +$41,451,700 +$33,227,600 +$20,412,400 +Adjustment +to reconcile net income to cash provided +by +operating activities: +Deferred +income taxes +3,350,600 +9,887,300 +8,462,300 +Depreciation, +depletion and amortization +21,116,200 +18,155,900 +15,312,800 +Accretion +of asset retirement obligation +465,200 +436,000 +379,200 +Exploratory +dry hole costs +11,115,100 +- +- +Unrealized +loss (gain) on derivative transactions +3,225,900 +535,200 +(1,110,200) +Cumulative +effect of change in accounting principle +- +- +2,271,300 +Gain +from sale of assets +(7,875,800) +(32,000) +(202,500) +Expired +and abandoned leases +47,600 +300,800 +1,383,000 +Amortization +of stock award +660,200 +3,700 +8,900 +Change in +assets and liabilities: +Increase in accounts receivable +(11,276,400) +(10,492,600) +(7,197,800) +(Increase) +decrease in accounts receivable affiliates +(5,003,200) +(343,200) +10,700 +(Increase) decrease in restricted cash +(835,700) +1,201,500 +894,100 +(Increase) decrease in inventories +(3,397,600) +357,000 +(1,383,600) +Decrease (increase) in other current assets +3,482,100 +4,776,200 +(1,095,900) +(Increase) decrease in other assets +(651,600) +(48,800) +1,696,200 +Increase +in production tax liability +12,634,000 +8,441,100 +3,974,800 +Increase in accounts payable and accrued expenses +22,453,500 +10,355,800 +13,018,300 +Increase (decrease) in advances for future drilling +contracts +7,502,100 +(7,961,500) +13,175,000 +Increase +in federal and state income taxes payable +8,473,200 +- +- +Increase in funds held for future distribution +5,434,500 +4,500,900 +4,493,000 +Total +adjustments +70,919,900 +40,073,300 +54,089,600 +Net +cash provided by operating activities +112,371,600 +73,300,900 +74,502,000 +Cash flows +from investing activities: +Capital +expenditures +(106,468,500) +(45,391,800) +(73,042,300) +Proceeds from sale of leases to partnerships +2,829,200 +1,950,900 +1,382,100 +Proceeds +from sale of fixed assets +9,597,600 +94,700 +156,800 +Net +cash used in investing activities +(94,041,700) +(43,346,200) +(71,503,400) +Cash flows +from financing activities: +Proceeds +from debt +91,000,000 +84,000,000 +86,600,000 +Retirement +of debt +(88,000,000) +(116,000,000) +(58,600,000) +Payment of +debt issue costs +(423,000) +(232,500) +- +Proceeds +from issuance of stock +11,600 +3,584,400 +- +Repurchase +of treasury stock +(7,878,800) +(2,749,100) +(748,700) +Net +cash (used in) provided from financing activities +(5,290,200) +(31,397,200) +27,251,300 +Net +increase (decrease) in cash and cash equivalents +13,039,700 +(1,442,500) +30,249,900 +Cash +and cash equivalents, beginning of year +77,070,400 +78,512,900 +48,263,000 +Cash and +cash equivalents, end of year +$ 90,110,100 +$ 77,070,400 +$ 78,512,900 +See accompanying +Notes to Consolidated Financial Statements. +F-7 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +Years Ended December 31, 2005, 2004 and 2003 +(1) Summary +of Significant Accounting Policies +General +Petroleum +Development Corporation (PDC or the Company) is an independent energy company +engaged primarily in the drilling and development, production and marketing of +natural gas and oil. Since it began oil and gas operations in 1969, the Company +has grown primarily through drilling and development activities, the +acquisition of producing natural gas and oil wells and the expansion of its +natural gas marketing activities. As of December 31, 2005, the Company operates approximately 2,800 wells located in the Appalachian Basin, Michigan, and the +Rocky Mountain Region. Substantially all of the Company's oil and gas wells are +located in West Virginia, Tennessee, Pennsylvania, Michigan, North Dakota, +Colorado and Kansas. The Company is involved in four business segments. The +segments are drilling and development, natural gas marketing, oil and gas sales +and well operations. (See Note 20) +Principles +of Consolidation +The accompanying consolidated financial +statements include the accounts of Petroleum Development Corporation (PDC) and its wholly owned subsidiaries, Riley +Natural Gas (RNG) and PDC Securities +Incorporated. All material intercompany accounts and transactions have been +eliminated in consolidation. The Company accounts for its investment in +interests in oil and gas limited partnerships under the proportionate +consolidation method. Under this method, the Company's financial statements +include its pro rata share of assets, liabilities and revenues and expenses +respectively of the limited partnerships in which it participates. The +Company's proportionate share of all significant transactions between the +Company and the limited partnerships is eliminated. +Cash +Equivalents +For +purposes of the statement of cash flows, the Company considers all highly +liquid debt instruments with original maturities of three months or less to be +cash equivalents. +Restricted +Cash +The +Company is required to maintain margin deposits with brokers for outstanding +derivative contracts. As of December 31, 2005 and 2004, cash in the amount of $1,500,600 and $664,900, respectively was on deposit. +Inventories +Inventories +consist primarily of tubular goods and other well equipment, parts and supplies +which are valued at the lower of average cost or market. An inventory of +natural gas is recorded when gas is purchased, through RNG activities, in +excess of deliveries to customers and is recorded at the lower of cost or +market. +Oil +and Gas Properties +The +Company accounts for its oil and gas properties under the successful efforts +method of accounting. Costs of proved developed producing properties, +successful exploratory wells and development dry hole costs are depreciated or +depleted by the unit-of-production method based on estimated proved developed +producing oil and gas reserves. Property acquisition costs are depreciated or +depleted on the unit-of-production method based on estimated proved oil and gas +reserves. The Company obtains new reserve reports from independent petroleum +engineers annually as of December 31st of each year. The Company adjusts oil +and gas reserves for any major acquisitions, new drilling and divestitures +during the year as needed. +F-8 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +Exploration +costs, including geological and geophysical expenses and delay rentals, are +charged to expense as incurred. Exploratory well drilling costs, including the +cost of stratigraphic test wells, are initially capitalized but charged to +expense if the well is determined to be nonproductive. The status of each +in-progress well is reviewed quarterly to determine the proper accounting +treatment under the successful efforts method of accounting. Exploratory well +costs continue to be capitalized as long as the well has found a sufficient +quantity of reserves to justify its completion as a producing well and the +Company is making sufficient progress assessing its reserves and economic and +operating viability. If an in-progress exploratory well is found to be +unsuccessful (referred to as a dry hole) prior to the issuance of our financial +statements, the costs are expensed to exploratory dry hole costs. If we are +unable to make a final determination about the productive status of a well +prior to issuance of our financial statements, the well is classified as +"Suspended Well Costs" until we have had sufficient time to conduct additional +completion or testing operations to evaluate the pertinent geological and +engineering data obtained. At the time when we are able to make a final +determination of a well's productive status, the well is removed from the +suspended well status and the proper accounting treatment is recorded. The +determination of an exploratory well's ability to produce is made within one +year from the completion of drilling activities. See Note 16. +The +acquisition costs of unproved properties are capitalized when incurred, until such +properties are transferred to proved properties or charged to expense when +expired, impaired or amortized. Unproved oil and gas properties with +individually significant acquisition costs are periodically assessed, and any +impairment in value is charged to expense. The amount of impairment recognized +on unproved properties which are not individually significant is determined by +amortizing the costs of such properties within appropriate fields based on the +Company's historical experience, acquisition dates and average lease terms. +Amortization of remaining lease costs for all other insignificant properties is +recorded over the average remaining lives of the leases. The valuation of +unproved properties is subjective and requires management of the Company to +make estimates and assumptions which, with the passage of time, may prove to be +materially different from actual realizable values. +Upon +sale or retirement of significant portions of or complete fields of depreciable +or depletable property, the book value thereof, less proceeds or salvage value, +is credited or charged to income. Upon sale of individual wells, the proceeds +are credited to property costs. +The +Company assesses impairment of capitalized costs of proved oil and gas +properties by comparing net capitalized costs to estimated undiscounted future +net cash flows on a field-by-field basis using estimated production based upon +prices at which management reasonably estimates such products to be sold. These +estimates of future product prices may differ from current market prices of oil +and gas. Any downward revisions to management's estimates of future production +or product prices could result in an impairment of the Company's oil and gas +properties in subsequent periods. If net capitalized costs exceed undiscounted +future net cash flows, the measurement of impairment is based on estimated fair +value which would consider future discounted cash flows. +Transportation +Equipment, Pipelines and Other Equipment +Transportation +equipment, pipelines and other equipment are carried at cost. Depreciation is +provided principally on the straight-line method over useful lives of 3 to 17 +years. The Company adopted FASB Statement No. 144 "Accounting for the +Impairment or Disposal of Long-Lived Assets" on January 1, 2002. The adoption of FASB No. 144 did not affect the Company's financial statements. +In +accordance with FASB Statement No. 144, long-lived assets, such as property, +plant, and equipment, are reviewed for impairment whenever events or changes in +circumstances indicate that the carrying amount of an asset may not be +recoverable. Recoverability of assets to be held and used is measured by a +comparison of the carrying amount of an asset to estimated undiscounted future +cash flows expected to be generated by the asset. If the carrying amount of an +asset exceeds its estimated future cash flows, an impairment charge is +recognized in the amount by which the carrying amount of the asset exceeds the +fair value of the asset. +F-9 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +Maintenance +and repairs are charged to expense as incurred. Major renewals and betterments +are capitalized. Upon the sale or other disposition of assets, the cost and +related accumulated depreciation, depletion and amortization are removed from +the accounts, the proceeds applied thereto and any resulting gain or loss is +reflected in income. +Buildings +Buildings +are carried at cost and depreciated on the straight-line method over estimated useful +lives of 30 years. +Asset +Retirement Obligations +The +Company accounts for asset retirement obligations by recording the fair value +of its plugging and abandonment obligations when incurred, which is at the time +the well is completely drilled. Upon initial recognition of an asset retirement +obligation, the Company increases the carrying amount of the long-lived asset +by the same amount as the liability. Over time, the liabilities are accreted +for the change in their present value, through charges to Interest expense. The +initial capitalized costs are depleted over the useful lives of the related +assets, through charges to depreciation, depletion and amortization. See Note 5 +for a reconciliation of asset retirement obligation activity. +Advances +for Future Drilling Contracts +Advances +for future drilling contracts represents funds received from Partnerships and +other joint ventures for drilling activities which have not been completed and +accordingly have not yet been recognized as revenue in accordance with the +Company's revenue recognition policies. +Retirement +Plans +The +Company has a 401-K contributory retirement plan (401-K Plan) covering +full-time employees. The Company provides a discretionary matching of employee +contributions to the plan. +The +Company has a profit sharing plan covering full-time employees. The Company's +contributions to this plan are discretionary. +The +Company has a deferred compensation arrangement covering executive officers of +the Company as a supplemental retirement benefit. +Revenue +Recognition +The +Company's drilling segment recognizes revenue from our drilling contracts with +our sponsored drilling programs using the percentage of completion method. +These contracts include the sale of equipment and the providing of services at +footage rates and are completed within nine to twelve months after the +commencement of drilling. The Company provides geological, engineering, and +drilling supervision on the drilling and completion process and uses +subcontractors to perform drilling and completion services. Revenues are +recognized under the percentage of completion method based upon the percentage +of contract costs incurred to date to the estimated total contract costs for +each contract. The Company utilizes this method because reasonably dependable +estimates of the total estimated costs can be made. Because the revenue +recognized depends on estimates of the final contract costs, which are assessed +continually during the term of the contract, recognized revenues are subject to +revisions as the contract progresses. Anticipated losses, if any, on +uncompleted contracts would be recorded at the time that our estimated costs +exceeded the contract revenue. In the fourth quarter of 2005, the Company +recorded a loss of $800,000 on uncompleted drilling contracts as cost of oil +and gas well drilling operations with the related liability recorded in other +accrued expenses in the accompanying consolidated balance sheet. The Company +did not experience any contract losses in 2004 or 2003. +Natural gas marketing is +recorded on the gross accounting method. RNG, our marketing subsidiary, +purchases gas from many small producers and bundles the gas together to sell in +larger amounts to purchasers of natural gas for a price advantage. RNG has latitude +in establishing price and discretion in supplier and purchaser selection. +Natural gas marketing revenues and expenses reflect the full cost and revenue +of those transactions because RNG takes title to the gas it purchases from the +various producers and bears the risks and rewards of that ownership. Both the +realized and unrealized portions of the RNG commodity based derivative +transactions for natural gas marketing activities are included in gas sales +from marketing activities or cost of gas marketing activities, as applicable. +F-10 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +Sales of natural gas are +recognized when natural gas has been delivered to a custody transfer point, +persuasive evidence of a sales arrangement exists, the rights and +responsibility of ownership pass to the purchaser upon delivery, collection of +revenue from the sale is reasonably assured and the sales price is fixed or +determinable. Natural gas is sold by the Company under contracts with terms +ranging from one month to three years. Virtually all of the Company's +contracts pricing provisions are tied to a market index, with certain +adjustments based on, among other factors, whether a well delivers to a +gathering or transmission line, quality of natural gas and prevailing supply +and demand conditions, so that the price of the natural gas fluctuates to +remain competitive with other available natural gas supplies. As a result, the +Company's revenues from the sale of natural gas will suffer if market prices +decline and benefit if they increase. The Company believes that the pricing +provisions of its natural gas contracts are customary in the industry. +The Company currently uses +the "Net-Back" method of accounting for transportation arrangements of our +natural gas sales. The Company sells gas at the wellhead and collects a price +and recognizes revenues based on the wellhead sales price since transportation +costs downstream of the wellhead are incurred by our customers and reflected in +the wellhead price. +Sales of oil are recognized +when persuasive evidence of a sales arrangement exists, the oil is verified as +produced and is delivered in a stock tank, collection of revenue from the sale +is reasonably assured and the sales price is determinable. The Company is +currently able to sell all the oil that it can produce under existing sales +contracts with petroleum refiners and marketers. The Company does not refine +any of its oil production. The Company's crude oil production is sold to +purchasers at or near the Company's wells under short-term purchase contracts +at prices and in accordance with arrangements that are customary in the oil +industry. +Well operations and +pipeline income is recognized when persuasive evidence of an arrangement +exists, services have been rendered, collection of revenues is reasonably +assured and the sales price is fixed or determinable. The Company is paid a +monthly operating fee for each well it operates for outside owners including +the limited partnerships sponsored by the Company. The fee covers monthly +operating and accounting costs, insurance and other recurring costs. The +Company may also receive additional compensation for special non-recurring +activities, such as reworks and recompletions. +Income +Taxes +Income +taxes are accounted for under the asset and liability method. +Deferred +tax assets and liabilities are recognized for the future tax consequences +attributable to differences between the financial statement carrying amounts of +existing assets and liabilities and their respective tax bases. Deferred tax +assets and liabilities are measured using enacted tax rates expected to apply +to taxable income in the years in which those temporary differences are +expected to be recovered or settled. The effect on deferred tax assets and +liabilities of a change in tax rates is recognized in income in the period that +includes the enactment date. +Derivative +Financial Instruments +The +Company accounts for derivative financial instruments in accordance with FAS +Statement No. 133 "Accounting for Derivative Instruments and Certain Hedging +Activities" as amended. +During +2005, 2004, and 2003, none of the derivative contracts qualified for hedge +accounting under the terms of FAS No. 133. Accordingly, the derivative +instruments are recorded as an asset or liability on the balance sheet at fair +value and the change in the fair value is recorded in oil and gas price risk +management, net for the Company's oil and gas commodities (derivatives related +to the Company's production only), in gas sales from marketing activities for +RNG's gas sales, in cost of gas marketing activities for RNG's gas purchases +and in interest expense for the Company's interest rate swap (2004 and 2003 +only). See Note 13. +In the +accompanying balance sheet, the Company records the fair value of derivatives +entered into on behalf of the affiliated partnerships and records an offsetting +receivable or payable with the partnerships. See Note 9. +F-11 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +Stock +Compensation +The +Company applies the intrinsic-value based method of accounting prescribed by +Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued +to Employees", and related interpretations including FASB Interpretation No. +44, "Accounting for Certain Transactions involving Stock Compensation, an +interpretation of APB Opinion No. 25", to account for its fixed-plan stock +options. Under this method, compensation expense is recorded on the date of +grant only if the current market price of the underlying stock exceeded the +exercise price. FASB Statement No. 123, "Accounting for Stock-Based +Compensation" and FASB Statement No. 148, "Accounting for Stock Based +Compensation-Transition and Disclosure, an amendment of FASB Statement No. +123", established accounting and disclosure requirements using a +fair-value-based method of accounting for stock-based employee compensation +plans. As permitted by existing accounting standards, the Company has elected +to continue to apply the intrinsic-value-based method of accounting described +above, and has adopted only the disclosure requirements of Statement 123, as +amended. If the fair-value-based method had been applied to all outstanding +and awards in each period, the impact in 2005 and 2004 would have been an +additional expense of $94,700 and $18,400, respectively. There would have been +no impact on reported net income in 2003. +Year Ended December 31, +2005 +2004 +Net income, as +reported +$ +41,451,700 +$ +33,227,600 +Stock-based +employee compensation +expenses +included in reported net +income, net +of related tax effects +413,900 +2,400 +Deduct total +stock-based employee +compensation +expense determined +under +fair-value based method +for all +awards, net of tax +(508,600) +(20,800) +Pro forma net +income +$ +41,357,000 +$ +33,209,200 +Basic earnings +per share as reported +$2.53 +$2.05 +Pro forma +basic earnings per share +$2.53 +$2.05 +Diluted +earnings per share as reported +$2.52 +$2.00 +Pro forma +diluted earnings per share +$2.52 +$2.00 +Compensation +expense for stock options is measured as the excess, if any, of the quoted +market price of the Company stock at the date of the grant over the amount an +optionee must pay to acquire the stock. The Company records compensation +expense for restricted stock awards based on the quoted market price of the +Company's stock at the date of grant and recognizes the cost over the vesting +period. +The +pro forma amounts that would have been reported if FAS No. 123 had been in +effect for all years are based on the fair value of the stock-based awards +granted for each year and recognized over the vesting period. +The +fair value at date of grant for a common stock option granted under Company's +option plan during 2004 was $16.75. There were no common stock options granted +during 2005 or 2003. The fair value of each option granted during 2004 was +estimated on the date of grant using the Black-Scholes option-pricing model +with the following weighted-average assumptions. +F-12 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +Dividend yield +0% +Expected volatility +39.71% +Risk-free interest +rate +4.06% +Expected option +life +(in years) +7.0 +As of December 31, 2005, there was approximately $131,700 of unrecognized, pre-tax compensation +cost related to non-vested stock options. This cost is expected to be +recognized over three years. The Company will adopt the provisions of FASB +Statement No. 123R (revised 2004), "Accounting for Share Based Payments," +effective January 1, 2006 regarding stock compensation as discussed above. Upon +adoption of FASB Statement No. 123R, the fair value of share based awards will +be recognized directly in our consolidated statements of income. +Use +of Estimates +Management +of the Company has made a number of estimates and assumptions relating to the +reporting of assets and liabilities and revenues and expenses and the +disclosure of contingent assets and liabilities to prepare these financial +statements in conformity with generally accepted accounting principles. Actual +results could differ from those estimates. Estimates which are particularly +significant to the consolidated financial statements include estimates of oil +and gas reserves and future cash flows from oil and gas properties. +Fair +Value of Financial Instruments +The +carrying values of the Company's receivables, payables and debt obligations are +estimated to be substantially the same as the fair values as of December 31, 2005, 2004 and 2003. +Reclassifications +Certain +reclassifications of prior year financial statement amounts have been made to +conform to current year presentations. The fair value of derivatives of +$3,266,100 and $6,716,400 were broken out from other current assets and other +accrued expenses, respectively as of December 31, 2004 in the accompanying +consolidated balance sheets. The decrease in restricted cash for the years +ended 2004 and 2003 was reclassified from cash flows from investing activities +to cash flows from operating activities and the proceeds from the retirement of +debt are shown gross instead of net for the years ended 2004 and 2003 in the +accompanying consolidated statements of cash flows. There are certain +reclassifications in the tax rate reconciliation for 2004 and the 2003 deferred +tax asset related to asset retirement obligations and the deferred tax +liability related to properties and equipment were both grossed-up by +approximately $1.4 million. See footnote 4. The oil and gas capitalized costs +as of December 31, 2004 were reclassified from intangible well equipment, +intangible drilling costs, undeveloped properties and capitalized asset +retirement costs to proved oil and gas properties and unproved oil and gas +properties to comply with required disclosures per FASB Statement No. 69. See +footnote 16. Expenditures for segment long-lived assets of $4,583,000 and +$6,168,000 in 2004 and 2003, respectively were reclassified from the drilling +and development segment to the oil and gas sales segment. See footnote 20. +Recently +Adopted Accounting Standards +The +FASB issued FIN 46R, "Consolidation of Variable Interest Entities", +in January 2003 and amended the interpretation in December 2003. A variable +interest entity (VIE) is an entity in which its voting equity investors lack +the characteristics of having a controlling financial interest or where the +existing capital at risk is insufficient to permit the entity to finance its +activities without receiving additional financial support from other parties. +FIN 46R requires the consolidation of entities which are determined to be VIEs +where the reporting company determines itself to be the primary beneficiary +(the entity that will absorb a majority of the VIE's expected losses, receive a +majority of the VIE's residual return, or both). The amended interpretation +was effective for the first interim annual reporting period ending after March 15, 2004, with the exception of special purpose entities for which the statement was +effective for periods ending after December 15, 2003. We have completed a review of our partnership investments and have determined that the partnerships +are not VIEs. +F-13 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +In +June 2005, the EITF reached a consensus on EITF Issue No. 04-5, "Determining +Whether a General Partner, or the General Partners as a Group, Controls a +Limited Partnership or Similar Entity When the Limited Partners Have Certain +Rights". This consensus applies to voting right entities not within the +scope of FASB Interpretation No. 46R, "Consolidation of Variable Interest +Entities", in which the investor is the general partner in a limited +partnership or functional equivalent. The EITF consensus is that the general +partner in a limited partnership is presumed to control that limited +partnership regardless of the extent of the general partner's ownership +interest and, therefore, should include the limited partnership in its +consolidated financial statements unless the limited partners have substantive +participating or kick-out rights. The EITF provided that the presumption may be +overcome if the limited partners possess certain substantive kick-out rights or +participation rights. Pursuant to the partnership agreements which govern the +limited partnerships sponsored by the Company, the presumption of control by +the Company, the general partner, is overcome because the investor partners +have substantive ability to dissolve (liquidate) the limited partnership or +otherwise remove the general partner through substantive kick-out rights that +can be exercised by a vote of simple majority of the investor partner units not +held by the general partners without having to show cause. As a result, the +partnership interests of the Company continue to be proportionately +consolidated as disclosed above. +On April 4, 2005, the FASB issued FASB Staff Position (FSP) FAS 19-1 "Accounting for +Suspended Well Costs." This staff position amends FASB Statement No. 19 +"Financial Accounting and Reporting by Oil and Gas Producing Companies" and +provides guidance about exploratory well costs to companies which use the +successful efforts method of accounting. The Position states that exploratory +well costs should continue to be capitalized if: 1) a sufficient quantity of +reserves are discovered in the well to justify its completion as a producing +well and 2) sufficient progress is made in assessing the reserves and the +well's economic and operating feasibility. If the exploratory well costs do +not meet both of these criteria, these costs should be expensed, net of any +salvage value. Additional annual disclosures are required to provide +information about management's evaluation of capitalized exploratory well +costs. In addition, the FSP requires annual disclosure of: 1) net changes from +period to period of capitalized exploratory well costs for wells that are +pending the determination of proved reserves, 2) the amount of exploratory well +costs that have been capitalized for a period greater than one year after the +completion of drilling and 3) an aging of exploratory well costs suspended for +greater than one year with the number of wells it related to. Further, the +disclosures should describe the activities undertaken to evaluate the reserves +and the projects, the information still required to classify the associated +reserves as proved and the estimated timing for completing the evaluation. The +Company adopted FAS 19-1 during the third quarter of 2005. See Note 16. The +application of this FSP did not have a significant impact on the Company's +financial position or results of operations. +Recently +Issued Accounting Standards +On December 16, 2004, +the FASB issued SFAS No. 123(R) "Accounting for Share Based +Payments" and has issued several subsequent Staff Positions clarifying +this guidance. This guidance replaced previously existing requirements +under SFAS No. 123 and APB No. 25. Under SFAS No. 123(R), +an entity must recognize the compensation cost related to employee services +received in exchange for all forms of share-based payments to employees, +including employee stock options, as an expense in its income statement. +The compensation cost of the award would generally be measured based on the +grant-date fair value of the award. The Company will be required to adopt +SFAS No. 123(R) in the first quarter of 2006. The Company intends to +use the modified prospective method for adoption of SFAS No. 123(R) as +permitted by the guidance. +The Company has determined +that the impact of SFAS No. 123(R) and related guidance will not be +material to its financial statements. In accordance with SFAS +No. 123, the Company has historically disclosed the impact on the +Company's net income and earnings per share had the fair value based method +been adopted. Had the Company adopted SFAS No. 123(R) in prior periods, +the impact of that standard on periods presented in these Consolidated +Financial Statements would have approximated the impact of SFAS No. 123 as +described in the disclosure of pro forma net income and earnings per share +presented earlier in Note 1. +In +December 2004, the FASB issued SFAS 153, "Exchange of Nonmonetary Assets ", +an amendment of APB Opinion 29, "Accounting for Nonmonetary +Transactions ". This amendment eliminates the exception for +nonmonetary exchanges of similar productive assets and replaces it with a general +exception for exchanges of nonmonetary assets that do not have commercial +substance. Under SFAS 153, if a nonmonetary exchange of similar productive +assets meets a commercial-substance criterion and fair value is determinable, +the transaction must be accounted for at fair value resulting in recognition of +any gain or loss. This statement is effective for nonmonetary transactions in +fiscal periods that begin after June 15, 2005. The adoption of SFAS No. 153 will not have a material impact on our results of operations or financial +position. +F-14 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +In +June 2005, the FASB issued SFAS No. 154, "Accounting Changes and Error +Corrections" - a replacement of APB Opinion No. 20 and FASB Statement No. +3, which replaces Accounting Principles Board Opinion No. 20, "Accounting +Changes", and SFAS No. 3, "Reporting Accounting Changes in Interim +Financial Statements", and changes the requirements for the accounting for +and reporting of a change in accounting principle. SFAS No. 154 requires +retrospective application for voluntary changes in accounting principle unless +it is impracticable to do so, and it applies to all voluntary changes in +accounting principle. It also applies to changes required by an accounting +pronouncement in the unusual instance that the pronouncement does not include +specific transition provisions. When a pronouncement includes specific +transition provisions, those provisions should be followed. SFAS No. 154 is +effective for accounting changes and corrections of errors made in fiscal years +beginning after December 15, 2005. Consequently, we will adopt the provisions +of SFAS 154 for our fiscal year beginning January 1, 2006. We currently believe that adoption of the provisions of SFAS No. 154 in 2006 will not have a material +impact on our consolidated financial statements. +(2) Accounts +Receivable +The +allowance for doubtful accounts receivable is determined based on the Company's +historical write-off experience and is the Company's best estimate of the +amount of probable credit losses in the Company's existing accounts receivable. +Included in other assets are noncurrent accounts receivable as of December 31, 2005 and 2004, in the amounts of $382,200 and $608,500 net of an allowance +for doubtful accounts of $161,400 and $244,400, respectively. +The +allowance for doubtful current accounts receivable as of December 31, 2005 and 2004 was $247,600 and $164,600, respectively. +(3) Long-Term +Debt +The +Company has a credit facility with J. P. Morgan Chase Bank, NA (formerly Bank +One, NA) and BNP Paribas of $200 million subject to and secured by required +levels of oil and gas reserves. The current borrowing base, based upon current +oil and gas reserves, is $125 million of which the Company has activated $80 +million of the facility. The Company is required to pay a commitment fee of +0.25 to 0.375 percent per annum on the unused portion of the activated credit +facility. Interest accrues at prime, with LIBOR (London Interbank Market Rate) +alternatives available at the discretion of the Company. No principal payments +are required until the credit agreement expires on November 4, 2010. +As of December 31, 2005 and 2004 the outstanding balance was $24,000,000 and $21,000,000, +respectively. Any amounts outstanding under the credit facility are secured by +substantially all properties of the Company. The credit agreement requires, +among other things, the existence of satisfactory levels of natural gas reserves, +maintenance of certain working capital and tangible net worth ratios along with +a restriction on the payment of dividends. At December 31, 2005, the outstanding balance was subject to a prime interest rate of 7.25%. As of the filing of +this Form 10-K, the Company was in compliance with all covenants in the credit +agreement, except for timely filing of this December 31, 2005 Form 10-K. The Company has received bank waivers to extend the due date of the December 31, 2005 consolidated financial statements until May 31, 2006, and the due date +of the March 31, 2006 consolidated financial statements until June 15, 2006. +(4) Income +Taxes +The +Company's provision for income taxes consisted of the following: +2005 +2004 +2003 +Current: +Federal +$ 17,893,900 +$ 8,649,900 +$ 2,600,700 +State +3,431,600 +1,713,300 +870,500 +Total +current income taxes +21,325,500 +10,363,200 +3,471,200 +Deferred: +Federal +2,833,800 +8,429,700 +7,429,800 +State +516,800 +1,457,600 +1,032,500 +Total +deferred income taxes +3,350,600 +9,887,300 +8,462,300 +Total +income taxes +$ 24,676,100 +$ 20,250,500 +$ 11,933,500 +F-15 +Income tax expense +differed from the amounts computed by applying the U.S. federal income tax rate +of 35%. +2005 +2004 +2003 +Computed +"expected" tax +$ 23,144,700 +$ 18,717,300 +$ 12,116,000 +State +income tax +2,566,500 +2,061,100 +1,236,900 +Percentage +depletion +(770,900) +(648,600) +(736,000) +Domestic +production activities deduction +(399,400) +- +- +Nonconventional +source fuel credit +- +- +(186,600) +Officers +life insurance +- +- +(350,000) +Surtax +exemption +- +- +(100,000) +Other +135,200 +120,700 +(46,800) +$ 24,676,100 +$ 20,250,500 +$ 11,933,500 +The tax effects +of temporary differences that give rise to significant portions of the deferred +tax assets and deferred tax liabilities at December 31, 2005 and 2004 are presented below. +2005 +2004 +Deferred tax +assets: +Allowance +for doubtful accounts +$ 159,100 +$ 159,100 +Drilling +notes +71,200 +57,200 +Deferred +revenue related to cash withheld +for future +plugging costs +823,800 +725,500 +Deferred +compensation +903,900 +692,100 +Asset +retirement obligations +3,241,600 +3,111,300 +Derivatives +1,561,600 +306,700 +Other +8,300 +21,800 +Total +gross deferred tax assets +6,769,500 +5,073,700 +Less +valuation allowance +- +- +Deferred +tax assets +6,769,500 +5,073,700 +Less +current deferred tax assets +(included +in other current assets) +(1,848,300) +(337,300) +Net +non-current deferred tax assets +4,921,200 +4,736,400 +Deferred tax +liabilities: +Properties +and equipment, principally due to differences in +depreciation and amortization +(31,809,700) +(27,712,700) +Total gross +deferred tax liabilities +(31,809,700) +(27,712,700) +Net +non-current deferred tax liability +$ (26,888,500) +$ (22,976,300) +In +assessing whether a valuation allowance for the deferred tax assets should be +recorded, management considers whether it is more likely than not that some +portion or all of the deferred tax assets will not be realized. The ultimate +realization of deferred tax assets is dependent upon the generation of future +taxable income during the periods in which those temporary differences become +deductible. Based upon the level of historical taxable income and projections +for future taxable income over the periods in which the deferred tax assets are +deductible, management believes it is more likely than not that the Company +will realize the benefits of these deductible differences. The amount of the +deferred tax asset considered realizable, however, could be reduced in the near +term if estimates of future taxable income during the carryforward period are +reduced. +Employee stock +options exercised during the year 2004 resulted in an income tax benefit of +$7,394,800 that is reflected in Stockholders' Equity and as a reduction of +current tax payable. +F-16 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +(5) Asset Retirement +Obligations +Changes in carrying +amounts of the asset retirement obligations associated with our working +interest in oil and gas properties are as follows: +2005 +2004 +2003 +Balance at +beginning of year +$7,998,200 +$7,390,800 +$6,046,200 +Obligations +assumed with development activities +and +acquisitions +301,400 +238,600 +997,200 +Obligations +discharged with disposed properties +and asset +retirements +(445,800) +(67,200) +(31,800) +Revisions to +estimates +14,200 +- +- +Accretion expense +465,200 +436,000 +379,200 +Balance at end +of year +$8,333,200 +$7,998,200 +$7,390,800 +Approximately +$50,000 was classified as short-term and included in other accrued expenses as +of December 31, 2005 and 2004. +If the +fair value of the estimated asset retirement obligation changes, an adjustment +is recorded to both the asset retirement obligation and the asset retirement +cost. +Upon +the adoption of FAS No. 143 effective January 1, 2003, the Company recorded a net asset of $2,382,900 and a related liability of $6,046,200 (using a 5.75% +discount rate) and a cumulative effect of change in accounting principle on +prior years of $2,271,300 (net of taxes of $1,392,000). +(6) Common +Stock +Stock-Based +Compensation Plans +As of December 31, 2005, the Company has stock-based compensation plans for certain employees +and officers. These plans are described below: +The +Company maintains a long-term equity compensation plan for officers and certain +key employees of the Company. Under the plan, approved by the shareholders in +June 2004, awards may be issued in the form of stock options, stock +appreciation rights, restricted stock, or performance shares. A total of +750,000 shares of common stock have been reserved for issuance. These awards +vest over periods set at the discretion of the Compensation Committee of the +Company's Board of Directors and have a maximum exercisable period of ten +years. During 2005 and 2004 the Company granted 14,000 shares and 23,380 +shares, respectively, with restriction periods of four years at the market +price on the date of issuance as deferred compensation to certain officers of +the Company. The related compensation amount is being amortized to expense over +the respective vesting periods and totaled $596,700 and $3,700 for the years +ended December 31, 2005 and 2004, respectively. +The +Company also maintains a restricted stock plan for non-employee directors. A +total of 40,000 shares of common stock have been reserved for issuance under +the plan which was approved by shareholders in June 2005. The stock is subject +to restrictions ending on the earliest of various retirement or termination +dates, including certain provisions for change in control. On July 8, 2005, 6,895 shares were granted at a price of $29.00 per share. Compensation +expense for the year ended December 31, 2005 related to these shares of restricted stock was $63,300. +Options +amounting to 16,880 shares were granted during 2004 to certain officers and +directors under the Company's Stock Option Plan. These options were granted +with an exercise price equal to the market value of the Company's common stock +as of the date of grant and vest over a four year period. The outstanding +options expire in 2014. +F-17 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +The +following table summarizes the activity of the Company's option plans: +Average +Range of +Number +Exercise +Exercise +of Shares +Price +Prices +Outstanding +January 1, 2003 +1,160,000 +$4.48 +$1.125 - 6.25 +Granted +- +- +- +Exercised +- +- +- +Outstanding +December 31, 2003 +1,160,000 +4.48 +1.125 - 6.25 +Granted +16,880 +37.15 +37.15 +Exercised +(1,100,000) +4.48 +1.125-6.25 +Outstanding +December 31, 2004 +76,880 +11.64 +3.875-37.15 +Granted +- +- +- +Exercised +(3,000) +3.88 +3.875 +Outstanding +December 31, 2005 +73,880 +$11.96 +$3.875-37.15 +Options +outstanding under the Company's plans as of December 31, 2005: +Option +Range of +Options +Remaining +Options +Weighted-Average +Grant +Expiration +Vesting +Exercise Price +Outstanding +Life +Exercisable +Exercise Price +Date +Date +Period +$3.875 - $6.25 +57,000 +2.9 years +57,000 +$4.50 +1999 +2009 +Less than 1 +year +$37.15 +16,880 +9 years +4,218 +$37.15 +2004 +2014 +1 to 4 years +Total +73,880 +61,218 +Common +Stock Repurchase +On March 13, 2003, the Company publicly announced the authorization by its Board of Directors +to repurchase up to 5% of the Company's common stock (785,000 shares) at fair +market value at the date of purchase. Under the program, management had +discretion as to the dates of purchase and amounts of stock to be purchased and +whether or not to make purchases. From inception of the program until December 31, 2004, the Company has repurchased 109,200 shares at an average price of $6.86 +for a total purchase price of approximately $749,100. This program expired on December 31, 2004. +In +March 2004, the Compensation Committee of the Board of Directors approved a +repurchase of 48,650 shares of common stock from one of the Company's +officers. The repurchase price of the common stock was the closing price on +the date of the repurchase of $26.61 per share and totaled $1,294,600 which +approximated the tax savings to be realized by the Company as a result of the +exercise of said officer's non-qualified stock options in 2004. The Company +also repurchased 1,703 shares from an employee upon retirement from the Company +in June, 2004 and the treasury stock was subsequently cancelled. +On March 18, 2005, the Company publicly announced the authorization by its Board of Directors +to repurchase up to 2% of the Company's outstanding common stock (331,796 +shares) at fair market value at the date of purchase. At a meeting held June 10, 2005, the Board of Directors of Petroleum Development Corporation approved an +amendment of the size of the stock repurchase from 2% to 10% (1,658,980 shares) +of the Company's then outstanding common stock. Under the program, the Board +has discretion as to the dates of purchase and amounts of stock to be purchased +and whether or not to make purchases. This program expired on December 31, 2005. The following activity has occurred since inception of the plan on March 18, 2005 until December 31, 2005. +Month of Purchase +May, 2005 +Average Price Paid +per Share +$23.75 +Broker/Dealer +McDonald Investments +Number of Shares +Purchased +331,796 +Remaining Number of +Shares to Purchase +1,327,184 +F-18 +On January 13, 2006, the Company publicly announced that +its Board of Directors authorized the repurchase of up to 10% (1,627,500 +shares) of the Company's common stock during 2006. Stock repurchases under this +program may be made in the open market or in private transactions, at times and +in amounts that management deems appropriate. The Company may terminate or +limit the stock repurchase program at any time. The following activity has +occurred since inception of the plan on January 13, 2006 until May 10, 2006. +Month of Purchase +January, 2006 +Average Price Paid +per Share +$39.33 +Broker/Dealer +McDonald +Investments +Number of Shares +Purchased +258,169 +Remaining Number +of Shares to Purchase +1,369,331 +Stock +Repurchase Agreement +The +Company had stock repurchase agreements with four executive officers of the +Company. These agreements were eliminated in December, 2005. The agreements +required the Company to maintain life insurance on each executive in the amount +of $1,000,000. The agreements required the Company to utilize the proceeds +from the insurance to purchase from the executives' estates or heirs, at their +option, shares of the Company's stock in the event of the executive's death. +The purchase price for the outstanding common stock was to be based upon the +average closing asked price for the Company's stock as quoted by NASDAQ on the +date of purchase. The Company is not required to purchase any shares in excess +of the amount provided for by such insurance. During the fourth quarter of +2003, the Company received $1,000,000 in life insurance proceeds which was +recorded as other income from the death of the Company's Chief Financial +Officer who had a stock repurchase agreement. In May 2004, the Company repurchased +50,487 shares of common stock from the estate of the Company's former officer +in accordance with the terms of this agreement. The repurchase price of the +stock was $27.73 per share (the 90-day average prior to the repurchase per +contract). The repurchase totaled $1,400,000 of which $1,000,000 was funded by +the life insurance proceeds. +(7) Employee +Benefit Plans +The +Company sponsors a qualified deferred compensation plan (401-K) that enables +eligible employees to contribute a portion of their compensation through +payroll deductions in accordance with specific guidelines. The Company matches +a percentage of the employees' contributions up to certain limits. Expenses +related to this plan amounted to $450,700, $382,700 and $305,500 for 2005, 2004 +and 2003, respectively. +The +Company has a profit sharing plan covering full-time employees. The Company +contributed $420,000, $300,000, and $250,000 to the plan in cash during 2005, +2004 and 2003, respectively. +During +2003 the Company expensed $90,000 under a deferred compensation arrangement +with certain executive officers of the Company. This amount was paid to the +executive officers during 2003. +The +Company has a deferred compensation arrangement covering certain executive +officers of the Company as a supplemental retirement benefit. During 2005, 2004 +and 2003 the Company expensed $169,000, $171,900 and $181,900, respectively, +and has recorded a related liability in the amount $1,129,200 and $1,000,200 as +of December 31, 2005 and 2004, respectively. The Company began paying the +retirement benefit during 2004 to the estate of one of the Company's former +officers. The Company paid $40,000 for each of the years 2005 and 2004. +The +Company maintains a non-qualified deferred compensation plan created for +non-employee directors of the Company. The amount of compensation deferred by +each Participant is based on Participant elections. +F-19 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +(8) Earnings Per +Share +2005 +2004 +2003 +Basic earnings per common share: +Net income before cumulative effect of +change in +accounting principle +$41,451,700 +$33,227,600 +$22,683,700 +Cumulative effect of accounting change, net +of tax +- +- +(2,271,300) +Net income +$ 41,451,700 +$ 33,227,600 +$ 20,412,400 +Weighted average common shares outstanding +16,361,530 +16,239,454 +15,659,591 +Basic earnings per common share +$ 2.53 +$ 2.05 +$ 1.30 +Diluted earnings per common and common +equivalent share: +Net income before cumulative effect of change in +accounting principle +$41,451,700 +$33,227,600 +$22,683,700 +Cumulative effect +of accounting change, net of tax +- +- +(2,271,300 ) +Net income +applicable to common stock +$ 41,451,700 +$ 33,227,600 +$ 20,412,400 +Weighted average +common shares outstanding +16,361,530 +16,239,454 +15,659,591 +Potentially dilutive securities: Stock options and awards +65,619 +367,177 +638,202 +Weighted average +common and common equivalent +shares outstanding +16,427,149 +16,606,631 +16,297,793 +Diluted earnings per common share +$ 2.52 +$ 2.00 +$ 1.25 +(9) Transactions +with Affiliates +Funds +held for future distribution on the consolidated balance sheets of $18,346,300 +and $12,911,800 primarily represents amounts owed to affiliated partnerships as +of December 31, 2005 and 2004, respectively. +The +Company provided oil and gas well drilling services and well operations and +pipeline services to affiliated partnerships. Substantially all of the +Company's revenue and expenses related to oil and gas well drilling operations +and revenues from well operations and pipeline income are associated with +services provided to the investing partners. Amounts due from the affiliated +partnerships as of December 31, 2005 and 2004 were $7,233,800 and $2,230,600, +respectively and are principally amounts due from the Partnerships related to +derivative positions. +Management +fees collected from the affiliated partnerships amounted to $1.7 million, $1.5 +million and $2.0 million for the years ended December 31, 2005, 2004 and 2003, +respectively, and are included in other income on the accompanying consolidated +statements of income. +Revenues +from oil and gas well drilling operations and costs of oil and gas well +drilling operations each include $218,700, $102,500 and $55,800 during 2005, +2004 and 2003, respectively related to investments made by officers of the +Company in working interests in wells drilled during the respective years. +The +Company through its wholly-owned subsidiary, PDC +Securities Incorporated, acts as Dealer-Manager of the Drilling Partnerships. PDC Securities Incorporated receives the applicable +commissions and marketing allowances from the Escrow Agent of the Drilling +Program and distributes them to the Soliciting Broker/Dealers who sell the +programs. The commissions and marketing allowances received by PDC Securities are included in other income net of +the commissions distributed to the soliciting broker/dealer. The net +commissions and marketing allowance amounts included in other income were less +than $1,000 for each of the years ending December 31, 2005, 2004 and 2003, respectively. The commissions and marketing allowances received by PDC +Securities and distributed to the Soliciting Broker/Dealers amounted to +$11,353,400, $9,747,500 and $7,994,300 for the years ended December 31, 2005, 2004, and 2003, respectively. +F-20 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +During +2005, 2004, and 2003, the Company paid $25,900, $22,500, and $30,000, +respectively, to the Corporate Secretary's law firm for various legal services. +(10) Commitments +and Contingencies +The +nature of the independent oil and gas industry involves a dependence on outside +investor drilling capital and involves a concentration of gas sales to a few +customers. The Company sells natural gas to various public utilities, gas +marketers and industrial customers. No customer accounted for 10% or more of +the Company's total revenues in 2005 or 2004. One customer accounted for 11.1% +of total revenues in 2003. +The +Company would be exposed to natural gas price fluctuations on underlying +purchase and sale contracts should the counterparties to the Company's +derivative instruments or the counterparties to the Company's gas marketing +contracts not perform. Nonperformance is not anticipated. There were no +counterparty default losses in 2005, 2004 or 2003. +Substantially +all of the Company's drilling programs contain a repurchase provision where +Investing Partners may request that the Company purchase their partnership +units at any time beginning with the third anniversary of the first cash +distribution. The provision provides that the Company is obligated to purchase +an aggregate of 10% of the initial subscriptions per calendar year (at a +minimum price of four times the most recent 12 months' cash distributions), if +repurchase is requested by investors, and subject to the Company's financial +ability to do so. The maximum annual repurchase obligation as of December 31, +2005 was approximately $9.2 million. The Company has adequate liquidity to meet +this obligation. During 2005 and 2004, the Company paid $352,000 and $408,300, +respectively, under this provision for the repurchase of partnership units. As +of December 31, 2005, outstanding repurchase offers to investing partners +totaled $256,400. In 2006, $70,700 of such outstanding offers were consummated +prior to their expiration. +The Company's drilling +programs formed since 1996 contain a performance supplement that requires the +Company to remit a payment equal to one-half of its share of revenue from the +partnership to the investing partners if certain levels of performance are not +met. During 2005, 2004, and 2003 the Company paid partnerships a total of +$689,700, $597,300 and $385,400, respectively in accordance with the provision. +As of December 31, 2005 based upon current oil and gas reserve reports of the +Partnerships with this provision, the maximum amount of this contingency is +$4.8 million. +As +Managing General Partner of 75 partnerships the Company has liability for any +potential casualty losses in excess of the partnership assets and insurance. +The Company's management believes the casualty insurance coverage carried by +the Company and its subcontractors is adequate to meet this potential +liability. +In +order to secure the services for drilling rigs, the Company made commitments to +the drilling contractors which call for a minimum commitment of $24,000 daily +for a specified amount of time if the Company ceases to use the drilling rigs, +an event that is not anticipated to occur, and a maximum commitment of $55,400 +daily for a specified amount of time for daily use of the drilling rigs. As of December 31, 2005, commitments for these three separate contracts expire in May of 2008, +July of 2009, and May of 2010. As of December 31, 2005, the Company has an outstanding minimum commitment for $22,524,000, and an outstanding maximum +commitment for $59,627,000. +From +time to time the Company is a party to various legal proceedings in the +ordinary course of business. The Company is not currently a party to any +litigation that it believes would have a materially adverse affect on the +Company's business, financial condition, results of operations, or liquidity. +(11) Lease +Obligations +The +Company has entered into operating leases on behalf of itself and its +Partnerships principally for the leasing of natural gas compressors on its Michigan operating facilities and office printing and copying equipment. The future minimum +lease payments under these non-cancelable operating leases as of December 31, 2005 are as follows: +F-21 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +Year +Lease Amount +2006 +$356,300 +2007 +297,500 +2008 +291,600 +2009 +291,000 +2010 +167,800 +Thereafter +28,000 +$ 1,432,200 +The Company's share +of this lease expense for operating leases for the years ended December 31, 2005, 2004 and 2003 was $313,000, $310,000 and $574,700, respectively. +(12) Supplemental +Disclosure of Cash Flows +The +Company paid $101,300, $1,049,200 and $1,274,003 for interest in 2005, 2004 and +2003, respectively. The Company paid income taxes in 2005, 2004 and 2003 in +the amounts of $10,675,000, $5,027,800 and $3,649,600, respectively. +During 2004, 337,360 +options were exercised by employees exchanging 62,999 mature shares of stock +with a fair value of $1,408,300. All these mature shares were subsequently +cancelled. +(13) Derivative +Financial Instruments +The Company utilizes +commodity based derivative instruments to manage a portion of its exposure to +price risk from its oil and natural gas sales and marketing activities. Company +policy prohibits the use of oil and natural gas future and option contracts for +speculative purposes. These instruments consist of NYMEX-traded natural gas +futures contracts and option contracts for Appalachian and Michigan production, +Panhandle-based contracts traded by BNP Paribas and NYMEX-traded contracts for +NECO production and CIG-based contracts traded by JP Morgan for other Colorado +production. These derivative instruments have the effect of locking in for +specified periods (at predetermined prices or ranges of prices) the prices the +Company will receive for the volume to which the derivative relates and, in the +case of RNG, the cost of gas supplies purchased for marketing activities. As a +result, while these derivatives are structured to reduce the Company's exposure +to changes in price associated with the derivative commodity, they also limit +the benefit the Company might otherwise have received from price changes +associated with the derivative commodity. RNG also enters into fixed-price +physical purchase and sale agreements that are derivative contracts. +The fair value of the +commodity based derivatives was $(9,365,700) and $(2,202,300) at December 31, 2005 and 2004, respectively. The Company recognized in the statement of +income an unrealized gain (loss) on commodity based derivatives of +$(3,225,900), $(1,127,900) and $632,600 for the years ended December 31, 2005, 2004, and 2003, respectively. +The following tables +summarize the open derivative option and purchase and sales contracts for Riley +Natural Gas and the Company as of December 31, 2005 and 2004. +F-22 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +Riley Natural Gas +Open Derivative Positions +Quantity +Weighted +Total Contract +Commodity +Type +Gas-Mmbtu +Average Price +Amount +Fair Value +Total +Positions as of December 31, 2005 +Natural Gas +Cash Settled +Futures/Swaps Purchases +1,025,500 +$ 9.05 +$9,283,010 +$ 1,983,352 +Natural Gas +Cash Settled +Futures/Swaps Sales +3,149,000 +$ 7.95 +$25,018,610 +$ (8,688,840) +Natural Gas +Cash Settled +Basis Swap Purchases +450,000 +$ 0.91 +$409,500 +$ (157,663) +Natural Gas +Cash Settled +Basis Swap Sales +240,000 +$ 0.50 +$120,000 +$ 3,700 +Natural Gas +Physical +Purchases +2,819,000 +$ 8.32 +$23,456,726 +$ 7,858,489 +Natural Gas +Physical Sales +585,222 +$ 10.72 +$6,272,822 +$ (670,419) +Natural Gas +Physical Basis +Purchases +240,000 +$ 0.45 +$108,000 +$ 8,300 +Natural Gas +Physical Basis +Sales +450,000 +$ 0.94 +$420,750 +$ 168,913 +Positions +maturing in 12 months following December 31, 2005 +Natural Gas +Cash Settled +Futures/Swaps Purchases +1,025,500 +$ 9.05 +$9,283,010 +$ 1,983,352 +Natural Gas +Cash Settled +Futures/Swaps Sales +2,709,000 +$ 8.12 +$21,991,390 +$ (7,185,253) +Natural Gas +Cash Settled +Basis Swap Purchases +450,000 +$ 0.91 +$409,500 +$ (157,663) +Natural Gas +Cash Settled +Basis Swap Sales +220,000 +$ 0.50 +$110,000 +$ 4,900 +Natural Gas +Physical +Purchases +2,379,000 +$ 8.71 +$20,717,126 +$ 5,966,998 +Natural Gas +Physical Sales +585,222 +$ 10.72 +$6,272,822 +$ (670,419) +Natural Gas +Physical Basis +Purchases +220,000 +$ 0.45 +$99,000 +$ 6,100 +Natural Gas +Physical Basis +Sales +450,000 +$ 0.94 +$420,750 +$ 168,913 +Prior Year +Total Positions as of December 31, 2004 +Natural Gas +Cash Settled +Sale +3,260,000 +$ 5.60 +$18,249,250 +$ (1,982,964) +Natural Gas +Cash Settled +Purchase +1,130,000 +$ 6.77 +$7,644,540 +$ (486,490) +Natural Gas +Cash Settled +Sale Option +530,000 +$ 5.30 +- +$ 134,242 +Natural Gas +Cash Settled +Purchase Option +265,000 +$ 7.00 +- +$ (85,541) +Natural Gas +Physical +Contract Sale +1,136,230 +$ 6.96 +$7,908,865 +$ 1,268,721 +Natural Gas +Physical +Contract Purchase +3,223,000 +$ 5.82 +$18,747,564 +$ 1,882,984 +The maximum +term for the derivative contracts listed above is 34 months. +F-23 +Petroleum Development Corporation +Open Derivative Positions +Quantity +Gas-Mmbtu +Weighted +Total Contract +Commodity +Type +Oil-Barrels +Average Price +Amount +Fair Value +Total +Positions as of December 31, 2005 +Natural Gas +Cash Settled +Option Sales +5,665,000 +$8.17 +$46,273,550 +$ (12,531,796) +Natural Gas +Cash Settled +Option Purchases +14,030,000 +$6.36 +$89,210,000 +$ 2,660,289 +Positions +maturing in 12 months following December 31, 2005 +Natural Gas +Cash Settled +Option Sales +4,930,000 +$8.07 +$39,802,550 +$ (10,411,106) +Natural Gas +Cash Settled +Option Purchases +12,560,000 +$6.38 +$80,165,000 +$ 2,251,533 +Prior Year +Total Positions as of December 31, 2004 +Natural Gas +Purchase +120,000 +$6.63 +$796,150 +$ (45,680) +Natural Gas +Sale Option +7,400,000 +$4.46 +- +$ 917,553 +Natural Gas +Purchase +Option +3,475,000 +$5.42 +- +$ (3,138,210) +Crude Oil +Sale Option +360,000 +$32.30 +- +$ 306,702 +Crude Oil +Purchase +Option +180,000 +$40.00 +- +$ (973,638) +The maximum +term for the derivative contracts listed above is 15 months. +In addition to including +the gross assets and liabilities related to the Company's share of oil and gas +production, the above tables and the accompanying consolidated balance sheets +include the gross assets and liabilities related to derivative contracts +entered into by the Company on behalf of the affiliate Partnerships as the +Managing General Partner. The accompanying consolidated balance sheets include +the negative fair value of derivatives and a corresponding receivable from the +Partnerships of $5,351,500 as of December 31, 2005 and $1,418,000 as of +December 31, 2004. In addition to the short-term fair value of derivatives +shown in the accompanying consolidated balance sheet there are long-term assets +and long-term liabilities which total to a net long-term liability of +approximately $1,323,100 as of December 31, 2005 and which total to a net long-term +asset of approximately $1,248,000 as December 31, 2004, respectively related to +the fair value of derivatives included in accompanying balance sheet. +The Company is required to +maintain margin deposits with brokers for outstanding futures contracts. As of +December 31, 2005 and 2004, cash in the amount of $1,500,600 and $664,900 was +on deposit. +An interest rate swap +agreement was used to reduce the potential impact of increases in interest +rates on variable rate long-term debt. The swap agreement expired in October +2004. The agreement required the Company, on a quarterly basis, to make a +fixed-rate interest payment of 6.89% plus its current LIBOR rate margin (+1.50% +At December 31, 2003) on a $10,000,000 amount related to its outstanding line +of credit. +The fair value of the +interest rate swap agreement was a liability of $592,700 at December 31, 2003. Current market pricing models were used to estimate fair value. The change in the +fair value of the swap is included in interest expense; the related gain was +$592,700 and $477,600 for the years ended December 31, 2004 and, 2003, respectively. +By using derivative +financial instruments to manage exposures to changes in interest rates and +commodity prices, the Company exposes itself to credit risk and market risk. +Credit risk is the failure of the counterparty to perform under the terms of +the derivative contract. When the fair value of a derivative contract is +positive, the counterparty owes the Company, which creates repayment risk. The +Company minimizes the credit or repayment risk in derivative instruments by +entering into transactions with high-quality counterparties. There were no +counterparty defaults during the years ended December 31, 2005, 2004 and 2003. +F-24 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +Changes in the fair value +of commodity based derivatives are recorded in earnings because they do not +qualify for hedge accounting. These changes are included in the following +income statement captions: +Income Statement Caption +Oil +and gas price risk management loss (gain), +net +Includes realized and unrealized gains +and losses on commodity based derivatives related to the +Company's +oil and gas sales. +Gas +sales from marketing activities +Cost +of gas marketing activities +Includes realized and unrealized gains +and losses on +commodity based derivatives +related to the RNG gas +sales and purchases. +(14) Purchases +and Sales of Oil and Gas Properties +During +the first quarter of 2005, the Company sold a portion of one of its undeveloped +Garfield County, Colorado leases to an unaffiliated entity. The proceeds of +the sale were $6.2 million and the Company's carrying value of the property was +zero. The Company was required to remit $1.0 million to the original lessor, +unless it commenced construction of certain facilities adjacent to this +undeveloped property subject to certain timing conditions. The gain of $5.2 +million was recognized during the first quarter of 2005 and is included in +"Other Income" in the accompanying consolidated statements of income. During +the second quarter of 2005, the Company commenced construction of the +facilities and recorded income of $1.0 million which is included in "Other +income" in the accompanying consolidated statements of income. +During +the second quarter of 2005, the Company completed the sale to an unaffiliated +entity of 111 Pennsylvania wells it purchased from Pemco Gas, Inc. in 1998. +The Company received proceeds of $3.4 million and recorded a gain of +approximately $1.7 million which is included in "Other income" in the +accompanying consolidated statements of income. +During +the second quarter of 2003, the Company purchased 166 wells in the Denver Julesburg Basin in northeastern Colorado from Williams Production RMT Company for $28 +million. The Company estimates the acquisition included approximately 22.6 +billion cubic feet (Bcf) of proved developed producing (PDP) and 3.4 Bcf of +proved developed non-producing reserves (PDNP), all of which is natural gas. +The Company received approval for increased density well spacing in 2004. The +Company drilled 20 new Niobrara wells on the property in 2004 and 72 wells in +2005. +During +the fourth quarter of 2003, the Company purchased from one of its unaffiliated +joint venture partners in the Denver-Julesburg Basin in Weld County, Colorado +approximately 3.1 billion cubic feet equivalent (Bcfe) of proved developed +producing reserves from interests in 20.6 net wells (230 gross) and 1.8 Bcfe of +proved developed non-producing reserves from interests in 17 net wells (183 +gross). The purchase price was $5.2 million which also included over 30 +additional drilling locations. +During +the fourth quarter of 2003, the Company purchased from an unaffiliated party 97 +gross wells (73 net) in the Denver-Julesburg Basin located in northeast +Colorado and northwestern Kansas for $6.0 million. This purchase added +approximately 4.5 billion cubic feet equivalent (Bcfe) of proved developed +producing and proved developed non-producing reserves to the Company's oil and +gas reserves along with 100,000 acres of oil and gas leases. +(15) Costs +Incurred in Oil and Gas Property Acquisition, Exploration and Development +Activities (unaudited) +Costs +incurred by the Company in oil and gas property acquisition, exploration and +development are presented below: +Years Ended December 31, +2005 +2004 +2003 +Acquisition of +properties: +Unproved +properties +$16,910,200 +$ 4,583,000 +$ 6,167,800 +Proved +properties +1,608,300 +720,000 +33,946,600 +Development costs +68,605,000 +32,700,500 +30,630,100 +Exploration costs +12,942,700 +4,169,900 +- +$ 100,066,200 +$ 42,173,400 +$ 70,744,500 +F-25 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +The +proved reserves attributable to the development costs in the above table were +85,624,000 Mcf and 1,576,000 Bbls for 2005, 40,716,000 Mcf and 358,000 Bbls for +2004, 27,719,000 Mcf and 517,000 Bbls for 2003 (amounts unaudited). Of the +above development costs incurred for the years ended December 31, 2005, 2004, and 2003 the amounts of $6,935,400, $1,819,619, and $4,289,600, +respectively, were incurred to develop proved undeveloped properties from the +prior year end. +Property +acquisition costs include costs incurred to purchase, lease or otherwise +acquire a property. Development costs include costs incurred to gain access to +and prepare development well locations for drilling, to drill and equip +development wells, recompletions and to provide facilities to extract, treat, +gather and store oil and gas. +(16) Oil +and Gas Capitalized Costs (unaudited) +Aggregate +capitalized costs for the Company related to oil and gas exploration and +production activities with applicable accumulated depreciation, depletion and +amortization are presented below: +December 31, +2005 +2004 +Proved +oil and gas properties +$ 345,533,300 +$ 274,631,900 +Unproved +oil and gas properties +19,846,300 +8,205,300 +365,379,600 +282,837,200 +Less +accumulated depreciation, +depletion +and amortization +102,513,400 +84,576,100 +$ 262,866,200 +$ 198,261,100 +Suspended +Well Costs +The following table lists +the capitalized exploratory well costs which are pending the determination of +proved reserves. +Balance, +January 1, 2003 +$ - +Additions +- +Charged to +expense +- +Balance, +January 1, 2003 +- +Addition - +Fox Federal #1-13 +4,169,900 +Charged to +expense +- +Balance, +December 31, 2004 +4,169,900 +Addition - +Violet Olsen 34-2914 +1,401,500 +Addition - +Norgaard #1 +516,900 +Addition - +Fedora +4,523,400 +Reclassification to wells, facilities and +equipment +based on determination of +proved +reserves +(4,523,400) +Charged to +expense - Fox Federal #1-13 +(4,169,900) +Balance, +December 31, 2005 +$1,918,400 +Both +of the above referenced wells with costs as of December 31, 2005 were drilled in the fourth quarter of 2005. The wells were completed and evaluated in 2006 and +were deemed to have proved reserves. +None +of the wells listed in the table have been capitalized for more than one year waiting +for a proved reserve determination. +F-26 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +Exploratory +dry hole costs of $11.1 million in the accompanying consolidated statements of +income include the $4.2 million above related to costs incurred in 2004 on the +Fox Federal #1-13 well plus $6.9 million of costs incurred and expensed during +2005. The 2005 costs incurred and expensed included an additional $1.2 million +related to the Fox Federal #1-13 well, approximately $5.42 million related to +the Coffeepot Springs #24-34 well in Colorado and four Kansas wells which +totaled $314,200. +(17) Results +of Operations for Oil and Gas Producing Activities (unaudited) +The +results of operations for oil and gas producing activities (excluding +marketing) are presented below: +Years Ended December 31, +2005 +2004 +2003 +(Restated) +(Restated) +Revenue: +Oil and gas sales +$102,559,200 +$69,492,100 +$48,393,800 +Expenses: +Production costs +16,193,400 +14,201,300 +9,714,600 +Oil and gas price risk management loss, net +9,368,100 +3,084,600 +812,400 +Depreciation, depletion and amortization +19,322,200 +16,680,200 +14,157,000 +Exploratory dry hole costs +11,115,100 +- +- +55,998,800 +33,966,100 +24,684,000 +Results of operations for oil and gas +producing activities before provision +for income taxes +46,560,400 +35,526,000 +23,709,800 +Provision for income taxes +18,112,000 +13,819,600 +9,223,100 +Results of operations for oil and gas +producing activities (excluding corporate +overhead and interest costs) +$28,448,400 +$21,706,400 +$14,486,700 +Production +costs include those costs incurred to operate and maintain productive wells and +related equipment, including costs such as labor, repairs, maintenance, +materials, supplies, fuel consumed, insurance and production taxes. In +addition, production costs include administrative expenses and depreciation +applicable to support equipment associated with these activities. Depreciation, +depletion and amortization expense includes those costs associated with +capitalized acquisition, exploration and development costs, but does not +include the depreciation applicable to support equipment. The provision for +income taxes is computed using statutory tax rates. +F-27 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +(18) Net +Proved Oil and Gas Reserves (Unaudited) +The +proved reserves of oil and gas of the Company have been estimated by +independent petroleum engineers at December 31, 2005, 2004 and 2003. These reserves have been prepared in compliance with the Securities and Exchange +Commission and Financial Accounting Standards Board rules which require that +reserve reports be prepared under economic and operating conditions existing at +the Company's year-end with no provision for price and cost escalation except +by contractual arrangements. An analysis of the change in estimated quantities +of oil and gas reserves, all of which are located within the United States, is shown below: +Oil (Bbls) +2005 +2004 +2003 +Proved developed +and undeveloped reserves: +Beginning +of year +3,316,000 +3,029,000 +2,073,000 +Revisions +of previous estimates +80,000 +305,000 +533,000 +Beginning +of year as revised +3,396,000 +3,334,000 +2,606,000 +New +discoveries and extensions: +Rocky +Mountain Region +1,576,000 +358,000 +517,000 +Sales +of reserves to partnerships +- +(12,000) +(112,000) +Purchase +of reserves: +Rocky Mountain +Region +5,000 +17,000 +307,000 +Production +(439,000 ) +(381,000) +(289,000 ) +End +of year +4,538,000 +3,316,000 +3,029,000 +Proved developed +reserves: +Beginning +of year +3,190,000 +2,889,000 +1,849,000 +End +of year +3,860,000 +3,190,000 +2,889,000 +Gas (Mcf) +2005 +2004 +2003 +Proved developed +and undeveloped reserves: +Beginning +of year +197,549,000 +180,998,000 +128,851,000 +Revisions +of previous estimates +(15,850,000 ) +(10,635,000) +4,394,000 +Beginning +of year as revised +181,699,000 +170,363,000 +133,245,000 +New +discoveries and extensions: +Rocky +Mountain Region +85,624,000 +40,716,000 +27,719,000 +Dispositions +to partnerships +(9,556,000) +(4,240,000) +(4,410,000) +Purchases +of reserves: +Michigan Basin +47,000 +96,000 +265,000 +Rocky +Mountain Region +71,000 +242,000 +32,169,000 +Appalachian +Basin +434,000 +744,000 +722,000 +Production +(11,031,000 ) +(10,372,000 ) +(8,712,000 ) +End +of year +247,288,000 +197,549,000 +180,998,000 +Proved developed +reserves: +Beginning +of year +146,152,000 +134,936,000 +94,847,000 +End +of year +155,354,000 +146,152,000 +134,936,000 +F-28 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to Consolidated +Financial Statements +(19) Standardized +Measure of Discounted Future Net Cash Flows and Changes Therein Relating to +Proved Oil and Gas Reserves (Unaudited) +Summarized +in the following table is information for the Company with respect to the standardized +measure of discounted future net cash flows relating to proved oil and gas +reserves. Future cash inflows are computed by applying year-end prices of oil +and gas relating to the Company's proved reserves to the year-end quantities of +those reserves. Future production, development, site restoration and +abandonment costs are derived based on current costs assuming continuation of +existing economic conditions. Future income tax expenses are computed by +applying the statutory rate in effect at the end of each year to the future +pretax net cash flows, less the tax basis of the properties and gives effect to +permanent differences, tax credits and allowances related to the properties. +2005 +2004 +2003 +Future +Estimated Cash Flows +$ +2,381,238,000 +$ +1,298,394,000 +$ +1,088,415,000 +Future +Estimated Production Costs +(545,683,000) +(319,065,000) +(250,735,000) +Future +Estimated Development Costs +(207,164,000) +(95,498,000) +(65,275,000) +Future +Estimated Income Tax Expense +(633,444,000) +(343,810,000) +(1) +(300,466,000) +(1) +Future Net +Cash Flows +994,947,000 +540,021,000 +(1) +471,939,000 +(1) +10% Annual +Discount for Estimated +Timing +of Cash Flows +(589,517,000) +(310,593,000) +(1) +(269,556,000) +(1) +Standardized +Measure of Discounted +Future +Estimated Net Cash Flows +$ +405,430,000 +$ +229,428,000 +(1) +$ 202,383,000 +(1) +(1) +Amounts +restated since the filing of the December 31, 2004 Form 10-K/A. +F-29 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +The +following table summarizes the principal sources of change in the standardized +measure of discounted future estimated net cash flows: +2005 +2004 +2003 +(Restated) +(Restated) +Sales of oil +and gas production +net +of production costs +$ +(86,366,000) +$ +(55,291,000) +$ (38,679,000) +Net changes in +prices and production costs +208,353,000 +26,768,000 +73,241,000 +Extensions, +discoveries, and improved +recovery, +less related costs +150,654,000 +51,413,000 +51,583,000 +Sales of +reserves +(14,456,000) +(7,565,000) +(5,637,000) +Purchase of +reserves +1,266,000 +1,953,000 +68,104,000 +Development +costs incurred during the period +24,035,000 +8,495,000 +10,400,000 +Revisions of +previous quantity estimates +(24,130,000) +6,312,000 +13,906,000 +Changes in +estimated income taxes +(112,054,000) +(16,160,000) +(73,907,000) +Accretion of +discount +38,241,000 +33,500,000 +15,182,000 +Timing and +other +(9,541,000) +22,380,000 +2,363,000 +Total +$ +176,002,000 +$ +27,045,000 +$ +116,556,000 +It is +necessary to emphasize that the data presented should not be viewed as +representing the expected cash flow from, or current value of, existing proved +reserves since the computations are based on a large number of estimates and +arbitrary assumptions. Reserve quantities cannot be measured with precision +and their estimation requires many judgmental determinations and frequent +revisions. The required projection of production and related expenditures over +time requires further estimates with respect to pipeline availability, rates of +demand and governmental control. Actual future prices and costs are likely to +be substantially different from the current prices and costs utilized in the +computation of reported amounts. Any analysis or evaluation of the reported +amounts should give specific recognition to the computational methods utilized +and the limitations inherent therein. +The estimated +present value of future cash flows relating to proved reserves is extremely +sensitive to prices used at any measurement period. The average prices used for +each commodity for the years ended December 31, 2005, 2004 and 2003 were as follows: +Average Price +As of December 31: +Oil +Gas +2005 +$58.25 +$8.56 +2004 +$41.63 +$5.87 +2003 +$31.80 +$5.48 +(20) Business +Segments (Thousands) +The Company's operating activities can be divided into four major +segments: drilling and development, natural gas marketing, oil and gas sales, +and well operations. The Company drills natural gas wells for Company-sponsored +drilling partnerships and retains an interest in each well. A wholly-owned +subsidiary, Riley Natural Gas, engages in the marketing of natural gas to +commercial and industrial end-users. The Company owns an interest in +approximately 2,800 wells from which it derives oil and gas working interests. +The Company charges Company-sponsored partnerships and other third parties +competitive industry rates for well operations and gas gathering. All material +inter-company accounts and transactions between segments have been eliminated. +Segment information for the years ended December 31, 2005, 2004 and 2003 is as follows: +F-30 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +2005 +2004 +2003 +(Restated) +(Restated) +REVENUES +Drilling +and Development +$ 99,963 +$ 94,076 +$ 57,509 +Natural Gas Marketing +121,387 +94,675 +73,186 +Oil and Gas Sales +102,559 +69,492 +48,394 +Well +Operations +8,760 +7,677 +6,907 +Unallocated +amounts (1) +10,464 +1,833 +3,475 +$ 343,133 +$ 267,753 +$ 189,471 +SEGMENT +INCOME BEFORE INCOME TAXES +Drilling +and Development +$ 11,778 +$ 16,380 +$ 10,564 +Natural +Gas Marketing +1,737 +1,784 +815 +Oil +and Gas Sales (3) +46,560 +35,526 +23,710 +Well +Operations +3,539 +3,695 +2,618 +Unallocated +amounts (1) +General +and Administrative expenses +(6,960) +(4,506) +(4,974) +Interest +expense +(682) +(674) +(1,195) +Other +(2) +10,156 +1,273 +3,079 +Total +$ 66,128 +$ 53,478 +$ 34,617 +SEGMENT +ASSETS +Drilling +and Development +$ 89,030 +$ 64,348 +$ 62,546 +Natural +Gas Marketing +56,518 +31,234 +17,007 +Oil +and Gas Sales +256,621 +211,255 +194,371 +Well +Operations +31,407 +16,518 +11,602 +Unallocated +amounts +Cash +3,383 +112 +800 +Other +12,126 +11,561 +11,216 +Total +$ 449,085 +$ 335,028 +$ 297,542 +EXPENDITURES +FOR SEGMENT LONG-LIVED ASSETS +Drilling +and Development +$ - +$ - +$ - +Natural +Gas Marketing +1 +6 +- +Oil +and Gas Sales +100,066 +42,173 +69,756 +Well +Operations +3,949 +1,911 +2,944 +Unallocated +amounts +2,452 +1,302 +342 +Total +$ 106,468 +$ 45,392 +$ 73,042 +(1) Items which are not allocated in assessing +segment performance. +(2) Includes interest on investments, partnership +management fees and gains on sales of assets in 2005, 2004 and 2003 which are +not allocated in assessing segment performance. +(3) Includes $11.1 million in exploratory dry hole +costs for the year ended December 31, 2005. +F-31 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +(21) Quarterly Financial Data (Unaudited) +Quarterly +financial data for the years ended December 31, 2005, 2004 and 2003, are as follows: +2005 +Quarter +Year +First +Second +Third +Fourth +(Restated) +(Restated) +(Restated) +Revenues: +Oil and gas +well drilling operations +$ +25,366,300 +$ 28,110,800 +$ 32,266,600 +$ 14,219,200 +$ +99,962,900 +Gas sales +from marketing activities +17,522,000 +25,917,100 +14,970,300 +62,694,700 +121,104,100 +Oil and gas +sales +18,663,700 +21,542,800 +28,413,400 +33,939,300 +102,559,200 +Well +operations and pipeline income +1,927,100 +2,067,900 +2,290,900 +2,473,700 +8,759,600 +Other income +6,213,800 +3,492,600 +209,400 +831,500 +10,747,300 +Total revenues +69,692,900 +81,131,200 +78,150,600 +114,158,400 +343,133,100 +Costs and +expenses: +Cost of oil +and gas well drilling operations +20,644,100 +23,743,000 +28,733,500 +15,064,300 +88,184,900 +Cost of gas +marketing activities +17,901,600 +26,177,300 +14,269,500 +61,295,300 +119,643,700 +Oil and gas +production costs and well operations costs +3,978,100 +4,481,200 +6,263,000 +5,212,400 +19,934,700 +Exploratory +dry hole costs +- +4,864,000 +135,800 +6,115,300 +11,115,100 +General and +administrative expenses +1,617,500 +1,266,000 +1,645,500 +2,431,300 +6,960,300 +Depreciation, depletion and amortization +4,856,900 +4,845,100 +5,120,000 +6,294,200 +21,116,200 +Total costs and expenses +48,998,200 +65,376,600 +56,167,300 +96,412,800 +266,954,900 +Income from +operations +20,694,700 +15,754,600 +21,983,300 +17,745,600 +76,178,200 +Interest +expense +147,800 +143,000 +142,200 +249,300 +682,300 +Oil and gas +price risk management loss (gain), net +3,659,100 +(858,400) +9,922,300 +(3,354,900) +9,368,100 +Income before +income taxes +16,887,800 +16,470,000 +11,918,800 +20,851,200 +66,127,800 +Income taxes +6,247,900 +6,091,400 +4,413,000 +7,923,800 +24,676,100 +Net income +$ +10,639,900 +$ 10,378,600 +$ +7,505,800 +$ 12,927,400 +$ +41,451,700 +Basic earnings +per common share +$ +0.64 +$ +0.63 +$ +0.46 +$ +0.80 +$ +2.53 +Diluted +earnings per common and +common +equivalent share +$ +0.64 +$ +0.63 +$ +0.46 +$ +0.79 +$ +2.52 +F-32 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +2004 (Restated) +Quarter +Year +First +Second +Third +Fourth +Revenues: +Oil and +gas well drilling operations +$ 22,109,100 +$ +24,065,900 +$ 24,070,300 +$ +23,830,700 +$ 94,076,000 +Gas sales +from marketing actitities +22,058,900 +24,954,300 +22,630,200 +24,983,400 +94,626,800 +Oil and +gas sales +16,316,200 +16,209,000 +16,580,500 +20,386,400 +69,492,100 +Well +operations and pipeline income +1,706,900 +1,737,600 +1,875,000 +2,357,400 +7,676,900 +Other +income +58,100 +622,000 +589,000 +611,600 +1,880,700 +Total revenues +62,249,200 +67,588,800 +65,745,000 +72,169,500 +267,752,500 +Costs and +expenses: +Cost of +oil and gas well drilling operations +17,965,500 +19,579,400 +19,681,300 +20,470,000 +77,696,200 +Cost of +gas marketing activities +21,889,700 +24,605,800 +22,047,400 +24,338,300 +92,881,200 +Oil and +gas production and well operations costs +3,775,500 +3,796,200 +3,753,600 +5,951,900 +17,277,200 +General +and administrative expenses +994,200 +900,900 +926,300 +1,684,200 +4,505,600 +Depreciation, depletion and amoritization +4,544,400 +4,451,300 +4,312,300 +4,847,900 +18,155,900 +Total costs and expenses +49,169,300 +53,333,600 +50,720,900 +57,292,300 +210,516,100 +Income from +operations +13,079,900 +14,255,200 +15,024,100 +14,877,200 +57,236,400 +Interest +expense +209,600 +194,400 +223,100 +46,600 +673,700 +Oil and gas +price risk management loss (gain), net +830,000 +868,700 +2,378,800 +(992,900) +3,084,600 +Income +before income taxes +12,040,300 +13,192,100 +12,422,200 +15,823,500 +53,478,100 +Income taxes +4,334,400 +4,755,400 +4,506,400 +6,654,300 +(1) +20,250,500 +Net income +$ +7,705,900 +$ +8,436,700 +$ +7,915,800 +$ +9,169,200 +$ 33,227,600 +Basic +earnings per common share +$ +0.49 +$ +0.52 +$ +0.49 +$ +0.55 +$ +2.05 +Diluted +earnings per common and +common-equivalent share +$ 0.47 +$ +0.51 +$ +0.47 +$ +0.54 +$ +2.00 +(1) Includes +an adjustment of approximately $600,000 to the tax provision of the prior +three quarters. +F-33 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +2003 (Restated) +Quarter +Year +First +Second +Third +Fourth +Revenues: +Oil and gas +well drilling operations +$ +17,147,000 +$ 9,507,000 +$ 11,325,800 +$ 19,529,800 +$ +57,509,600 +Gas sales +from marketing actitities +20,651,000 +16,805,000 +20,370,200 +15,305,500 +73,131,700 +Oil and gas +sales +9,658,200 +11,213,200 +13,304,200 +14,218,200 +48,393,800 +Well +operations and pipeline income +1,542,800 +1,671,500 +1,747,500 +1,945,300 +6,907,100 +Other +income +327,400 +285,100 +488,300 +2,427,700 +3,528,500 +Total revenues +49,326,400 +39,481,800 +47,236,000 +53,426,500 +$ 189,470,700 +Costs and +expenses: +Cost of oil +and gas well drilling operations +13,325,300 +7,760,600 +9,201,400 +16,658,600 +$ +46,945,900 +Cost of gas +marketing activities +20,937,600 +16,443,700 +19,797,200 +15,182,900 +72,361,400 +Oil and gas +production and well operations cost +2,694,200 +3,363,300 +3,868,500 +3,325,300 +13,251,300 +General and +administrative expenses +1,177,700 +1,186,600 +1,377,300 +1,232,800 +4,974,400 +Depreciation, depletion and amoritization +3,146,400 +3,594,400 +4,140,100 +4,431,900 +15,312,800 +Total costs and expenses +41,281,200 +32,348,600 +38,384,500 +40,831,500 +$ 152,845,800 +Income from +operations +8,045,200 +7,133,200 +8,851,500 +12,595,000 +36,624,900 +Interest +expense +215,500 +257,300 +355,000 +367,500 +1,195,300 +Oil and gas +price risk-management loss(gain), net +788,400 +(426,400) +(550,900) +1,001,300 +812,400 +Income before +income taxes and cumulative +effect of +change in accounting principle +7,041,300 +7,302,300 +9,047,400 +11,226,200 +34,617,200 +Income taxes +2,324,500 +2,410,100 +2,986,900 +4,212,000 +11,933,500 +Net income +before cumulative effect of +change in +accounting principle +4,716,800 +4,892,200 +6,060,500 +7,014,200 +22,683,700 +Cumulative +effect of change in accounting +principle +(net of taxes of $1,392,000) +(2,271,300) +- +- +- +(2,271,300) +Net income +$ +2,445,500 +$ 4,892,200 +$ 6,060,500 +$ 7,014,200 +$ +20,412,400 +Basic earnings +per common share before +accounting +change +$ +0.30 +$ +0.31 +$ 0.39 +$ +0.45 +$ +1.45 +Cumulative +effect of change in +accounting +principle +$ +(0.15) +- +- +- +$ +(0.15) +Basic earnings +per common share +$ +0.15 +$ +0.31 +$ +0.39 +$ +0.45 +$ +1.30 +Diluted +earnings per share before +accounting +change +$ +0.29 +$ +0.30 +$ +0.37 +$ 0.43 +$ +1.39 +Cumulative +effect of change in +accounting +principle +$ +(0.14) +- +- +- +$ +(0.14) +Diluted +earnings per common and +common +equivalent share +$ +0.15 +$ +0.30 +$ +0.37 +$ +0.43 +$ +1.25 +F-34 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +The following tables +set forth the effect of the restatement (See footnote 22 for discussion of +restatement) on the affected line items within the Company's previously +reported consolidated statements of income for the quarters ended March 31, +2005, June 30, 2005 and September 30, 2005 and for each of the quarters in 2004 +and 2003. +Quarterly +Information +2005 +(Unaudited) +(in thousands) +First Quarter +Second Quarter +Third Quarter +As +As +As +Consolidated +Statements +previously +As +previously +As +previously +As +of Income +Data: +reported +restated +reported +restated +reported +restated +Revenues: +Oil and gas +well drilling operations +$ 32,351 +$ 25,366 +$ 36,057 +$ 28,111 +$ 39,711 +$ 32,267 +Well +operations and pipeline income +$ 2,112 +$ 1,927 +$ 2,244 +$ 2,068 +$ 2,483 +$ 2,291 +Other income +$ 6,214 +$ 6,214 +$ 3,573 +$ 3,493 +$ 209 +$ 209 +Total +revenues +$ 76,863 +$ 69,693 +$ 89,334 +$ 81,131 +$ 85,787 +$ 78,150 +Costs and +expenses: +Cost of oil +and gas well drilling operations +$ 27,629 +$ 20,644 +$ 31,689 +$ 23,743 +$ 36,178 +$ 28,734 +Oil and gas +production +and well +operations costs +$ 4,163 +$ 3,978 +$ 4,738 +$ 4,482 +$ 6,455 +$ 6,263 +Total costs +and expenses +$ 56,168 +$ 48,998 +$ 73,579 +$ 65,376 +$ 63,804 +$ 56,167 +Income from +operations +$ 20,695 +$ 20,695 +$ 15,755 +$ 15,755 +$ 21,983 +$ 21,983 +Quarterly +Information (Unaudited) +(in +thousands) +2004 +First Quarter +Second Quarter +Third Quarter +Fourth Quarter +Consolidated Statements +As +As +As +As +of +Income Data: +previously +As +previously +As +previously +As +previously +As +reported +restated +reported +restated +reported +restated +reported +restated +Revenues: +Oil and +gas well drilling operations +$ 29,499 +$ 22,109 +$ 29,454 +$ 24,066 +$ 30,394 +$ 24,070 +$ 29,864 +$ 23,831 +Well +operations and pipeline income +$ 1,838 +$ 1,707 +$ 1,912 +$ 1,738 +$ 2,074 +$ 1,875 +$ 2,561 +$ 2,357 +Other +income +$ 58 +$ 58 +$ 687 +$ 622 +$ 589 +$ 589 +$ 612 +$ 612 +Total +revenues +$ 69,770 +$ 62,249 +$ 73,217 +$ 67,589 +$ 72,268 +$ 65,745 +$ 78,405 +$ 72,169 +Costs and +expenses: +Costs of +oil and gas well drilling +operations +$ 25,356 +$ 17,966 +$ 24,967 +$ 19,579 +$ 26,005 +$ 19,681 +$ 26,503 +$ 20,470 +Oil and +gas production and well +operations +costs +$ 3,906 +$ 3,776 +$ 4,036 +$ 3,796 +$ 3,952 +$ 3,754 +$ 6,156 +$ 5,952 +Total +costs and expenses +$ 56,690 +$ 49,169 +$ 58,961 +$ 53,333 +$ 57,244 +$ 50,721 +$ 63,528 +$ 57,292 +Income from operations +$ 13,080 +$ 13,080 +$ 14,255 +$ 14,255 +$ 15,024 +$ 15,024 +$ 14,877 +$ 14,877 +F-35 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +Quarterly +Information (Unaudited) +(in +thousands) +2003 +First Quarter +Second Quarter +Third Quarter +Fourth Quarter +Consolidated Statements +As +As +As +As +of Income +Data: +previously +As +previously +As +previously +As +previously +As +reported +restated +reported +restated +reported +restated +reported +restated +Revenues: +Oil and +gas well drilling operations +$ 21,498 +$ 17,147 +$ 11,866 +$ 9,507 +$ 14,080 +$ 11,326 +$ 24,398 +$ 19,530 +Well +operations and pipeline income +$ 1,648 +$ 1,543 +$ 1,769 +$ 1,672 +$ 1,865 +$ 1,747 +$ 2,066 +$ 1,945 +Other +income +$ 385 +$ 327 +$ 285 +$ 285 +$ 488 +$ 488 +$ 2,428 +$ 2,428 +Total +revenues +$ 53,840 +$ 49,326 +$ 41,938 +$ 39,482 +$ 50,108 +$ 47,236 +$ 58,415 +$ 53,426 +Costs and +expenses: +Costs of +oil and gas well +drilling +operations +$ 17,676 +$ 13,325 +$ 10,120 +$ 7,761 +$ 11,956 +$ 9,201 +$ 21,526 +$ 16,659 +Oil and +gas production and well +operations costs +$ 2,857 +$ 2,694 +$ 3,460 +$ 3,363 +$ 3,986 +$ 3,869 +$ 3,446 +$ 3,325 +Total +costs and expenses +$ 45,795 +$ 41,281 +$ 34,805 +$ 32,349 +$ 41,256 +$ 38,384 +$ 45,820 +$ 40,831 +Income +from operations +$ 8,045 +$ 8,045 +$ 7,133 +$ 7,133 +$ 8,852 +$ 8,852 +$ 12,595 +$ 12,595 +(22) Restatement +In this Annual Report on +Form 10-K for the year ended December 31, 2005, the Company is amending and +restating its prior consolidated statements of income for the years ended December 31, 2004 and 2003, and for each of the quarters ended in the years 2004 and +2003. This Annual Report on Form 10-K is also amending and restating our consolidated +statements of income for the quarterly periods ended March 31, 2005, June 30, 2005, and September 30, 2005. +As previously announced in +a Form 8K as filed with the Securities and Exchange Commission on April 3, +2006, the Company identified that corrections were needed to certain revenues +and expenses to properly reflect the elimination of transactions between the +Company and the limited partnerships. The corrections resulted in +elimination of revenues and expenses of equal amounts. The restatement had no +effect on Net Income, Earnings per Share, Cash Flow, Proved Oil and Gas +Reserves, or the Company's financial position. In addition, the Company made +other corrections that in the prior periods were considered immaterial both +individually and in the aggregate. +Effects +of the Restatement +The +restatement also impacted or made changes to the following financial statement +footnotes; Note 17, 19, 20, 21 and added Note 22, Restatement. +F-36 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +The +following tables set forth the effects of the restatement on the affected line +items within the Company's previously reported Consolidated Statements of Income +for the years 2004 and 2003. +For the year +ended December 31, +(in +thousands) +Consolidated +Statements +2004 +2003 +of Income +Data: +As +As +previously +As +previously +As +reported +restated +reported +restated +Revenues: +Oil and gas +well drilling operations +$ 119,211 +$ 94,076 +$ 71,842 +$ 57,510 +Well +operations and pipeline income +$ 8,385 +$ 7,677 +$ 7,348 +$ 6,907 +Other Income +$ 1,946 +$ 1,881 +$ 3,586 +$ 3,529 +Total +revenues +$ 293,660 +$ 267,753 +$204,301 +$189,471 +Costs and +expenses: +Costs of oil +and gas well drilling operations +$ 102,831 +$ 77,696 +$ 61,278 +$ 46,946 +Oil and gas +production +and +well operations costs +$ 18,050 +$ 17,277 +$ 13,749 +$ 13,251 +Total costs +and expenses +$ 236,423 +$ 210,516 +$167,676 +$152,846 +Income from +operations +$ 57,236 +$ 57,236 +$ 36,625 +$ 36,625 +F-37 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES +Years Ended December 31, 2005, 2004 and 2003 +Column +A +Column B +Column C +Column +D +Column E +Additions, +Balance at +Charged to +Balance +Beginning +Costs and +At End +Description +of Period +Expenses +Deductions +of Period +Allowance for doubtful +accounts deducted +from accounts receivable in the +Balance sheet +2005 +$409,000 +$ - +$ +- +$409,000 +2004 +$487,300 +$ - +$ 78,300 (a) +$409,000 +2003 +$524,500 +$ - +$ 37,200 (a) +$487,300 +(a) +Deduction relates to +the write-off of accounts receivable deemed uncollectible. +F-38 \ No newline at end of file diff --git a/raw/filings/0000077877/2005/0000077877-06-000037/filing_metadata.csv b/raw/filings/0000077877/2005/0000077877-06-000037/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..abd26a33825f1a03fa7d7e9edf27f09838820044 --- /dev/null +++ b/raw/filings/0000077877/2005/0000077877-06-000037/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 +0000077877,PDCE,"PDC ENERGY, INC.",10-K,2006-05-31,2005-12-31,2006-05-31T20:29:10.000Z,0000077877-06-000037,pdc10k20053.htm,,2742406,0,0,https://www.sec.gov/Archives/edgar/data/77877/000007787706000037/pdc10k20053.htm,https://www.sec.gov/Archives/edgar/data/77877/000007787706000037/,2005,2005,1 diff --git a/raw/filings/0000077877/2005/0000077877-06-000037/item1.txt b/raw/filings/0000077877/2005/0000077877-06-000037/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..1ee85162597d8e1bba5ead3e2b2134e7e14d0050 --- /dev/null +++ b/raw/filings/0000077877/2005/0000077877-06-000037/item1.txt @@ -0,0 +1,974 @@ +Item 1. Business +Petroleum +Development Corporation is an independent energy company engaged primarily in +the development, production and marketing of natural gas and oil. Since it +began oil and gas operations in 1969, the Company has grown primarily through +drilling and development activities, the acquisition of producing natural gas +and oil wells and the expansion of its natural gas marketing activities. As of December 31, 2005, the Company operates approximately 2,800 wells located in the +Appalachian Basin, Michigan, and the Rocky Mountain Region, with gross proved +reserves of 708 billion cubic feet equivalent of natural gas ("Bcfe", based on +one barrel of oil equals 6 thousand cubic feet equivalent of natural gas +("Mcfe")) of which the Company's share is 275 Bcfe. The Company's share of +production for the fourth quarter of 2005 averaged 38,800 Mcfe per day. +See Glossary of +Terms used in this Form 10-K on Page 61. +Business Segments +The Company's +operations are divided into four segments for management and reporting +purposes. (See Note 20). +Drilling and Development +The Company drills +wells not only for itself, but also for other investor partners. When the +Company drills wells for others it earns profit above the cost of the wells. +The Drilling and Development segment records the payments received from others +as revenue and the related costs as expenses. +Since 1984, the +Company has sponsored limited partnerships formed to engage in drilling +operations. The Company typically purchases a 20% to 30% ownership working interest +in these drilling limited partnerships. In 2005, the Company, through two public +and one private drilling partnership, raised $116 million making it one of the +largest sponsors of public oil and gas partnership programs in the United State s as it has been for the last several years. With the partnerships as a +drilling partner, the Company has been able to expand its drilling +opportunities, reduce its drilling risk through greater diversification, and to +share the costs of the infrastructure necessary to support such activities. +2 +Natural Gas Marketing +The Company's +wholly-owned subsidiary, Riley Natural Gas (RNG), purchases, aggregates and +resells natural gas developed by the Company and other producers. This allows +the Company to diversify its operations beyond natural gas drilling and +production. RNG has established relationships with many of the natural gas +producers in the Appalachian Basin and has significant expertise in the natural +gas end‑user market. In addition, RNG has extensive experience in the use +of economic hedging and derivative strategies, which the Company utilizes to +help manage the financial impact on the Company and its Partnerships of changes +in the price of natural gas and oil. RNG also manages the marketing of oil and +gas for the Company's wells outside the Appalachian Basin, but does not market +gas or oil for non-affiliated producers in those areas. +Oil and Gas Sales +Revenue from the +sale of oil and natural gas from the Company's interest in oil and gas wells is +reported in this segment. The Company has interests in approximately 2,800 wells +ranging from a few percent to 100 percent. During 2005 approximately 12% of the +Company's production was generated by Appalachian Basin wells, 12% by Michigan Basin wells and 76% by Rocky Mountain wells. As of the end of 2005, the Company's +total proved reserves were located as follows: Appalachian Basin 14%, Michigan 9% and Rocky Mountain Region 77%. The majority of the Company's undeveloped +reserves are in the Rocky Mountain Region and the planned drilling for 2006 +will be focused in that area. +Well Operations +The Company operates +almost all of the approximately 2,800 wells in which it owns an interest. When +it owns less than 100 percent of the working interest in a well, it charges the +other owners a competitive operating fee for operating the well. These +revenues and the associated costs are reflected in the Well Operations segment. +Areas of Operations +The Company's +operations are divided into three regions, the Appalachian Basin, Michigan, and +the Rocky Mountain Region. The Company has conducted operations in the Appalachian +Basin since its inception in 1969, in Michigan since 1997, and in the Rocky +Mountain Region since 1999. The Company includes its North Dakota operations in +the Rocky Mountain Region. +In all three regions +the Company has historically targeted shallow (less than 10,000 feet), +developmental natural gas reserves for development. In some areas of the Rocky +Mountain Region, Michigan and the Appalachian Basin the wells also produce oil +in conjunction with natural gas. Recently the Company has begun to drill to +progressively deeper targets in the Rocky Mountain Region. In particular it +has drilled several wells with depths of more than 12,000 feet and horizontal +wells with a total drilled footage approaching 20,000 feet. The Company's +management believes these deeper and horizontal wells offer the possibility of +significantly greater reserves and production than shallow wells, although they +are also more expensive to drill. In addition the probability of encountering +problems when drilling a deep or horizontal well is generally greater than when +drilling a shallow well. With increasing costs for and declining availability +of proved developed drilling locations, the Company's management believes the +additional risk associated with exploratory drilling is justified by the +potential to generate additional proved locations at a significantly lower cost +than would be required to purchase proved undeveloped locations. +Business Strategy +The Company's +primary objective is to increase shareholder value by expanding its oil and +natural gas reserves, production and revenues through a strategy that includes +the following key elements: +Drill and Develop +Drilling new wells, +particularly shallow, developmental natural gas wells, has been the mainstay of +the Company's drilling program for a number of years. The Company drilled 242 +wells in 2005, compared to 158 wells in 2004. In addition the Company seeks to +maximize the value of its existing wells through a program of well +recompletions and drilling in areas where attractive opportunities exist. The Company's +management believes that it will be able to drill a substantial number of new +wells on its current undeveloped leased properties. As of December 31, 2005, the Company had leases or other development rights to +3,000 undeveloped acres in the Michigan Basin, 10,000 undeveloped acres in the +northern Appalachian Basin and 245,250 undeveloped acres in the Rocky Mountain +Region. The Company also has about 67 +Wattenberg Field wells (Colorado) that it plans to recomplete in 2006, including +43 of the new wells it has drilled since 1999 in the field. +3 +To support future +development activities the Company has conducted exploratory drilling in the +past and has continuing exploratory drilling plans in 2006. The goal of the +exploration program is to develop several significant new areas for the Company +to include in its future development drilling programs. +Acquire +The Company's +acquisition efforts are focused on producing properties that fit well within +existing operations or in areas where the Company is establishing new +operations. Preferred properties have most of their value in producing wells, +behind pipe reserves or high quality proved undeveloped locations. +Acquisitions have historically offered economies in management and +administration, and the Company's management believes that it can acquire and +manage more producing wells without incurring substantial increases in its +administrative costs. +Diversify and Focus +With operations in +the Rocky Mountains, Michigan and the Appalachian Basin, the Company has proven +its ability to grow through operations in geographically diverse areas. While +these areas provide geographic diversification, within each area the Company +has concentrated positions that lend themselves to effective development and +operation. The Company plans to conduct the majority of its drilling +activities in the Rocky Mountain Region during 2006, but will continue to seek +additional opportunities for expansion in areas where the Company's experience +and expertise can be applied successfully. +Manage Risk +The Company seeks +opportunities to reduce the risks inherent in the oil and gas industry in a +variety of ways. For a number of years an integral part of the Company's +strategy has been to concentrate on development drilling and geographical +diversification to reduce risk levels associated with natural gas and oil drilling, +production and markets. Development drilling is less risky than exploratory +drilling and is likely to generate cash returns more quickly. Development +drilling will remain the foundation of our drilling activities in 2006. However +the Company's management believes the increasing cost of high quality +development locations has made exploratory drilling more attractive. +Exploratory wells have the potential of identifying new development +opportunities at a significantly lower cost than the current cost of proven +locations. While successful exploratory efforts could add to the Company's +future drilling opportunities at favorable costs, under the successful efforts +method of accounting, exploratory dry holes are expensed at the time it is +recognized that they are unproductive. This could result in greater short term +expenses and a reduction in the near-term profitability of the Company. +To help offset the +relatively high business risk inherent in the oil and gas industry the Company +maintains a conservative financial structure. The Company's management +believes that successful natural gas marketing is essential to profitable +operations in a deregulated gas market. To further this goal, the Company +utilizes its marketing subsidiary, Riley Natural Gas (RNG), to manage the +marketing of the Company's oil and natural gas and its commodity derivatives. This +allows the Company to maintain better control over third party risk in sales +and derivative activities. The Company uses natural gas and oil derivatives to reduce +the effects of volatility of energy prices. +Available Information Posted on the Company's Website +The Company's +Internet address is www.petd.com. Electronic copies of the Company's annual report +on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, +and amendments to those reports are available free of charge by visiting the +"Financial Information" section of www.petd.com. These reports are posted as soon as reasonably +practicable after they are electronically filed with the Securities and +Exchange Commission. Additionally, information including the Company's press +releases, current drilling program sales, Bylaws, Committee Charters, Code of +Business Conduct and Ethics, Shareholder Communication Policy, Board Nomination +Procedures and the Whistleblower and Qualified Legal Compliance Committee +Hotline is also available at the site. +Industry Overview +Natural gas is the +second largest energy source in the United States, after liquid petroleum. The +estimated 21.9 Tcf of natural gas consumed in 2005 represented approximately +23% of the total energy used in the United States. Natural gas is consumed in +the United States as follows: 35% by industrial end-users as feedstock for +products such as plastic and fertilizer or as the energy source for producing +products such as glass; 22% and 14% by residential and commercial end-users, +respectively, for uses including heating, cooling and cooking; and 26% by +utilities for the generation of electricity; and 3% for other users. (Source U.S. Energy Information Administration) +4 +The Company's +management believes that the market for natural gas will continue to grow in +the future. Natural gas is the cleanest and most environmentally safe of the +fossil fuels. Relative to other energy sources, natural gas usage and losses +during transportation from source to destination are slight, averaging only +about 3% of the natural gas energy. The delivery of natural gas is among the +safest means of distributing energy to customers, as the natural gas +transmission system is fixed and is located underground. +The deregulation of +the natural gas industry and a favorable regulatory environment have resulted +in end-users' ability to purchase natural gas on a competitive basis from a +greater variety of sources. Increasing international demand for petroleum +combined with supply constraints drove oil prices to record high levels in 2005. +Continuing increases in world energy demand appear likely in 2006 and beyond. +This makes natural gas more competitive in domestic markets as a replacement +for oil and increases the value of domestic oil and natural gas reserves. +The Company's +management believes that the foregoing factors, together with the increased +availability of natural gas as a form of energy for residential, commercial and +industrial uses, should increase the demand for natural gas as well as create +new markets for natural gas even at prices that are high by historical +standards. +Because local +supplies of natural gas are inadequate to meet demand in sections of the +country, areas including the West Coast and the Northeast import natural gas +from producing areas via interstate natural gas pipelines. The cost of +transporting natural gas from the major producing areas to markets creates a +price advantage for production located closer to the consuming regions. Natural +gas producers in the Appalachian Basin and Michigan benefit from proximity to +the northeastern United States. +In contrast, much of +the production in the Rocky Mountains is transported significant distances to +end user markets. As a result the price received for gas in the Rocky Mountains is generally less than the price received in areas closer to the primary +consuming areas. The Rocky Mountain Region is believed to hold substantial undeveloped +natural gas resources. Recent and planned additions to pipeline capacity in +the region have made the area more attractive for development. Although gas +from the region will generally sell for less than gas in the Appalachian and +Michigan Basins, development costs may be less. +Operations +Exploration and Development Activities +The Company's +development activities focus on the identification and drilling of new +productive wells, the acquisition of existing producing wells from other +producers, and maximizing the value of the Company's current properties through +infill drilling, recompletions, and other production enhancements. +Prospect Generation +The Company's staff +of professional geologists is responsible for identifying areas with potential +for economic production of natural gas and oil. These geologists have decades +of cumulative experience evaluating prospects and drilling natural gas and oil +wells. They utilize results from logs, seismic data and other tools to evaluate +existing wells and to predict the location of economically attractive new gas +reserves. To further this process, the Company has collected and continues to +collect logs, core data, production information and other raw data available +from state and private agencies, other companies and individuals actively +drilling in the regions being evaluated. From this information the geologists +develop models of the subsurface structures and formations that are used to +predict areas with prospects for economic development. +On the basis of +these models, the geologists instruct the Company's land department to obtain +available natural gas and oil leaseholds, farmouts and other development rights +in these prospective areas. These rights are then obtained, if possible, by the +Company's land department or contract landmen under the direction of the +Company's land manager. In most cases, the Company pays a lease bonus and +annual rental payments, converting, upon initiation of production, to a royalty +on gross production revenue in return for obtaining the leases. In addition +overriding royalty payments may be made to third parties in conjunction with +the acquisition of drilling rights initially leased by others. As of December 31, 2005, the Company had leasehold rights to approximately 258,000 acres +available for development. See "Properties--Oil and Natural Gas +Leases." +5 +Drilling Activities +When prospects have +been identified and leased, the Company develops these properties by drilling +wells. In 2005, the Company drilled a total of 234 development wells of which +232 were successfully completed as producing wells. Typically, the Company will +act as driller‑operator for these prospects, frequently selling interests +in the wells to partnerships, primarily Company‑sponsored partnerships, +and other entities that are interested in exploration or development of the +prospects. The Company retains a working interest in each well it drills. +The Company also +drilled 8 exploratory wells in 2005 and plans additional exploratory wells in +2006. Currently the Company plans to retain most if not all of the working +interest in the exploratory wells, since the Company partnerships focus on +developmental activities and are allowed only limited participation in +exploratory drilling. Five of the exploratory wells drilled in 2005 were dry. +The associated costs of these dry holes were $11,115,100 and these costs were +expensed in 2005. See "Financing of Company Drilling and Development Activities" +And "Drilling and Development Activities Conducted for Company Sponsored +Partnerships." +Much of the work +associated with drilling, completing and connecting wells, including drilling, +fracturing, logging and pipeline construction is performed under the Company's +direction by subcontractors specializing in those operations, as is common in +the industry. When judged advantageous, material and services used by the +Company in the development process are acquired through competitive bidding by +approved vendors. The Company also directly negotiates rates and costs for +services and supplies when conditions indicate that such an approach is +warranted. Because the prices paid to the Company by its drilling partnerships +for the Company's services are frequently fixed before the wells are drilled or +are determined based primarily on the well depth, the Company is subject to the +risk that prices of goods or services used in the development process could +increase, rendering its contracts with its investor partners less profitable or +unprofitable. In addition, problems encountered in the process can +substantially increase development costs, sometimes without recourse for the +Company to recover its costs from its partners. To minimize these risks, the +Company seeks to fix its development costs in advance of drilling when +possible. +Drilling Activity +The following tables +summarize the Company's development and exploratory drilling activity for the +last five years. There is no correlation between the number of productive wells +completed during any period and the aggregate reserves attributable to those +wells. +Development Wells Drilled +Total +Productive +Dry +Drilled +Net +Drilled +Net +Drilled +Net +2001 +141 +40.00 +135 +37.94 +6 +2.06 +2002 +70 +13.71 +70 +13.71 +- +- +2003 +110 +28.51 +110 +28.51 +- +- +2004 +157 +43.00 +153 +42.40 +4 +0.60 +2005 +234 +103.40 +232 +102.00 +2 +1.40 +Total +712 +228.62 +700 +224.56 +12 +4.06 +Exploratory Wells Drilled +Total +Productive +Dry +Drilled +Net +Drilled +Net +Drilled +Net +2001 +- +- +- +- +- +- +2002 +- +- +- +- +- +- +2003 +1 +1.00 +- +- +1 +1 +2004 +1 +1.00 +- +- +1 +1 +2005 +8 +7.30 +3 +2.30 +5 +5.00 +Total +10 +9.30 +3 +2.30 +7 +7.00 +6 +Financing of Company Drilling and Development Activities +The Company conducts +development drilling activities for its own account and acts as operator for +other investors. When conducting activities for its own account the Company +uses cash flow from operations and capital provided from its long term credit +facility to fund its share of operations. The Company currently has activated +$80 million of a $200 million credit facility with J.P. Morgan Chase Bank, NA +and BNP Paribas (collectively "the Banks"), however the Banks have determined +that the Company's current oil and gas reserves would support up to $125 +million of borrowing if the need arose. As of the end of 2005 the Company had $24 +million outstanding under the facility. +Drilling and Development Activities Conducted for Company +Sponsored Partnerships +In addition to wells +and interests in wells that it drills for itself, the Company also acts as +operator for other oil and gas investors. Historically these other investors +have included individuals, corporations, partnerships formed by non-affiliated +parties and other investors. Currently the Company's drilling partners consist +primarily of public and private partnerships sponsored by the Company. The +Company makes a cash investment to purchase an interest in the drilling and +development activities of each partnership. +In 1984, the Company +began sponsoring private drilling limited partnerships, and, in 1989, the +Company began to offer partnership interests in public drilling programs +registered with the SEC. The Company's public and private partnerships had $116 +million in subscriptions in 2005, $100 million in subscriptions in 2004, and $78.3 +million in subscriptions in 2003. The Company invests, as its equity +contribution to each drilling partnership, an additional sum approximating 22% to +32% of the aggregate subscriptions received for that particular drilling +partnership and receives a 20% to 30% working interest in each partnership, +respectively. As a result, the Company is subject to substantial cash +commitments at the closing of each drilling partnership. During 2005 this contribution +amounted to $29.0 million. The funds received from these programs are +restricted for future drilling operations. While funds were received by the Company +pursuant to drilling contracts in the years indicated, the Company recognizes +revenues from drilling operations on the percentage of completion method as the +wells are drilled, rather than when funds are received. Substantially all of +the Company's drilling and development funds are now received from partnerships +in which the Company serves as managing general partner. However, because wells +produce for a number of years, the Company continues to serve as operator for a +number of unaffiliated parties. +The process begins +when the Company enters into a development agreement with an investor partner, +pursuant to which the Company agrees to sell some or all of its rights in the +property to be drilled to the partnership or other entity. The partnership or +other entity thereby becomes owner of a working interest in the property. +The Company's drilling +contracts with its investor partners have historically taken many different +forms. Starting in 2006 the drilling agreements can be classified as a +"cost plus" rate, whereby the Company receives a percentage profit in +addition to the actual well costs. In the past the drilling contracts could be +classified as on a "footage-based" rate, whereby the Company received +drilling and completion payments based on the depth of the well. Oil and gas leases +are sold to the partnership at the Company's cost. The Company may also +purchase an additional working interest in the partnership properties. In its +financial reporting the Company reports only its share of reserves, production, +oil and gas sales and costs associated with wells in which other investors +participate. The level of the Company's drilling and development activity +is dependent upon the amount of subscriptions in its public drilling +partnerships and investments from other partnerships or other joint venture +partners. Accepting investments from third party investors and Company +sponsored partnerships enables the Company to diversify its holdings, thereby +reducing the risk of the Company's investments. Additionally, the Company +benefits through such arrangements by its receipt of fees for its management +services and/or through an increased share in the revenues produced by the +developed properties. The Company's management believes that investments in +drilling activities, whether through Company‑sponsored partnerships or +other sources, are influenced in part by the favorable treatment that such +investments enjoy under the federal income tax laws. No assurance can be given +that the Company will continue to have access to funds generated through these +financing vehicles or that the favorable tax treatment will continue. +Purchases of Producing Properties +In addition to +drilling new wells, the Company continues to pursue opportunities to purchase +existing wells from other producers as well as greater ownership interests in +the wells it operates. Generally, outside interests purchased include a +majority interest in the wells and the right to operate the wells. Although the +Company made several offers to purchase properties during 2005, other potential +purchasers outbid the Company; therefore none of its offers were successful. +The Company purchased +a number of small interests in its partnerships from investor partners wishing +to sell their interests in 2005, 2004 and 2003. +7 +Production +The following table +shows the Company's net production in thousands of barrels (MBbl) of crude oil +and in million cubic feet (Mmcf) of natural gas and the costs and weighted +average selling prices of oil in barrels (Bbl) and gas in thousands of cubic +feet (Mcf). +Year Ended December 31, +2005 +2004 +2003 +2002 +2001 +Production(1): +Oil(MBbl) +439 +381 +289 +227 +195 +Natural +Gas (Mmcf) +11,031 +10,372 +8,712 +6,462 +6,085 +Equivalent +Mmcf(2) +13,665 +12,659 +10,449 +7,824 +7,255 +Average sales price: +Oil +(per Bbl)(3) +$50.56 +$38.00 +$29.43 +$24.41 +$22.53 +Natural +gas (per Mcf)(3) +$7.29 +$5.30 +$4.58 +$2.65 +$4.08 +Average +production cost (lifting cost) +Per +equivalent Mcf(4) (restated) +$1.19 +$1.12 +$0.93 +$0.76 +$0.79 +(1) Production +as shown in the table is net to the Company and is determined by multiplying +the gross production volume of properties in which the Company has an interest +by the percentage of the leasehold or other property interest owned by the +Company. +(2) A +ratio of energy content of natural gas and oil (six Mcf of natural gas equals +one barrel of oil) was used to obtain a conversion factor to convert oil +production into equivalent Mcf of natural gas. +(3) The +Company utilizes commodity based economic derivative instruments to hedge and manage +a portion of its exposure to price volatility of its natural gas and oil sales. +The above table does not include the results of derivative transactions. +(4) Production +costs represent oil and gas operating expenses which include severance and ad +valorem taxes as reflected in the financial statements of the Company. See Oil +and Gas Production and Well Operations Costs in Management's Discussion and +Analysis. +Natural Gas Sales +Natural gas produced +by the Company's well interests is generally sold under monthly contracts. +Virtually all of the Company's contract pricing provisions are tied to a market +index, with certain adjustments based on, among other factors, whether a well +delivers to a gathering or transmission line, quality of natural gas and +prevailing supply and demand conditions, so that the price of the natural gas +fluctuates to remain competitive with other available natural gas supplies. As +a result, the Company's revenues from the sale of natural gas will suffer if +market prices decline and benefit if they increase. The Company's management +believes that the pricing provisions of its natural gas contracts are customary +in the industry. +The Company sells +its natural gas to industrial end-users, utilities, other gas marketers, and +other wholesale gas purchasers. Three customers accounted for 15.2%, 12.9% and +10.6% respectively of the Company's revenues from oil and gas sales (9.9%, 8.4% +and 6.9% of total revenues) in 2005. Two customers accounted for 14.1% and +11.3% respectively of the Company's revenues from oil and gas sales (8.6% and +7.0% of total revenues) in 2004. Three customers accounted for 16.4%, 17.2% and +14.2%, respectively of the Company's revenues from oil and gas sales (10.5%, 11.1% +and 9.1% of total revenues) in 2003. No other single purchaser of the Company's +natural gas accounted for 10% or more of the Company's total revenues during +2005, 2004, and 2003. +At December 31, 2005, natural gas produced by the Company sold at prices per Mcf ranging from +$2.52 to $13.31, depending upon well location, the date of the sales contract +and other factors. The weighted net average price of natural gas sold by the +Company during 2005 was $7.29 per Mcf. +In general, the +Company, together with its marketing subsidiary, RNG, has been and expects to +continue to be able to produce and sell natural gas from its wells without +significant curtailment by providing natural gas to purchasers at competitive +prices. Open access transportation through the country's interstate pipeline +system makes a broad range of markets accessible to the Company. Whenever +feasible the Company obtains access to multiple pipelines and markets from each +of its gathering systems seeking the best available market for its natural gas +at any point in time. +8 +Oil Sales +Some of the +Company's wells in the Appalachian Basin, Michigan, most of the Company's wells +in Wattenberg field in Colorado, and the Company's North Dakota wells produce +oil in addition to natural gas. At the end of 2005 oil was about 10% of the +Company's total equivalent reserves. +The Company is +currently able to sell all the oil that it can produce under existing sales +contracts with petroleum refiners and marketers. The Company does not refine +any of its oil production. The Company's crude oil production is sold to +purchasers at or near the Company's wells under short-term purchase contracts. One +purchaser accounted for 10.5%, 7.8% and 10.9% of the Company's revenues from +oil and gas sales (6.9%, 4.8% and 7.0% of total revenues) in 2005, 2004, and +2003. At December 31, 2005, oil produced by the Company sold at prices ranging +from $54.40 to $57.37 per barrel, depending upon +the location and quality of oil. In 2005, the weighted net average price per +barrel of oil sold by the Company was $50.56. +Oil production is +subject to many of the same operating hazards and environmental concerns as +natural gas production, but is also subject to the risk of oil spills. Federal +regulations require certain owners or operators of facilities that store or +otherwise handle oil, such as the Company, to procure and implement Spill Prevention, +Control and Counter-measures ("SPCC") plans relating to the possible discharge +of oil into surface waters. The Oil Pollution Act of 1990 ("OPA") +subjects owners of facilities to strict joint and several liability for all +containment and cleanup costs and certain other damages arising from oil +spills. Noncompliance with OPA may result in varying civil and criminal +penalties and liabilities. Operations of the Company are also subject to the +Federal Clean Water Act and analogous state laws relating to the control of +water pollution, which laws provide varying civil and criminal penalties and +liabilities for release of petroleum or its derivatives into surface waters or +into the ground. +Natural Gas Marketing +The Company's +natural gas marketing activities involve the purchase of natural gas from other +producers and the sale of that natural gas along with natural gas produced by +the Company. The Company's management believes that in a deregulated market, +successful natural gas marketing is an essential component of profitable +operations. A variety of factors affect the market for natural gas, including +the availability of other domestic production, natural gas imports, the +availability and price of alternative fuels, the proximity and capacity of +natural gas pipelines, general fluctuations in the supply and demand for +natural gas and the effects of state and federal regulations on natural gas production +and sales. The natural gas industry also competes with other industries in +supplying the energy and fuel requirements of industrial, commercial and +individual customers. +RNG, a wholly owned +subsidiary, is a natural gas marketing company that specializes in the +purchase, aggregation and sale of natural gas production in the Company's +operating areas. RNG markets natural gas produced by the Company and also +purchases natural gas from other producers and resells to utilities, end users +or other marketers. The employees of RNG have extensive knowledge of natural +gas markets in the Company's areas of operations. Such knowledge assists the +Company in maximizing its prices as it markets natural gas from +Company-operated wells. The gas is marketed to natural gas utilities, pipelines +and industrial and commercial customers, either directly through the Company's +gathering system, or utilizing transportation services provided by regulated +interstate pipeline companies. +Derivative Activities +The Company utilizes +commodity based economic derivative instruments to manage a portion of the +exposure to price volatility stemming from its oil and natural gas sales and +marketing activities. These instruments consist of NYMEX-traded natural gas +futures and option contracts for Appalachian, Michigan and eastern Colorado production, and CIG (Colorado Interstate Gas Index)-based contracts for other Colorado production and NYMEX traded oil futures and option contracts for Colorado oil +production. The Company may utilize derivatives based on other indices or +markets where appropriate. The contracts economically hedge committed and +anticipated natural gas purchases and sales and anticipated oil sales, +generally forecasted to occur within the next two to three year period. Company +policy prohibits the use of natural gas or oil futures or options for +speculative purposes and permits utilization of derivatives only if there is an +underlying physical position. +9 +The Company through +RNG has extensive experience with the use of cash-settled derivatives to reduce +the risk and impact of natural gas price changes. These financial derivatives are +used by RNG to coordinate fixed and variable priced purchases and sales, and by +the Company to "lock in" fixed prices from time to time for the +Company's share of production, and to establish "floors" and +"ceilings" or "collars" on the possible range of the prices +realized for the sale of natural gas and oil. RNG also enters into fixed-price +purchases and sales contracts with counterparties. These fixed physical +contracts meet the FAS 133 definition of a derivative. Both types of +derivatives (i.e., the physical deals and the cash settled contracts) are +carried on the balance sheet at fair value with changes in fair values recognized +currently in the income statement. While derivatives can help provide price +protection if spot prices drop, derivatives can also limit upside potential. +For natural gas +sales not subject to fixed price contracts, the Company is subject to price +fluctuations for natural gas sold in the spot market and under market index +contracts. The Company continues to evaluate the potential for reducing these +risks by entering into derivative transactions. In addition, the Company may +also close out any portion of derivatives that may exist from time to time +which may result in a realized gain or loss on that derivative transaction. The +Company economically manages the price risk on only a portion of its +anticipated production, so some of the production is subject to the full +fluctuation of market pricing. +Well Operations +The +Company currently operates approximately 1,365 wells in the Appalachian Basin, 205 +wells in the Michigan Basin and 1,077 wells in the Rocky Mountain Region. The +Company's ownership interest in these wells ranges from less than 1% to 100%, +and, on average, the Company has an approximate 50.35% ownership interest in +the wells it operates. The Company has an interest in approximately 143 +non-operated wells in the Rocky Mountain Region. +The Company is paid +a monthly operating fee for each well it operates for outside owners including +the limited partnerships sponsored by the Company. The fee is competitive with +rates charged by other operators in the area. The fee covers monthly operating +and accounting costs, insurance and other recurring costs. The Company may also +receive additional compensation for special non-recurring activities, such as +reworks and recompletions. +Transportation +Natural gas wells +are connected by pipelines to natural gas markets. Over the years, the Company +has developed gathering systems in some of its areas of operations. The Company +also continues to construct new trunk lines as necessary to provide for the +marketing of natural gas being developed from new areas and to enhance or +maintain its existing systems. +The Company is paid +a transportation fee for natural gas that is moved by other shippers through +these pipeline systems. In many cases the Company has been able to receive +higher natural gas prices as a result of its ability to move natural gas to +more attractive markets through this pipeline system, to the benefit of both +the Company and its investor partners. +Governmental Regulation +The Company's +business and the natural gas industry in general are heavily regulated. The +availability of a ready market for natural gas production depends on several +factors beyond the Company's control. These factors include regulation of +natural gas production, federal and state regulations governing environmental +quality and pollution control, the amount of natural gas available for sale, +the availability of adequate pipeline and other transportation and processing +facilities and the marketing of competitive fuels. State and federal +regulations generally are intended to protect consumers from unfair treatment, +control and reduce the risk to the public and workers from the drilling, +completion, production and transportation of oil and natural gas, prevent waste +of natural gas, protect rights to produce natural gas between owners in a common +reservoir and control contamination of the environment. Pipelines are subject +to the jurisdiction of various federal, state and local agencies. In the +western part of the United States the federal and state governments own a large +percentage of the land and the rights to develop oil and natural gas. Recently +the Company has increased its positions in these types of leases. Generally government +leases are subject to additional regulations and controls not commonly seen on +private leases. The Company takes the steps necessary to comply with applicable +regulations both on its own behalf and as part of the services it provides to +its investor partnerships. The Company's management believes that it is in +compliance with such statutes, rules, regulations and governmental orders, +although there can be no assurance that this is or will remain the case. The +following discussion of the regulation of the United States natural gas +industry is not intended to constitute a complete discussion of the various +statutes, rules, regulations and environmental orders to which the Company's +operations may be subject. +10 +Regulation of Oil and Natural Gas Exploration and +Production +The Company's oil +and natural gas operations are subject to various types of regulation at the +federal, state and local levels. Prior to commencing drilling activities for a +well, the Company must procure permits and/or approvals for the various stages +of the drilling process from the applicable state and local agencies in the state +in which the area to be drilled is located. Such permits and approvals include +those for the drilling of wells, and such regulation includes maintaining +bonding requirements in order to drill or operate wells and regulating the +location of wells, the method of drilling and casing wells, the surface use and +restoration of properties on which wells are drilled, the plugging and +abandoning of wells and the disposal of fluids used in connection with +operations. The Company's operations are also subject to various conservation +laws and regulations. These include the regulation of the size of drilling and +spacing units or proration units and the density of wells which may be drilled +and the unitization or pooling of properties. In this regard, some states allow +the forced pooling or integration of tracts to facilitate exploration while +other states rely primarily or exclusively on voluntary pooling of lands and +leases. In areas where pooling is voluntary, it may be more difficult to form +units, and therefore, more difficult to develop a project if the operator owns +less than 100% of the leasehold. In addition, state conservation laws may +establish maximum rates of production from oil and natural gas wells, generally +prohibiting the venting or flaring of natural gas and imposing certain +requirements regarding the ratability of production. Where wells are to be +drilled on state or federal leases, additional regulations and conditions may +apply. The effect of these regulations may limit the amount of oil and natural +gas the Company can produce from its wells and may limit the number of wells or +the locations at which the Company can drill. The regulatory burden on the oil +and natural gas industry increases the Company's costs of doing business and, +consequently, affects its profitability. Inasmuch as such laws and regulations +are frequently expanded, amended and reinterpreted, the Company is unable to +predict the future cost or impact of complying with such regulations. +Regulation of Sales and Transportation of Natural Gas +Historically, the +transportation and sale for resale of natural gas in interstate commerce were +regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act +of 1978 (the "NGPA") and the regulations promulgated thereunder by +the Federal Energy Regulatory Commission (FERC). Maximum selling prices of +certain categories of natural gas sold in "first sales," whether sold +in interstate or intrastate commerce, were regulated pursuant to the NGPA. The +Natural Gas Wellhead Decontrol Act (the "Decontrol Act") removed, as +of January 1, 1993, all remaining federal price controls from natural gas sold +in "first sales" on or after that date. FERC's jurisdiction over +natural gas transportation was unaffected by the Decontrol Act. While sales by +producers of natural gas and all sales of crude oil, condensate and natural gas +liquids can currently be made at market prices, Congress could reenact price +controls in the future. +The Company's sales +of natural gas are affected by the availability, terms and cost of +transportation. The price and terms for access to pipeline transportation are +subject to extensive regulation. In the past, FERC has undertaken various +initiatives to increase competition within the natural gas industry. As a +result of initiatives like FERC Order No. 636, issued in April 1992, the +interstate natural gas transportation and marketing system was substantially +restructured to remove various barriers and practices that historically limited +non‑pipeline natural gas sellers, including producers, from effectively +competing with interstate pipelines for sales to local distribution companies +and large industrial and commercial customers. The most significant provisions +of Order No. 636 require that interstate pipelines provide transportation +separate or "unbundled" from their sales service, and require that +pipelines provide firm and interruptible transportation service on an open +access basis that is equal for all natural gas suppliers. In many instances, +the result of Order No. 636 and related initiatives has been to substantially +reduce or eliminate the interstate pipelines' traditional role as wholesalers +of natural gas in favor of providing only storage and transportation services. +Another effect of regulatory restructuring is the greater transportation access +available on interstate pipelines. In some cases, producers and marketers have +benefited from this availability. However, competition among suppliers has +greatly increased and traditional long‑term producer-pipeline contracts +are rare. Furthermore, gathering facilities of interstate pipelines are no +longer regulated by FERC, thus allowing gatherers to charge higher gathering +rates. +Additional proposals +and proceedings that might affect the natural gas industry occur frequently in +the Congress, FERC, state commissions, state legislatures, 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 FERC and Congress will continue. The Company cannot determine to +what extent future operations and earnings of the Company will be affected by +new legislation, new regulations, or changes in existing regulation, at +federal, state or local levels. +Environmental Regulations +The Company's +operations are subject to numerous laws and regulations governing the discharge +of materials into the environment or otherwise relating to environmental +protection. Public interest in the protection of the environment has increased +dramatically in recent years. The trend of more expansive and stricter +environmental legislation and regulations could continue. To the extent laws +are enacted or other governmental action is taken that restricts drilling or +imposes environmental protection requirements that result in increased costs +and reduced access to the natural gas industry in general, the business and +prospects of the Company could be adversely affected. +11 +The Company +generates wastes that may be subject to the Federal Resource Conservation and +Recovery Act ("RCRA") and comparable state statutes. The U.S. +Environmental Protection Agency ("EPA") and various state agencies +have limited the approved methods of disposal for certain hazardous and nonhazardous +wastes. Furthermore, certain wastes generated by the Company's operations that +are currently exempt from treatment as "hazardous wastes" may in the +future be designated as "hazardous wastes," and therefore be subject +to more rigorous and costly operating and disposal requirements. +The Company +currently owns or leases numerous properties that for many years have been used +for the exploration and production of oil and natural gas. Although the Company's +management believes that it has utilized good operating and waste disposal +practices, prior owners and operators of these properties may not have utilized +similar practices, and hydrocarbons or other wastes may have been disposed of +or released on or under the properties owned or leased by the Company or on or +under locations where such wastes have been taken for disposal. These +properties and the wastes disposed thereon may be subject to the Comprehensive +Environmental Response, Compensation and Liability Act ("CERCLA"), +RCRA and analogous state laws as well as state laws governing the management of +oil and natural gas wastes. Under such laws, the Company 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) or to perform remedial plugging operations to +prevent future contamination. +CERCLA and similar +state laws impose liability, without regard to fault or the legality of the +original conduct, on certain classes of persons that are considered to have +contributed to the release of a "hazardous substance" into the +environment. These persons include the owner or operator of the disposal site +or sites where the release occurred and companies that disposed of or arranged +for the disposal of the hazardous substances found at the site. Persons who are +or were responsible for release of 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, and 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. +The Company's +operations may be subject to the Clean Air Act ("CAA") and comparable +state and local requirements. Amendments to the CAA were adopted in 1990 and +contain provisions that may result in the gradual imposition of certain pollution +control requirements with respect to air emissions from the operations of the +Company. The EPA and states have been developing regulations to implement these +requirements. The Company may be required to incur certain capital expenditures +in the next several years for air pollution control equipment in connection +with maintaining or obtaining operating permits and approvals addressing other +air emission-related issues. +The Company's +expenses relating to preserving the environment during 2005 were not significant +in relation to operating costs and the Company expects no material change in +2006. Environmental regulations have had no materially adverse effect on the +Company's operations to date, but no assurance can be given that environmental +regulations will not, in the future, result in a curtailment of production or +otherwise have a materially adverse effect on the Company's business, financial +condition or results of operations. +Operating Hazards and Insurance +The Company's +exploration and production operations include a variety of operating risks, +including the risk of fire, explosions, blowouts, cratering, pipe failure, +casing collapse, abnormally pressured formations, and environmental hazards +such as gas leaks, ruptures and discharges of toxic gas, the occurrence of any +of which could result in substantial losses to the Company due to injury and +loss of life, severe damage to and destruction of property, natural resources +and equipment, pollution and other environmental damage, clean‑up +responsibilities, regulatory investigation and penalties and suspension of +operations. The Company's pipeline, gathering and distribution operations are +subject to the many hazards inherent in the natural gas industry. These +hazards include damage to wells, pipelines and other related equipment, and +surrounding properties caused by hurricanes, floods, fires and other acts of +God, inadvertent damage from construction equipment, leakage of natural gas and +other hydrocarbons, fires and explosions and other hazards that could also +result in personal injury and loss of life, pollution and suspension of +operations. +Any significant +problems related to its facilities could adversely affect the Company's ability +to conduct its operations. In accordance with customary industry practice, the +Company maintains insurance against some, but not all, potential risks; +however, there can be no assurance that such insurance will be adequate to +cover any losses or exposure for liability. The occurrence of a significant +event not fully insured against could materially adversely affect the Company's +operations and financial condition. The Company cannot predict whether +insurance will continue to be available at premium levels that justify its +purchase or whether insurance will be available at all. +12 +Competition +The Company's management believes that its exploration, +drilling and production capabilities and the experience of its management and +professional staff generally enable it to compete effectively. The Company +encounters competition from numerous other oil and natural gas companies, +drilling and income programs and partnerships in all areas of its operations, +including drilling and marketing oil and natural gas and obtaining desirable oil +and natural gas leases. Many of these competitors possess larger staffs and +greater financial resources than the Company, which may enable them to identify +and acquire desirable producing properties and drilling prospects more +economically. The Company's ability to explore for oil and natural gas +prospects and to acquire additional properties in the future depends upon its +ability to conduct its operations, to evaluate and select suitable properties +and to consummate transactions in this highly competitive environment. The +Company competes with a number of other companies that offer interests in +drilling partnerships with a wide range of investment objectives and program +structures. Competition for investment capital for both public and private +drilling programs is intense. The Company also faces intense competition in the +marketing of natural gas from competitors including other producers as well as +marketing companies. Also, international developments and the possible improved +economics of domestic natural gas exploration may influence other companies to +increase their domestic oil and natural gas exploration. Furthermore, +competition among companies for favorable prospects can be expected to +continue, and it is anticipated that the cost of acquiring properties may increase +in the future. During 2005 the industry experienced increased demand for +drilling services and supplies. This is resulting in increasing costs, and in +some cases the demand for supplies and services exceeds the available supplies. +This can result in higher well costs and delays in the execution of planned +drilling operations. Factors affecting competition in the oil and natural gas +industry include price, location, availability, quality and volumes produced. +The Company's management believes that it can compete effectively in the oil +and natural gas industry on each of the foregoing factors. Nevertheless, the +Company's business, financial condition or results of operations could be +materially adversely affected by competition. +Employees +As of December 31, 2005, the Company had 150 employees, including 21 in finance and data +processing, 9 in administration, 15 in exploration and development, 99 in +production and 6 in natural gas marketing. The Company's engineers, supervisors +and well tenders are responsible for the day-to-day operation of wells and +pipeline systems. In addition, the Company retains subcontractors to perform +drilling, fracturing, logging, and pipeline construction functions at drilling +sites. The Company's employees act as supervisors of the subcontractors. The +Company added 36 new employees in 2005. +The Company's +employees are not covered by a collective bargaining agreement. The Company +considers relations with its employees to be excellent. \ No newline at end of file diff --git a/raw/filings/0000077877/2005/0000077877-06-000037/item9a.txt b/raw/filings/0000077877/2005/0000077877-06-000037/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..d5591e698d4095944dcaa4afd5e11413bc9d86af --- /dev/null +++ b/raw/filings/0000077877/2005/0000077877-06-000037/item9a.txt @@ -0,0 +1,5711 @@ +Item 9A. Controls and Procedures +(a) +Evaluation +of Disclosure Controls and Procedures +The Company has evaluated, +under the supervision and with the participation of the Company's management, +including the Company's Chief Executive Officer, President and Chief Financial +Officer, the effectiveness of the design and operations of the Company's +disclosure controls and procedures pursuant to Securities Exchange Act of 1934, +as amended (the Exchange Act) Rules 13a-15(e) and 15-d-15(e) as of December 31, 2005. In the course of the evaluation, the Company considered the material +weaknesses in the Company's internal control over financial reporting and other +internal control matters discussed below and has concluded that the Company did +not maintain effective disclosure controls and procedures as of December 31, 2005. +(b) +Changes +and Remediation in the Company's Internal Control Over Financial Reporting +There have not been any changes in the +Company's internal control over financial reporting (as such term is defined in +Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934) during +the most recent fiscal quarter that have materially affected or are reasonably +likely to materially affect the Company's internal control over financial +reporting, except for changes in the fourth quarter of 2005 as noted below. +• +The +Company has increased the Company's technical expertise through development of +training programs and acquiring accounting research software during the fourth +quarter of 2005. Training will be on-going, however programs provided during +2005 included oil and gas accounting, general accounting and SEC financial +reporting. +• +The +Company has enhanced the documentation of the Company's policies and procedures +and related templates and analyses that support the Company's application of +accounting principles in the several areas, including derivative accounting, +oil and gas properties, and asset retirement obligations during the fourth +quarter of 2005. +In addition, during the third +quarter of fiscal 2005 and subsequently in 2006 the Company made the following +changes and remediation: +At the direction of the +Company's board of directors and audit committee, the Company has spent and +continues to spend a significant amount of time and resources to improve the +Company's control environment. The Company is committed to instilling strong +internal control policies and procedures and ensuring that the "tone at the +top" fully supports accuracy and completeness in all financial reporting. In +support of this position, the Company's progress toward improving internal +control over financial reporting has been openly communicated with the +Company's Audit Committee, and the Company has undertaken to improve the design +and effectiveness of the Company's internal control over financial reporting. +The initiatives developed by the Company were both organizational and process +focused. Organizational changes made during 2005 and through the date of this +filing include, among others: +45 +• +The +Company has enhanced the corporate accounting and reporting functions in the +third quarter of 2005 by creating and filling several new positions with +professionals highly experienced in oil and gas accounting. Two new +professionals hold degrees in accounting and are Certified Public Accountants. +One additional Certified Public Accountant was hired in early 2006, and a financial +reporting director will be hired during 2006. +• +The +Company engaged a team of highly experienced advisors in early 2006 to assist +with various accounting research, projects and monitoring activities. They +assist the Company with accounting and reporting issues including, but not +limited to, derivatives, oil and gas activities, new accounting standards or +rules, SEC reporting and on-going monitoring of changes that may impact the +Company's application of accounting principles. +• +The +Company has strengthened its Sarbanes-Oxley Act Section 404 compliance department through the addition of a +leadership position and other experienced resources in the third quarter of +2005. The Company believes the strengthening of this department will +significantly improve the design, effectiveness and monitoring of internal +control over financial reporting. +The Company has also +implemented or is planning to implement several process changes to improve the +documentation supporting certain accounting and reporting activities as well as +to improve the documentation of the Company's application of accounting +principles. +• +The +Company has evaluated and selected a third-party integrated oil and gas +accounting software system, which the Company plans to implement during 2006. +The Company believes the +measures taken to date and planned for the future will address the reported +material weaknesses and intends to complete the remediation efforts during +2006. In addition, the Company will continue to develop and implement other initiatives +during 2006 that will further improve both the effectiveness and efficiency of +the Company's internal control over financial reporting. +(c) +Management's +Report on Internal Control Over Financial Reporting +The Company's management is +responsible for establishing and maintaining adequate internal control over +financial reporting, as that term is defined under Rule 13a-15(f) promulgated +under the Exchange Act. In order to evaluate the effectiveness of the +Company's internal control over financial reporting as of December 31, 2005, as required by Section 404 of the Sarbanes-Oxley Act of 2002, management conducted +an assessment, including testing, using the criteria set forth in Internal +Control - Integrated Framework issued by the committee of Sponsoring +Organization of the Treadway Commission (the "COSO Framework"). Because of +inherent limitations, internal control over financial reporting may not prevent +or detect misstatements. In addition, 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 the degree of compliance +with policies or procedures may deteriorate. +A material weakness is a +control deficiency, or combination of control deficiencies, that results in +more than a remote likelihood that a material misstatement of the annual or +interim financial statements will not be prevented or detected. The Company's +assessment as of December 31, 2005, identified the following material +weaknesses: +The Company did not have +effective policies and procedures, and was not adequately staffed with +accounting personnel possessing an appropriate level of technical expertise in +U.S. generally accepted accounting principles, as further described below: +• +The Company +did not have effective policies and procedures, or personnel with sufficient +technical expertise, to properly account for derivative transactions in +accordance with generally accepted accounting principles. Specifically, the +Company's policies and procedures relating to derivatives transactions were not +designed effectively to ensure that each of the requirements for hedge +accounting was evaluated appropriately with respect to the Company's commodity +based derivatives. Additionally, the Company's policies and procedures relating +to the derivative transactions entered into on behalf of affiliated +partnerships were not adequate to ensure these transactions were recorded +properly in the financial statements. +As a result, a misstatement was identified in the fair value of derivatives and +the oil and gas price risk management loss accounts that was corrected prior to +the issuance of the Company's 2005 consolidated financial statements. This deficiency results in more than a remote likelihood +that a material misstatement of the Company's annual or interim consolidated +financial statements would not be prevented or detected. +46 +• +The +Company did not have effective policies and procedures, or personnel with +sufficient technical expertise, to ensure compliance with appropriate +accounting principles for its oil and gas properties. Specifically, the +Company's policies and procedures were not designed effectively to ensure that +the calculation of depreciation and depletion and the determination of impairments +were performed in accordance with the applicable authoritative accounting +guidance. As a result, +misstatements were identified in the accumulated depreciation, depletion and +amortization and the depreciation, depletion and amortization expense accounts +that were corrected prior to the issuance of the Company's 2005 consolidated +financial statements. This deficiency results in more +than a remote likelihood that a material misstatement of the Company's annual +or interim consolidated financial statements would not be prevented or +detected. +• +The +Company did not have effective policies and procedures, or personnel with +sufficient technical expertise, to ensure proper accounting and disclosure for +income taxes. Specifically, the Company's policies and procedures did not +provide for appropriate control documentation or supervisory review of +permanent and temporary differences, or assessment of tax reserves to ensure +that they were properly reflected and disclosed in the Company's financial +statements. As a result, +misstatements were identified in the deferred income tax liability and income +tax expense accounts that were corrected prior to the issuance of the Company's +2005 consolidated financial statements. This +deficiency results in more than a remote likelihood that a material +misstatement of the Company's annual or interim consolidated financial +statements would not be prevented or detected. +• +The +Company did not have effective policies and procedures, or personnel with +sufficient technical expertise, to ensure that its accounting for asset +retirement obligations complied with generally accepted accounting principles. +Specifically, the Company's policies and procedures regarding the estimate of +the fair value of the asset retirement obligations were not designed +effectively to ensure that it was estimated in accordance with FAS No. 143, Asset +Retirement Obligations . This deficiency results in more than a remote +likelihood that a material misstatement of the Company's annual or interim +consolidated financial statements would not be prevented or detected. +• +The +Company did not have effective policies and procedures, or personnel with +sufficient technical expertise, to provide for adequate monitoring and +assessment of the application of accounting principles, standards or rules as it +relates to proportionate consolidation in a timely manner. As a result of this +control deficiency, the Company did not appropriately eliminate its proportionate share of transactions with +the Company sponsored limited partnerships, which resulted in the restatement +of the Company's financial statements for the first three quarters of 2005, the +years ended December 31, 2004, 2003, 2002, and 2001 and each of the quarters in +2004 and 2003. +Management has concluded +that, as a result of the material weaknesses noted above, the Company did not +maintain effective internal control over financial reporting as of December 31, 2005 based on criteria set forth in the COSO Framework. +The Company's independent +registered public accounting firm, KPMG LLP, has issued an audit report on +management's assessment of the Company's internal control over financial +reporting as of December 31, 2005. Their report follows this section of the +Form 10-K. +47 +Report of +Independent Registered Public Accounting Firm +The Board of Directors and Stockholders +Petroleum Development Corporation: +We have audited management's assessment, included in +the accompanying Management's Report on Internal Control Over Financial +Reporting (Item 9A(c)), that Petroleum Development Corporation (the Company) +did not maintain effective internal control over financial reporting as of December 31, 2005 because of the effect of the material weaknesses identified in +management's assessment based on criteria established in Internal +Control-Integrated Framework issued by the Committee of Sponsoring +Organizations of the Treadway Commission (COSO). 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 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. +A +material weakness is a control deficiency, or combination of control +deficiencies, that results in more than a remote likelihood that a material +misstatement of the annual or interim financial statements will not be +prevented or detected. Management has identified and included in its assessment +the following material weaknesses as of December 31, 2005: +The +Company did not have effective policies and procedures, and was not adequately +staffed with accounting personnel possessing an appropriate level of technical +expertise in U.S. generally accepted accounting principles, as further +described below: +The Company +did not have effective policies and procedures, or personnel with +sufficient technical expertise, to properly account for derivative +transactions in accordance with generally accepted accounting principles. +Specifically, the Company's policies and procedures relating to +derivatives transactions were not designed effectively to ensure that each +of the requirements for hedge accounting was evaluated appropriately with +respect to the Company's commodity based derivatives. Additionally, the +Company's policies and procedures relating to the derivative transactions +entered into on behalf of affiliated partnerships were not adequate to ensure +these transactions were recorded properly in the financial statements. As +a result, a misstatement was identified in the fair value of derivatives +and the oil and gas price risk management loss accounts in the Company's +2005 preliminary consolidated financial statements. This deficiency results in more than a remote +likelihood that a material misstatement of the Company's annual or interim +consolidated financial statements would not be prevented or detected. +48 +The +Company did not have effective policies and procedures, or personnel with +sufficient technical expertise, to ensure compliance with appropriate +accounting principles for its oil and gas properties. Specifically, the +Company's policies and procedures were not designed effectively to ensure +that the calculation of depreciation and depletion and the determination +of impairments were performed in accordance with the applicable authoritative +accounting guidance. As a result, misstatements were identified in the +accumulated depreciation, depletion and amortization and the depreciation, +depletion and amortization expense accounts in the Company's preliminary 2005 +consolidated financial statements. This +deficiency results in more than a remote likelihood that a material +misstatement of the Company's annual or interim consolidated financial +statements would not be prevented or detected. +The +Company did not have effective policies and procedures, or personnel with +sufficient technical expertise, to ensure proper accounting and disclosure +for income taxes. Specifically, the Company's policies and procedures did +not provide for appropriate control documentation or supervisory review of +permanent and temporary differences, or assessment of tax reserves to +ensure that they were properly reflected and disclosed in the Company's +financial statements. As a result, misstatements were identified in the +deferred income tax liability and income tax expense accounts in the +Company's preliminary 2005 consolidated financial statements. This deficiency results in more than a remote +likelihood that a material misstatement of the Company's annual or interim +consolidated financial statements would not be prevented or +detected. +The +Company did not have effective policies and procedures, or personnel with +sufficient technical expertise, to ensure that its accounting for asset +retirement obligations complied with generally accepted accounting +principles. Specifically, the Company's policies and procedures regarding +the estimate of the fair value of the asset retirement obligations were +not designed effectively to ensure that it was estimated in accordance +with FAS No. 143, Asset Retirement Obligations. This deficiency results in more than a remote +likelihood that a material misstatement of the Company's annual or interim +consolidated financial statements would not be prevented or detected. +The +Company did not have effective policies and procedures, or personnel with sufficient +technical expertise, to provide for adequate monitoring and assessment of +the application of accounting principles, standards or rules as it relates +to proportionate consolidation in a timely manner. As a result of this control deficiency, the Company did not +appropriately eliminate its proportionate share of transactions +with the Company sponsored limited partnerships, which resulted in the +restatement of the Company's financial statements for the first three +quarters of 2005, the years ended December 31, 2004, 2003, 2002, and 2001 and each of the quarters in 2004 and 2003. +We also have audited, in accordance with the standards +of the Public Company Accounting Oversight Board (United States), the +consolidated balance sheets of Petroleum Development Corporation and +subsidiaries as of December 31, 2005 and 2004, and the related consolidated +statements of income, stockholders' equity and cash flows for each of the years +in the three-year period ended December 31, 2005. The aforementioned material weaknesses were considered in determining the nature, timing and extent of +audit tests applied in our audit of the 2005 consolidated financial statements, and this report does not affect our report dated +May 24, 2006, which expressed an unqualified opinion on those consolidated +financial statements. +In our opinion, management's assessment that Petroleum +Development Corporation did not maintain 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 (COSO). Also, in our opinion, because of the effect of the +material weaknesses described above on the achievement of the objectives of the +control criteria, Petroleum Development Corporation did not maintain 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 (COSO). +KPMG LLP +Pittsburgh, Pennsylvania +May 24, 2006 +49 +Item +9B. Other Information +None. +PART III +Item +10. Directors and Executive Officers of the Company +Directors and Executive Officers of the Company +The executive officers and directors of the +Company, their principal occupations for the past five years and additional +information are set forth below: +Name +Age +Positions and Offices Held +Held Current +Position Since +Steven R. Williams +55 +Chairman and Chief Executive Officer, +and Director +January 2004 +March 1983 +Thomas E. Riley +53 +President +Director +December 2004 +January 2004 +Darwin L. Stump +51 +Chief Financial Officer and Treasurer +November 2003 +Eric R. Stearns +48 +Executive Vice President Exploration and Production +December 2005 +Gregory A. Morgan +47 +Secretary +September 2004 +Vincent F. D'Annunzio +54 +Director +February 1989 +Jeffrey C. Swoveland +51 +Director +March 1991 +Donald B. Nestor +57 +Director +March 2000 +Kimberly Luff Wakim +47 +Director +January 2003 +David C. Parke +39 +Director +November 2003 +Steven R. Williams was elected Chairman and Chief +Executive Officer in January 2004. Mr. Williams served as President from March +1983 until December 2004 and has been a Director of the Company since March +1983. +Thomas E. Riley was elected Director in January 2004 by +the Board of Directors and assumed the position of President in December 2004. +Previously Mr. Riley was appointed Executive Vice President of Production, +Natural Gas Marketing and Business Development in November 2003. Prior thereto, +Mr. Riley served as Vice President Gas Marketing and Acquisitions of the +Company since April 1996. Prior to joining the Company, Mr. Riley was president +of Riley Natural Gas Company, a natural gas marketing company which the Company acquired in April 1996. +Darwin L. Stump was appointed Chief Financial Officer and +Treasurer in November 2003. Mr. Stump has been an officer of the Company since +April 1995 and held the position of Corporate Controller since 1980. Mr. Stump, +a CPA, was a senior accountant with Main Hurdman, Certified Public Accountants +prior to joining the Company. +Eric R. Stearns was appointed Executive Vice President of +Exploration and Production in December 2005. Prior to that he was Executive +Vice President of Exploration and Development since November 2003, having +previously served as Vice President of Exploration and Development since April +1995. Mr. Stearns joined the Company as a geologist in 1985 after working for Hywell, +Incorporated and for Petroleum Consultants. +Gregory A. Morgan has been a member of the law firm of +Young, Morgan & Cann, Clarksburg, West Virginia since 1986. Mr. Morgan is +not active in the day-to-day business of the Company, but his law firm provides +legal services to the Company. +Vincent F. D'Annunzio has served as president of Beverage +Distributors, Inc. located in Clarksburg, West Virginia since 1985. +Jeffrey C. Swoveland has served as Chief Financial +Officer of Body Media since September, 2000. Prior thereto, Mr. Swoveland was +Vice President-Finance and Treasurer of Equitable Resources, Inc. since 1994. +Donald B. Nestor is a Certified Public Accountant and a +Partner in the CPA firm of Toothman Rice, P.L.L.C. and is in charge of the +firm's Buckhannon, West Virginia office. Mr. Nestor has served in that +capacity since 1975. +50 +Kimberly Luff Wakim, an Attorney and Certified Public +Accountant, is a Partner with the law firm Thorp, Reed & Armstrong LLP. +Ms. Wakim joined Thorp Reed & Armstrong LLP in 1990. +David C. Parke was elected Director by the Board of +Directors in November 2003. In 2003, Mr. +Parke joined Mufson/Howe/Hunter & Company LLC, an investment banking firm +as a founder and Director. From 1992-2003, Mr. Parke was with the corporate +finance department of Investec, Inc. and its predecessor Pennsylvania Merchant +Group Ltd., investment banking companies. Prior to joining Pennsylvania +Merchant Group, Mr. Parke served in the corporate finance departments of Wheat +First Butcher & Singer, now part of Wachovia Securities, and Legg Mason, +Inc. +The Company's By-Laws +provide that the directors of the Company shall be divided into three classes +and that, at each annual meeting of stockholders of the Company, successors to +the class of directors whose term expires at the annual meeting will be elected +for a three-year term. The classes are staggered so that the term of one class +expires each year. Mr. Williams, Mr. Nestor and Ms. Wakim are members of the +class whose term expires in 2006. Mr. D'Annunzio and Mr. Riley are members of +the class whose term expires in 2007. Mr. Swoveland and Mr. Parke are members +of the class whose term expires in 2008. There is no family relationship between +any director or executive officer and any other director or executive officer +of the Company. There are no arrangements or understandings between any +director or officer and any other person pursuant to which the person was +selected as an officer. +On January 24, 2003, the Company adopted a Code of Business Conduct and Ethics Policy meeting the +specified standards applicable to the Chief Executive Officer and Chief +Financial Officer. The policy also covers all the corporate officers. The +policy is posted on the Company's website at www.petd.com. The Company will provide a copy of the +Code to any person, without charge, upon request to the Company's Secretary at +the Company's principal executive offices or by telephone at 800-624-3821. +The Company has determined that all of +its directors, other than Messrs. Williams and Riley are independent under +NASDAQ rule 4200. +The Audit Committee +of the Board of Directors is comprised entirely of independent directors as +defined by the NASDAQ rule 4200(a)(15). Donald B. Nestor, CPA, a partner in +the certified public accounting firm of Toothman Rice PLLC, chairs the +committee; other audit committee members are Mr. Jeffrey C. Swoveland and Ms. +Kimberly Luff Wakim. The Board of Directors has determined that Mr. Nestor and +the other Audit Committee members qualify as audit committee financial experts +and are independent of management. +The Nominating and +Governance and Compensation Committees are also comprised entirely of +independent directors of the Company. Vincent F. D'Annunzio chairs the +Nominating and Governance Committee, and David C. Parke chairs the Compensation +Committee. +The independent +directors conduct meetings without the presence of management at each scheduled +Board meeting. Kimberly Luff Wakim serves as Chairperson of these meetings +having been selected as lead independent director by the Board. +Shareholders wishing +to communicate with the Board of Directors or a committee may do so by writing +to the attention of the Board or Committee at the corporate headquarters or by +emailing the Board at board@petd.com, with "Board" or appropriate +committee in the subject line. +51 +Item 11. Executive Compensation +Summary +Compensation Table +The following table sets forth in summary form the compensation +received during each of the Company's last three fiscal years by the Chief +Executive Officer and by each other executive officer of the Company whose +salary and bonus exceeded $100,000 in 2005 (the "Named Executives"). +Annual Compensation +Long +Term Compensation +Other +Restricted +Securities +Annual +Stock +underlying +All +Other +Name +and +Bonus +Compen- +Awards +Options +Compen- +Principal +Position +Year +Salary($) +(1)($) +sation($)(2) +($)(3) +(#)(4) +sation($)(5) +Steven +R. Williams +2005 +318,000 +271,597 +11,886 +- +- +146,666 +Chief +Executive Officer +2004 +300,000 +300,000 +37,567 +302,030 +5,870 +135,834 +and Director +2003 +166,485 +1,312,385 +6,241 +- +- +101,726 +Thomas +E. Riley +2005 +252,000 +141,135 +4,638 +- +- +106,666 +President +2004 +240,000 +140,000 +5,624 +200,239 +3,890 +100,834 +and Director +2003 +153,400(6) +121,370 +1,565 +- +- +21,726 +Eric +R. Stearns +2005 +231,000 +129,374 +11,406 +- +- +102,666 +Executive +Vice President +2004 +220,000 +140,000 +9,678 +188,796 +3,670 +97,834 +2003 +132,567(6) +121,370 +1,084 +- +- +20,726 +Darwin +L. Stump +2005 +210,000 +98,713 +9,398 +- +- +106,666 +Chief +Financial Officer +2004 +200,000 +140,000 +12,773 +177,577 +3,450 +97,834 +and Treasurer +2003 +112,733(6) +121,370 +1,074 +- +- +12,777 +(1) Includes bonuses earned in the reported fiscal year and paid +in the following fiscal year. +(2) Amounts disclosed in this column consist of use of a company +vehicle, life insurance, disability insurance, and medical reimbursement as +provided for in the Named Executive's employment contract. +(3) Amounts disclosed in this column consist of the value of +restricted stock awards based upon the closing price of our common stock on the +date of grant which was $37.15 on December 13, 2004. During 2004 the number of +shares awarded to Messrs. Williams, Riley, Stearns and Stump amounted to 8,130, +5,390, 5,080 and 4,780 shares, respectively. These shares vest in four equal +installments on the first, second, third and fourth anniversaries of the grant +date. +(4) Amounts in this column represent the number of options granted +on December 13, 2004 to the named individuals. The fair value of these options +at date of grant was $16.75 using the Black-Scholes option pricing model with +an exercise price of $37.15. These options vest in four equal installments on +the first, second, third and fourth anniversaries of the grant date. +52 +(5) This amount includes contributions made by the Company under +the Company's Employee Profit Sharing Plan and 401(k) plan. In 2005, 2004 and +2003 the Company contributed $420,000, $300,000 and $250,000, respectively, to +the Employee Profit Sharing Plan. Of the contributions for 2005 and 2004, +Messrs. Williams, Riley, Stearns and Stump were each credited $13,666 and +$9,834, respectively. Of the contributions for 2003, Messrs., Williams, Riley +and Stearns were each credited $9,726 and Mr. Stump was credited $8,634. The +Company provided a matching of 401(k) contribution based upon all employees +respective contributions. The total Company matching contributions were +$450,653, $382,700 and $305,515 in 2005, 2004 and 2003. For 2005, Messrs. +Williams, Riley and Stump were each credited with matching contributions of +$18,000, Mr. Stearns was credited with a matching contribution of $14,000. For +2004, Messrs. Williams and Riley were each credited with matching contributions +of $16,000, Messrs. Stearns and Stump were credited with matching contributions +of $13,000. For 2003, Messrs. Williams and Riley were each credited with +matching contributions of $12,000, Messrs. Stearns and Stump were credited with +matching contributions of $11,000 and $4,143, respectively. This amount also +includes retirement compensation for the named individuals which provides for +an amount per year worked under their employment agreements for 10 years +following their termination of service. The total amounts earned during 2005 +and 2004 to be paid over the ten-year period following such individuals' +termination amounted to $115,000 and $110,000, respectively for Mr. Williams, +and $75,000 for Messrs. Riley, Stearns and Stump for each year. For 2003 such +amount was $80,000 for Mr. Williams. See "Retirement Arrangements" +discussed below for a description of these arrangements. +(6) +This amount includes +compensation for Messrs. Riley, Stearns and Stump earned during 2003 while each +was an officer of the Company prior to becoming an Executive Officer in +November 2003. +Aggregated +Option Exercises in Last Fiscal Year and Fiscal Year-End Option Values +The following +table provides certain information with respect to options exercised during +2005 by the persons named in the Summary Compensation Table under the Company's +stock option plans, the number of options outstanding as of December 31, 2005 +and the year-end value of such options, with respect to options granted +pursuant to the Company's employee stock compensation plans. +Value of Unexercised +Number +Number of Options +In-The-Money Options +of Shares +Value +at Year-end +at Year-End(1)($) +Exercised +Realized ($)* +Exercisable +Unexercisable +Exercisable +Unexercisable* +Steven R. Williams +- +- +1,467 +4,403 +- +- +Thomas E. Riley +- +- +972 +2,918 +- +- +Eric R. Stearns +- +- +917 +2,753 +- +- +Darwin L. Stump +- +- +862 +2,588 +- +- +*Market value of +the underlying securities at exercise or year-end, as applicable, minus the +exercise price. +(1) On December +31, 2005, the closing sales price of the Common Stock was $33.34 per share; the +exercise price of these options is $37.15 per share. +Employment and Other Agreements and +Arrangements +The +Company entered into employment agreements with Messrs. Williams, Riley, +Stearns and Stump effective January 1, 2004. The initial term of the agreements +is for two years and they are automatically extended for an additional 12 +months beginning on the first anniversary of the effective date and on each +successive anniversary unless either party cancels. The employment agreements +provided for a base annual salary for Mr. Williams, Mr. Riley, Mr. Stearns and +Mr. Stump in the amounts of $300,000, $240,000, $220,000 and $200,000, +respectively for 2004. For 2005 the Compensation Committee established base +salaries for Mr. Williams, Mr. Riley, Mr. Stearns and Mr. Stump in the amounts +of $318,000, $252,000, $231,000 and $210,000, respectively. Each employment +agreement provides for an annual performance bonus, based upon a combination of +written objective criteria approved by the Compensation Committee, determined +prior to the beginning of each calendar year and upon the discretion of the +Compensation Committee. The maximum amounts of the entire annual performance +bonus were $300,000 for Mr. Williams and $140,000 for Messrs. Riley, Stearns +and Stump in 2004. Each of the executives earned the maximum bonus in 2004. For +2005 the Compensation Committee set maximum annual performance amounts for Mr. +Williams, Mr. Riley, Mr. Stearns and Mr. Stump of $413,400, $201,600, $184,800 +and $168,000, respectively. Bonus earned in 2005 was $271,597 for Mr. Williams, +$141,135 for Mr. Riley, $129,374 for Mr. Stearns and $98,713 for Mr. Stump. +In +the event of a change in control of the Company, each Named Executive has the +right to elect to terminate his employment under his employment agreement and +receive severance compensation equal to three times the sum of 1) his highest +base salary in the previous two years of employment plus 2) highest bonus paid +to the named Executive during the same two year period. +Each +employment agreement contains a standard non-disclosure covenant. Each +employment agreement also provides that the Named Executive is prohibited +during the term of his employment and for a period of one year following his +termination from engaging in any business that is competitive with the +Company's oil and gas drilling business. +Retirement Arrangements +The +Company provides supplemental retirement benefits under terms of the various +employment agreements with the Company's executive officers. The January 1, +2004 agreements provide for retirement benefits for each executive officer for +a ten year period following the date of termination of service. During the life +of each respective agreement, $110,000 for Mr. Williams and $75,000 for each of +Messrs. Riley, Stearns and Stump are allocated yearly to their respective +retirement account. The allocated amounts are accumulated over the life of the +respective agreements. Following termination of service the aggregate fund will +be disbursed to the individual officer in equal installments over ten years. +Mr. Williams' agreement has an escalator provision which provides an increase +in the annual contribution allocated to his retirement amount equal to $5,000 +per year. In 2004, the allocation to Mr. Williams supplemental retirement +account was $110,000; in 2005, the allocation increased to $115,000 for his +account; in 2006, the allocation will increase to $120,000. At December 31, +2005, the executive officers had accumulated the following amounts in their +respective retirement accounts, Mr. Williams $225,000; Mr. Riley $150,000; Mr. +Stearns $150,000 and Mr. Stump $150,000. These accounts will continue to +accumulate retirement funds during the terms of the respective employment +agreements. +53 +Under +his previous employment agreement, Mr. Williams also earned supplemental +retirement benefits. The prior agreement requires the Company to pay Mr. +Williams an annual sum of $40,000 per year for the ten year period following +his retirement from the Company (an aggregate of $400,000), in addition to +benefit discussed above. This benefit was fully vested on December 31, 2003. +Stock Option Plans +Under +the Company's incentive stock option plans, options to purchase shares of +Common Stock of the Company may be granted to certain officers and key +employees of the Company, which options are intended to qualify as incentive +stock options under the provisions of the Internal Revenue Code. The options +may be exercised six months after the date of grant. Options will expire ten +years from the date of grant if not exercised. A dissolution or liquidation of +the Company or a merger or consolidation in which the Company is not the +surviving corporation will cause each outstanding option to terminate, provided +that each optionee, in such event, will have the right immediately prior to +said dissolution or liquidation or merger or consolidation to exercise his +option in whole or in part without regard to any installment vesting provisions +with respect to such options. No additional options may be granted under these +earlier plans. +As +approved by the shareholders at the annual meeting in 2004, the Company has a +Long-Term Equity Compensation Plan which allows for the awarding of +Non-qualified stock options, Incentive Stock Options, Stock Appreciation +Rights, Restricted Stock, Performance shares and Performance units. The number +of shares allocated to this plan is 750,000 shares. During 2004, a total of +23,380 shares of restricted stock and 16,880 options were granted to the +executives named previously. As of April 30, 2006, 664,075 shares remain in the +plan, for future grants. +Key-Man Life Insurance +The +Company maintains key-man life insurance policies on the life of Mr. Williams +in the amount of $4.0 million, and in the amount of $1.0 million for Messrs. +Riley, Stearns and Stump. The Company is the beneficiary of each policy. +Employee 401(k) and Profit Sharing Plan +In +1987, the Company established a retirement plan qualified under Section 401(k) +of the Internal Revenue Code. The plan is funded by employee contributions and +a company matching contribution. Administrative costs of the plan are borne by +the Company. The employees choose from eight investment programs and, +therefore, the amount of an individual's plan assets depends on the amount of +their contributions and the performance by their chosen investments. +In +1992, the Company began a Profit Sharing Retirement plan to supplement the +401(k) Plan. Contributions are dependent on corporate profitability and are at +the discretion of the Board of Directors of the Company. The Company filed and +qualified the plan with the Internal Revenue Service. +Item 12. Security Ownership of Certain Beneficial +Owners and Management and Related Stockholder Matters +The following table sets forth certain information +regarding ownership of the Company's Common Stock as of April 30, 2006 by (a) +each person known by the Company to own beneficially more than 5% of the +outstanding shares of Common Stock; (b) each director of the Company; (c) each +Named Executive; (d) all directors and executive officers as a group. +54 +Beneficial Ownership (1) +Name +and Address +Number +Percent +Barclays +Global Investors, NA +45 +Fremont Street +San +Francisco, CA 94105 +2,477,121 +(2) +15.40% +Fidelity +Management +82 +Devonshire Street +Boston, MA 02109 +2,415,600 +(3) +15.00% +Kayne Anderson Rudnick +Investment Management LLC +1800 Avenue of the Stars 2nd Floor +Los Angeles, CA 90067 +1,281,289 +(4) +8.00% +Steinberg Asset Management LLC +12 East 49th Street +New York, NY 10017 +1,104,781 +(5) +6.90% +Steven +R. Williams +103 +East Main Street +Bridgeport, WV 26330 +421,101 +(6) +2.60% +Thomas +E. Riley +103 +E. Main Street +Bridgeport, WV 26330 +109,700 +(7) +* +Eric +R. Stearns +103 +E. Main Street +Bridgeport, WV 26330 +61,438 +(8) +* +Darwin +L. Stump +103 +E. Main Street +Bridgeport, WV 26330 +30,473 +(9) +* +Vincent F. D'Annunzio +18,646 +* +Jeffrey C. Swoveland +13,721 +* +Donald B. Nestor +2,522 +* +Kimberly Luff Wakim +2,965 +* +David C. Parke +2,450 +* +All +directors and executive officers as a +663,016 +4.10% +group (9 persons) +55 +* Less than 1% +(1) +Includes shares over which the +person currently holds or shares voting or investment power. Unless otherwise +indicated in the footnotes to this table, the persons named in this table have +sole voting and investment power with respect to the shares beneficially owned. +(2) +According to the Schedule 13G +filed by Barclay Global Investors, NA with the Securities and Exchange +Commission on January 26, 2006. +(3) +According to the Schedule 13G +filed by Fidelity Management with the Securities and Exchange Commission on +January 10, 2006. +(4) According to +Schedule 13G filed by Kayne Anderson Rudnick Investment Management, LLC with +the Securities and Exchange Commission on February 6, 2006. +(5) According to the +Schedule 13F-HR filed by Steinberg Asset Management, LLC with the Securities +and Exchange Commission on April 17, 2006. +(6) Mr. Williams: +includes 1,467 shares subject to options exercisable within 60 days of April +30, 2006. +(7) Mr. Riley: includes +972 shares subject to options exercisable within 60 days of April 30, 2006. +(8) Mr. Stearns: +includes 917 shares subject to options exercisable within 60 days of April 30, +2006. +(9) Mr. Stump: includes +862 shares subject to options exercisable within 60 days of April 30, 2006. +Section +16(a) Beneficial Ownership Reporting Compliance +Section 16(a) of the Exchange Act requires the +Company's officers and directors, and persons who own more than 10% of a +Company's equity securities, to file reports of ownership and changes in +ownership with the Securities and Exchange Commission. Officers, directors and +holders of more than 10% of the Common Stock are required by regulations +promulgated by the Commission pursuant to the Exchange Act to furnish the +Company with copies of all Section 16(a) forms they file. The Company assists +officers and directors, and will assist beneficial owners, if any, of more than +10% of the Common Stock, in complying with the reporting requirements of +Section 16(a) of the Exchange Act. +Based solely on its review of the copies of such +forms received by it, the Company believes that since January 1, 2005, all +Section 16(a) filing requirements applicable to its directors, officers and +greater than 10% beneficial owners were met. +The Company has the +following common stock options outstanding under the stock option plans authorized +for issuance: +Equity +Compensation Plan Information +April 30, 2006 +Plan Category +Number of securities to +be issued upon exercise +of outstanding options, +warrants and rights +(a) +Weighted-average +exercise price of +outstanding options, +warrants and rights +(b) +Number of securities +remaining available for +future issuance under +equity compensation +plans (excluding +securities reflected in +column (a)) +(c) +Equity compensation plans +approved by security holders +94,234 +$18.82 +664,075 +Equity compensation plans not +approved by security holders +0 +0 +0 +Total +94,234 +$18.82 +664,075 +Item 13. Certain Relationships and Related Transactions +During the year ended December 31, 2005, there was no transaction or +series of transactions to which we were or are a party in which the amount +involved exceeded or exceeds $60,000 and in which any director, executive +officer, holder of more than 5% of our common stock or any member of the +immediate family of any of the foregoing persons had or will have a direct or +indirect material interest. +Item 14. Principal +Accountant Fees and Services +KPMG Fees +The following +table presents the aggregate fees billed to the Company by KPMG LLP (KPMG) for +services in 2005 and 2004 as of March 31, 2006: +56 +2005 +2004 +Audit Fees +$ 1,743,010 +$ 708,524 +Audit Related +Fees +140,977 +309,127 +Total Audit +and Audit Related Fees +$1,883,987 +$1,017,651 +Tax Fees +0 +4,000 +All Other Fees +0 +0 +Total Fees +$ 1,883,987 +$ 1,021,651 +Audit +Fees +The aggregate +audit fees billed for professional services rendered by KPMG LLP for the audit +of our annual financial statements and the audit of the Company's internal +controls over financial reporting for the fiscal years ended December 31, 2005 +and 2004, including reviews of the condensed financial statements included in +our quarterly reports on Form 10-Q for the fiscal years ended December 31, 2005 +and 2004, were $1,743,010 and $708,524. +Audit Related +Fees +The aggregate of +audit related fees relating to registration statements filed with the +Securities and Exchange Commission amounted to $24,900 for the year ended +December 31, 2004. Also included as audit related fees are the annual audits of +the financial statements for the fiscal years ended December 31, 2005 and 2004 +of sixty-five and sixty-two limited partnerships, respectively, for which the +Company acts as managing general partner. The aggregate billings for those +professional services was $284,227 for the year ended December 31, 2004, the +services for the year ended December 31, 2005 have not been billed as of March +31, 2006. The total of audit related fees for the year ended December 31, 2005 +was for due diligence services provided for a contemplated transaction. +Tax Fees +Tax Fees include +tax compliance services for the fiscal year ended December 31, 2004 provided +for the partnerships formed in such year for which the Company acts as managing +general partner, in the amount of $4,000. +Pre-Approval +Policies and Procedures +The Sarbanes-Oxley +Act of 2002 requires that all services provided to the Company by its Independent +Registered Public Accounting Firm be subject to pre-approval by the Audit +Committee or authorized members of the Committee. The Audit Committee has +adopted policies and procedures for pre-approval of all audit services and +non-audit services to be provided by the Company's Independent Registered +Public Accounting Firm. Services necessary to conduct the annual audit must be +pre-approved by the Audit Committee annually at a meeting. Permissible +non-audit services to be performed by the independent accountant may also be +approved on an annual basis by the Audit Committee if they are of a recurring +nature. Permissible non-audit services to be conducted by the independent +accountant which are not eligible for annual pre-approval must be pre-approved +individually by the full Audit Committee or by an authorized Audit Committee +member. Actual fees incurred for all services performed by the independent +accountant will be reported to the Audit Committee after the services are fully +performed. The duties of the Committee are described in the Audit Committee +Charter, which is available at the Company's website under Corporate +Governance. +Item 15. Exhibits and Financial Statement Schedules +(a) (1) Financial +Statements: +See +Index to Financial Statements and Schedules on page F-1. +(2) Financial +Statement Schedules: +See +Index to Financial Statements and Schedules on page F-1. +Schedules +and Financial Statements Omitted +All other financial +statement schedules are omitted because they are not required, inapplicable, or +the information is included in the Financial Statements or Notes thereto. +(3) Exhibits: +See +Exhibits Index on page E-1. +57 +CONFORMED COPY +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. +PETROLEUM +DEVELOPMENT CORPORATION +By /s/ +Steven R. Williams +Steven R. +Williams, Chairman +May 31, 2006 +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/ Steven R. Williams +Steven R. Williams +Chairman, Chief Executive Officer and Director +May 31, 2006 +/s/ Darwin L. Stump +Darwin L. Stump +Chief Financial Officer and Treasurer +(principal financial and accounting officer) +May 31, 2006 +/s/ Thomas E. Riley +Thomas E. Riley +President and Director +May 31, 2006 +/s/ Donald B. Nestor +Donald B. Nestor +Director, Chairman of Audit Committee +May 31, 2006 +/s/ Vincent F. D'Annunzio +Vincent F. D'Annunzio +Director +May 31, 2006 +/s/ Jeffrey C. Swoveland +Jeffrey C. Swoveland +Director +May 31, 2006 +/s/ Kimberly Luff Wakim +Kimberly Luff Wakim +Director +May 31, 2006 +/s/ David C. Parke +David C. Parke +Director +May 31, 2006 +58 +Exhibits Index +(a) Exhibits +Exhibit Name +Exhibit +Number +Location +Articles of Incorporation +3.1 +Incorporated by reference to Exhibit 3.1 to Form S-2 +SEC File No. 333-36369 filed on September 25, 1997 +By Laws +3.2 +Incorporated by reference to Exhibit 3.2 to Form 8-K +SEC File No. 0-07246 filed on September 8, 2003 +Amended +and restated Credit Agreement, dated as of November 4, 2005, Petroleum Development Corporation, as borrower, and JPMorgan Chase Bank, N.A. and BNP Paribas, +as lenders. +10.1 +Incorporated by reference to Exhibit 10.2 to Form 8-K +dated November 4, 2005. +Employment Agreement with Steven R. Williams, Chief +Executive Officer and Chairman, dated as of March 7, 2003 and amended December 29, 2005 +10.2 +Incorporated by reference in Exhibit 10.2 to Form 10-K +filed on March 7, 2003 and amended by reference of Form 8-K filed January 4, 2006 +Employment Agreement with Darwin L. Stump, Chief +Financial Officer, dated as of January 5, 2004 and amended December 29, 2005 +10.3 +Incorporated by reference to Exhibit 99.4 Form 8-K +dated January 5, 2004 and Exhibit 99.4 to Form 8-K dated January 4, 2006 +Employment Agreement with Thomas E. Riley, President, +dated as of January 5, 2004 and amended December 29, 2005 +10.4 +Incorporated by reference to Exhibit 99.6 Form 8-K +dated January 5, 2004 and Exhibit 99.2 to Form 8-K dated January 4, 2006 +Employment Agreement with Eric R. Stearns, Executive +Vice President, dated as of January 5, 2004 and amended December 29, 2005 +2005 Non-Employee Director Restricted Stock Plan +10.5 +10.6 +Incorporated by reference to Exhibit 99.5 Form 8-K +dated January 5, 2004 and Exhibit 99.3 to Form 8-K dated January 4, 2006. +Incorporated by reference to Exhibit 99.1 to Form S-8, +SEC file No. 333-126444 filed on July 7, 2005 +2004 Long-Term Equity Compensation Plan +10.7 +Incorporated by reference to Exhibit 99.1 to Form S-8, +SEC File No. 333-118215, filed on August 13, 2004 +Non-Employee Director Deferred Compensation Plan +10.8 +Incorporated by reference Exhibit 99.1 to Form S-8, SEC +File No. 333-118222, filed on August 13, 2004 +1999 Incentive Stock Option and Non-Qualified Stock +10.9 +Incorporated by reference to Exhibit 99.1 to form S-8, +SEC File No. 333-111825, filed on January 9, 2004 +1997 Employee Incentive Stock Option Plan +10.10 +Incorporated by reference to Exhibit 99.1 to Form S-8, +SEC File No. 333-111824, filed on January 9, 2004 +Tom Carpenter Employment Agreement Stock Option Plan +10.11 +Incorporated by reference to Exhibit 99.1 to Form S-8, +SEC File No. 333-111823, filed on January 9, 2004 +Code of Business Conduct and Ethics +14 +Incorporated by reference to Exhibit 3.1 to +Form 10-K for the year ended December 31, 2002, SEC File No. 0-07246 filed on March 7, 2003 +Subsidiaries +21 +Riley Natural Gas Company, a West Virginia Corporation +21 +PDC Securities Incorporated, a West Virginia Corporation +Consent of Independent Registered Public Accounting +Firm +23.1 +Filed herewith. +Consent of Independent Petroleum Engineers +Consent of Independent Petroleum Engineers +23.2 +23.3 +Filed herewith. +Filed herewith +Rule 13a-14(a)/15d-14(a) Certification by Chief +Executive Officer +31.1 +Filed herewith. +Rule 13a-14(a)/15d-14(a) Certification by Chief +Financial Officer +31.2 +Filed herewith. +Title 18 U.S.C. Section 1350 (Section 906 of +Sarbanes-Oxley Act of 2002) Certifications by Chief Executive Officer and +Chief Financial Officer +32.1 +Filed herewith. +59 +GLOSSARY OF TERMS +The following +are abbreviations and definitions of terms commonly used in the oil and gas +industry and this Form 10-K. +Bbl . One barrel, or 42 U.S. gallons of liquid volume. +Bcf . One billion cubic feet. +Bcfe . One billion cubic feet of natural +gas equivalents. +Completion . The installation of permanent +equipment for the production of oil or gas. +Credit +Facility. A line +of credit provided by a group of banks, secured by oil and gas properties. +DD&A. Refers to depreciation, depletion +and amortization of the Company's property and equipment. +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 hydrocarbons in sufficient quantities to justify +completion as an oil or gas well. +Exploratory +well . A well +drilled to find and produce oil or natural gas reserves not classified as +proved, to find a new productive reservoir in a field previously found to be +productive of oil or natural gas in another reservoir or to extend a known +reservoir. +Extensions +and discoveries . +As to any period, the increases to proved reserves from all sources other than +the acquisition of proved properties or revisions of previous estimates. +Gross +acres or wells . +Refers to the total acres or wells in which the Company has a working interest. +Horizontal +drilling . A +drilling technique that permits the operator to contact and intersect a larger +portion of the producing horizon than conventional vertical drilling techniques +and may, depending on the horizon, result in increased production rates and +greater ultimate recoveries of hydrocarbons. +MBbls . One thousand barrels. +Mcf . One thousand cubic feet. +Mcfe . One thousand cubic feet of +natural gas equivalents, based on a ratio of 6 Mcf for each barrel of oil, +which reflects the relative energy content. +MMbtu. One million British thermal +units. One British thermal unit is the heat required to raise the +temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit. +MMcf . One million cubic feet. +MMcfe. One million cubic feet of natural +gas equivalents. +Natural +gas liquids . +Liquid hydrocarbons that have been extracted from natural gas, such as ethane, +propane, butane and natural gasoline. +Net +acres or wells . +Refers to gross acres or wells multiplied, in each case, by the percentage +working interest owned by the Company. +Net +production . Oil +and gas production that is owned by the Company, less royalties and production +due others. +NYMEX . New York Mercantile Exchange, the +exchange on which commodities, including crude oil and natural gas futures +contracts, are traded. +60 +Oil . Crude oil or condensate. +Operator . The individual or company +responsible for the exploration, development and production of an oil or gas +well or lease. +Present +value of proved reserves . +The present value of estimated future revenues, discounted at 10% annually, to +be generated from the production of proved reserves determined in accordance +with Securities and Exchange Commission guidelines, net of estimated production +and future development costs, using prices and costs as of the date of +estimation without future escalation, without giving effect to +(i) estimated future abandonment costs, net of the estimated salvage value +of related equipment, (ii) nonproperty related expenses such as general +and administrative expenses, debt service and future income tax expense, or +(iii) depreciation, depletion and amortization. +Proved +developed nonproducing reserves . +Reserves that consist of (i) proved reserves from wells which have been +completed and tested but are not producing due to lack of market or minor +completion problems which are expected to be corrected and (ii) proved reserves +currently behind the pipe in existing wells and which are expected to be +productive due to both the well log characteristics and analogous production in +the immediate vicinity of the wells. +Proved +developed producing reserves. +Proved reserves that can be expected to be recovered from currently producing +zones under the continuation of present operating methods. +Proved +developed reserves. +The combination of proved developed producing and proved developed nonproducing +reserves. +Proved +reserves . 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, i.e., prices and costs as of the date the estimate is +made. Prices include consideration of changes in existing prices provided +only by contractual arrangements, but not on escalations based upon future +conditions. +Proved +undeveloped reserves (PUD) . +Proved 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. +Royalty . An interest in an oil and gas +lease that gives the owner of the interest the right to receive a portion of +the production from the leased acreage (or of the proceeds of the sale +thereof), but generally does not require the owner to pay any portion of the +costs of drilling or operating the wells on the leased acreage. Royalties +may be either landowner's royalties, which are reserved by the owner of the +leased acreage at the time the lease is granted, or overriding royalties, which +are usually reserved by an owner of the leasehold in connection with a transfer +to a subsequent owner. +SEC . The United States Securities and +Exchange Commission. +Standardized +measure of discounted future net cash flows . Present value of proved reserves, as adjusted to +give effect to (i) estimated future abandonment costs, net of the +estimated salvage value of related equipment, and (ii) estimated future +income taxes. +Undeveloped +acreage . Leased +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 proved reserves. +Working +interest . An +interest in an oil and gas lease that gives the owner of the interest the right +to drill for and produce oil and gas on the leased acreage and requires the +owner to pay a share of the costs of drilling and production operations. +The share of production to which a working interest is entitled will be smaller +than the share of costs that the working interest owner is required to bear to +the extent of any royalty burden. +Workover . Operations on a producing well to +restore or increase production. +61 +PETROLEUM +DEVELOPMENT CORPORATION AND SUBSIDIARIES +Index to Financial +Statements and Financial Statement Schedule +1. +Financial Statements: +Report of Independent +Registered Public Accounting Firm +F-2 +Consolidated Balance +Sheets - December 31, 2005 and 2004 +F-3 & 4 +Consolidated Statements +of Income - +Years Ended December 31, 2005, 2004 and 2003 +F-5 +Consolidated Statements +of Stockholders' Equity - +Years Ended December 31, 2005, 2004 and 2003 +F-6 +Consolidated Statements +of Cash Flows - +Years Ended December 31, 2005, 2004 and 2003 +F-7 +Notes to Consolidated +Financial Statements +F-8 -F-37 +2. +Financial Statement Schedule: +Schedule II - Valuation and Qualifying Accounts and +Reserves +F-38 +F-1 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Report of +Independent Registered Public Accounting Firm +The Board of Directors and Stockholders +Petroleum Development Corporation: +We have audited the accompanying consolidated balance +sheets of Petroleum Development Corporation and subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of income, +stockholders' equity, and cash flows for each of the years in the three-year +period ended December 31, 2005. In connection with our audits of the +consolidated financial statements, we also have audited the related financial +statement schedule II. These consolidated financial statements and financial +statement schedule are the responsibility of the Company's management. Our +responsibility is to express an opinion on these consolidated financial +statements and financial statement schedule 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, the consolidated financial statements +referred to above present fairly, in all material respects, the financial +position of Petroleum Development Corporation and subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for +each of the years in the three-year period ended December 31, 2005, in conformity with U. S. generally accepted accounting principles. Also in our opinion, the +related financial statement schedule, when considered in relation to the basic +consolidated financial statements taken as a whole, presents fairly, in all +material respects, the information set forth therein. +As discussed in Note 22 to the consolidated financial +statements, the Company restated its 2004 and 2003 consolidated financial +statements. +As discussed in Note 1 to the consolidated financial +statements, the Company adopted the provisions of Statement of Financial +Accounting Standards No. 143, Accounting for Asset Retirement Obligations, in +2003. +We also have audited, in accordance with the standards of +Public Company Accounting Oversight Board (United States), the effectiveness of +Petroleum Development Corporation's 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 (COSO) and our report dated May 15, 2006, expressed an +unqualified opinion on management's assessment of, and an adverse opinion on +the effective operation of, internal control over financial reporting as of December 31, 2005. +KPMG LLP +Pittsburgh, Pennsylvania +May 24, 2006 +F-2 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Consolidated Balance +Sheets +December 31, 2005 and 2004 +Assets +2005 +2004 +Current +assets: +Cash +and cash equivalents +$ +90,110,100 +$ 77,070,400 +Restricted +cash +1,500,600 +664,900 +Accounts +receivable +49,779,500 +33,834,700 +Accounts receivable affiliates +7,233,800 +2,230,600 +Inventories +5,054,900 +1,657,300 +Fair value of derivatives +10,381,800 +3,266,100 +Other +current assets +4,640,500 +6,612,800 +Total +current assets +168,701,200 +125,336,800 +Properties +and equipment: +Oil +and gas properties (successful +efforts +accounting method) +365,379,600 +282,837,200 +Pipelines +11,511,600 +9,515,000 +Transportation +and other equipment +6,382,800 +4,453,700 +Land +and buildings +3,980,800 +2,942,800 +Construction in progress +1,509,300 +- +388,764,100 +299,748,700 +Less +accumulated depreciation, +depletion +and amortization +111,605,900 +92,165,400 +277,158,200 +207,583,300 +Other +assets +3,225,500 +2,108,200 +Total +Assets +$ +449,084,900 +$ 335,028,300 +(Continued) +F-3 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Consolidated +Balance Sheets +December 31, 2005 and 2004 +Liabilities +and Stockholders' Equity +2005 +2004 +Current +liabilities: +Accounts +payable +$ +65,004,100 +$ +43,182,900 +Production +tax liability +30,144,500 +17,510,500 +Fair value +of derivatives +18,424,400 +6,716,400 +Other +accrued expenses +4,140,500 +2,286,800 +Advances +for future drilling contracts +49,999,400 +42,497,300 +Federal and +state income taxes payable +8,473,200 +- +Funds +held for future distribution +18,346,300 +12,911,800 +Total +current liabilities +194,532,400 +125,105,700 +Long-term debt +24,000,000 +21,000,000 +Other +liabilities +7,115,500 +3,927,500 +Deferred +income taxes +26,888,500 +22,976,300 +Asset +retirement obligation +8,283,200 +7,998,200 +Total +liabilities +260,819,600 +181,007,700 +Commitments +and contingencies (Note 10) +Stockholders' +equity: +Common +stock, par value $.01 per share; +authorized +50,000,000 shares; issued and +outstanding +16,281,923 and 16,589,824 shares +162,800 +165,800 +Additional +paid-in capital +30,422,900 +37,684,300 +Retained +earnings +158,504,200 +117,052,500 +Unamortized +stock award +(824,600) +(882,000) +Total +stockholders' equity +188,265,300 +154,020,600 +Total +Liabilities and Stockholders' Equity +$ +449,084,900 +$ 335,028,300 +See accompanying Notes to Consolidated +Financial Statements. +F-4 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Consolidated Balance +Sheets +December 31, 2005 and 2004 +2005 +2004 +2003 +(Restated) +(Restated) +Revenues: +Oil +and gas well drilling operations +$ 99,962,900 +$ 94,076,000 +$ 57,509,600 +Gas +sales from marketing activities +121,104,100 +94,626,800 +73,131,700 +Oil +and gas sales +102,559,200 +69,492,100 +48,393,800 +Well +operations and pipeline income +8,759,600 +7,676,900 +6,907,100 +Other +income +10,747,300 +1,880,700 +3,528,500 +Total +revenues +343,133,100 +267,752,500 +189,470,700 +Costs and +expenses: +Cost +of oil and gas well drilling operations +88,184,900 +77,696,200 +46,945,900 +Cost +of gas marketing activities +119,643,700 +92,881,200 +72,361,400 +Oil +and gas production and well operations costs +19,934,700 +17,277,200 +13,251,300 +Exploratory +dry hole costs +11,115,100 +- +- +General +and administrative expenses +6,960,300 +4,505,600 +4,974,400 +Depreciation, +depletion and amortization +21,116,200 +18,155,900 +15,312,800 +Total +costs and expenses +266,954,900 +210,516,100 +152,845,800 +Income +from operations +76,178,200 +57,236,400 +36,624,900 +Interest +expense +682,300 +673,700 +1,195,300 +Oil +and gas price risk management loss, net +9,368,100 +3,084,600 +812,400 +Income +before income taxes and cumulative +effect +of change in accounting principle +66,127,800 +53,478,100 +34,617,200 +Income taxes +24,676,100 +20,250,500 +11,933,500 +Net +income before cumulative effect of +change +in accounting principle +41,451,700 +33,227,600 +22,683,700 +Cumulative +effect of change in accounting +principle (net +of taxes of $1,392,000) +- +- +(2,271,300) +Net income +$ 41,451,700 +$ 33,227,600 +$ 20,412,400 +Basic earnings +per common share before +accounting +change +$ +2.53 +$ +2.05 +$ +1.45 +Cumulative +effect of change in accounting +principle +- +- +$ +(0.15) +Basic earnings +per common share +$ +2.53 +$ +2.05 +$ +1.30 +Diluted +earnings per share before accounting +change +$ +2.52 +$ +2.00 +$ +1.39 +Cumulative +effect of change in accounting +principle +- +- +$ +(0.14) +Diluted +earnings per common and common +equivalent +share +$ +2.52 +$ +2.00 +$ +1.25 +See accompanying Notes to Consolidated Financial Statements. +F-5 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Consolidated +Statements of Stockholders' Equity +Years Ended December 31, 2005, 2004, and 2003 +Common Stock Issued +Treasury Stock +Number of +Additional +Retained +at Cost +Unamortized +Shares +Amount +Paid-In-Capital +Earnings +(Restated) +Stock Award +Total +Balance, December 31, 2002 +15,734,767 +$ 157,300 +$ 29,340,500 +$ 63,412,500 +$ - +$ (23,700) +$ 92,886,600 +Amortization of stock award +- +- +- +- +- +8,900 +8,900 +Repurchase of treasury stock +- +- +- +- +(748,700) +- +(748,700) +Treasury stock retirement +(106,334) +(1,100) +(747,600) +- +748,700 +- +- +Net income +- +- +- +20,412,400 +- +- +20,412,400 +Balance, December 31, 2003 +15,628,433 +156,200 +28,592,900 +83,824,900 +- +(14,800) +112,559,200 +Issuance of common stock +Exercise of employee stock +options +1,100,000 +11,000 +4,981,700 +- +- +- +4,992,700 +Stock award +23,380 +200 +870,700 +- +- +(870,900) +- +Amortization of stock award +- +- +- +- +- +3,700 +3,700 +Repurchase of treasury stock +- +- +- +- +(4,157,400) +- +(4,157,400) +Treasury stock retirement +(161,989) +(1,600) +(4,155,800) +- +4,157,400 +- +- +Income tax benefit from the exercise of stock +options +- +- +7,394,800 +- +- +- +7,394,800 +Net income +- +- +- +33,227,600 +- +- +33,227,600 +Balance, December 31, 2004 +16,589,824 +165,800 +37,684,300 +117,052,500 +- +(882,000) +154,020,600 +Issuance of common stock +Exercise of employee stock +options +3,000 +100 +11,500 +- +- +- +11,600 +Stock award +20,895 +200 +602,600 +- +- +(602,800) +- +Amortization of stock award +- +- +- +- +- +660,200 +660,200 +Repurchase of treasury stock +- +- +- +- +(7,878,800) +- +(7,878,800) +Treasury stock retirement +(331,796) +(3,300) +(7,875,500) +- +7,878,800 +Net income +- +- +- +41,451,700 +- +- +41,451,700 +Balance, December 31, 2005 +16,281,923 +$ 162,800 +$ 30,422,900 +$ 158,504,200 +$ - +$ (824,600) +$188,265,300 +See accompanying +Notes to Consolidated Financial Statements. +F-6 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Consolidated +Statements of Cash Flows +Years Ended December 31, 2005, 2004, and 2003 +Cash flows +from operating activities: +2005 +2004 +2003 +Net +income +$41,451,700 +$33,227,600 +$20,412,400 +Adjustment +to reconcile net income to cash provided +by +operating activities: +Deferred +income taxes +3,350,600 +9,887,300 +8,462,300 +Depreciation, +depletion and amortization +21,116,200 +18,155,900 +15,312,800 +Accretion +of asset retirement obligation +465,200 +436,000 +379,200 +Exploratory +dry hole costs +11,115,100 +- +- +Unrealized +loss (gain) on derivative transactions +3,225,900 +535,200 +(1,110,200) +Cumulative +effect of change in accounting principle +- +- +2,271,300 +Gain +from sale of assets +(7,875,800) +(32,000) +(202,500) +Expired +and abandoned leases +47,600 +300,800 +1,383,000 +Amortization +of stock award +660,200 +3,700 +8,900 +Change in +assets and liabilities: +Increase in accounts receivable +(11,276,400) +(10,492,600) +(7,197,800) +(Increase) +decrease in accounts receivable affiliates +(5,003,200) +(343,200) +10,700 +(Increase) decrease in restricted cash +(835,700) +1,201,500 +894,100 +(Increase) decrease in inventories +(3,397,600) +357,000 +(1,383,600) +Decrease (increase) in other current assets +3,482,100 +4,776,200 +(1,095,900) +(Increase) decrease in other assets +(651,600) +(48,800) +1,696,200 +Increase +in production tax liability +12,634,000 +8,441,100 +3,974,800 +Increase in accounts payable and accrued expenses +22,453,500 +10,355,800 +13,018,300 +Increase (decrease) in advances for future drilling +contracts +7,502,100 +(7,961,500) +13,175,000 +Increase +in federal and state income taxes payable +8,473,200 +- +- +Increase in funds held for future distribution +5,434,500 +4,500,900 +4,493,000 +Total +adjustments +70,919,900 +40,073,300 +54,089,600 +Net +cash provided by operating activities +112,371,600 +73,300,900 +74,502,000 +Cash flows +from investing activities: +Capital +expenditures +(106,468,500) +(45,391,800) +(73,042,300) +Proceeds from sale of leases to partnerships +2,829,200 +1,950,900 +1,382,100 +Proceeds +from sale of fixed assets +9,597,600 +94,700 +156,800 +Net +cash used in investing activities +(94,041,700) +(43,346,200) +(71,503,400) +Cash flows +from financing activities: +Proceeds +from debt +91,000,000 +84,000,000 +86,600,000 +Retirement +of debt +(88,000,000) +(116,000,000) +(58,600,000) +Payment of +debt issue costs +(423,000) +(232,500) +- +Proceeds +from issuance of stock +11,600 +3,584,400 +- +Repurchase +of treasury stock +(7,878,800) +(2,749,100) +(748,700) +Net +cash (used in) provided from financing activities +(5,290,200) +(31,397,200) +27,251,300 +Net +increase (decrease) in cash and cash equivalents +13,039,700 +(1,442,500) +30,249,900 +Cash +and cash equivalents, beginning of year +77,070,400 +78,512,900 +48,263,000 +Cash and +cash equivalents, end of year +$ 90,110,100 +$ 77,070,400 +$ 78,512,900 +See accompanying +Notes to Consolidated Financial Statements. +F-7 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +Years Ended December 31, 2005, 2004 and 2003 +(1) Summary +of Significant Accounting Policies +General +Petroleum +Development Corporation (PDC or the Company) is an independent energy company +engaged primarily in the drilling and development, production and marketing of +natural gas and oil. Since it began oil and gas operations in 1969, the Company +has grown primarily through drilling and development activities, the +acquisition of producing natural gas and oil wells and the expansion of its +natural gas marketing activities. As of December 31, 2005, the Company operates approximately 2,800 wells located in the Appalachian Basin, Michigan, and the +Rocky Mountain Region. Substantially all of the Company's oil and gas wells are +located in West Virginia, Tennessee, Pennsylvania, Michigan, North Dakota, +Colorado and Kansas. The Company is involved in four business segments. The +segments are drilling and development, natural gas marketing, oil and gas sales +and well operations. (See Note 20) +Principles +of Consolidation +The accompanying consolidated financial +statements include the accounts of Petroleum Development Corporation (PDC) and its wholly owned subsidiaries, Riley +Natural Gas (RNG) and PDC Securities +Incorporated. All material intercompany accounts and transactions have been +eliminated in consolidation. The Company accounts for its investment in +interests in oil and gas limited partnerships under the proportionate +consolidation method. Under this method, the Company's financial statements +include its pro rata share of assets, liabilities and revenues and expenses +respectively of the limited partnerships in which it participates. The +Company's proportionate share of all significant transactions between the +Company and the limited partnerships is eliminated. +Cash +Equivalents +For +purposes of the statement of cash flows, the Company considers all highly +liquid debt instruments with original maturities of three months or less to be +cash equivalents. +Restricted +Cash +The +Company is required to maintain margin deposits with brokers for outstanding +derivative contracts. As of December 31, 2005 and 2004, cash in the amount of $1,500,600 and $664,900, respectively was on deposit. +Inventories +Inventories +consist primarily of tubular goods and other well equipment, parts and supplies +which are valued at the lower of average cost or market. An inventory of +natural gas is recorded when gas is purchased, through RNG activities, in +excess of deliveries to customers and is recorded at the lower of cost or +market. +Oil +and Gas Properties +The +Company accounts for its oil and gas properties under the successful efforts +method of accounting. Costs of proved developed producing properties, +successful exploratory wells and development dry hole costs are depreciated or +depleted by the unit-of-production method based on estimated proved developed +producing oil and gas reserves. Property acquisition costs are depreciated or +depleted on the unit-of-production method based on estimated proved oil and gas +reserves. The Company obtains new reserve reports from independent petroleum +engineers annually as of December 31st of each year. The Company adjusts oil +and gas reserves for any major acquisitions, new drilling and divestitures +during the year as needed. +F-8 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +Exploration +costs, including geological and geophysical expenses and delay rentals, are +charged to expense as incurred. Exploratory well drilling costs, including the +cost of stratigraphic test wells, are initially capitalized but charged to +expense if the well is determined to be nonproductive. The status of each +in-progress well is reviewed quarterly to determine the proper accounting +treatment under the successful efforts method of accounting. Exploratory well +costs continue to be capitalized as long as the well has found a sufficient +quantity of reserves to justify its completion as a producing well and the +Company is making sufficient progress assessing its reserves and economic and +operating viability. If an in-progress exploratory well is found to be +unsuccessful (referred to as a dry hole) prior to the issuance of our financial +statements, the costs are expensed to exploratory dry hole costs. If we are +unable to make a final determination about the productive status of a well +prior to issuance of our financial statements, the well is classified as +"Suspended Well Costs" until we have had sufficient time to conduct additional +completion or testing operations to evaluate the pertinent geological and +engineering data obtained. At the time when we are able to make a final +determination of a well's productive status, the well is removed from the +suspended well status and the proper accounting treatment is recorded. The +determination of an exploratory well's ability to produce is made within one +year from the completion of drilling activities. See Note 16. +The +acquisition costs of unproved properties are capitalized when incurred, until such +properties are transferred to proved properties or charged to expense when +expired, impaired or amortized. Unproved oil and gas properties with +individually significant acquisition costs are periodically assessed, and any +impairment in value is charged to expense. The amount of impairment recognized +on unproved properties which are not individually significant is determined by +amortizing the costs of such properties within appropriate fields based on the +Company's historical experience, acquisition dates and average lease terms. +Amortization of remaining lease costs for all other insignificant properties is +recorded over the average remaining lives of the leases. The valuation of +unproved properties is subjective and requires management of the Company to +make estimates and assumptions which, with the passage of time, may prove to be +materially different from actual realizable values. +Upon +sale or retirement of significant portions of or complete fields of depreciable +or depletable property, the book value thereof, less proceeds or salvage value, +is credited or charged to income. Upon sale of individual wells, the proceeds +are credited to property costs. +The +Company assesses impairment of capitalized costs of proved oil and gas +properties by comparing net capitalized costs to estimated undiscounted future +net cash flows on a field-by-field basis using estimated production based upon +prices at which management reasonably estimates such products to be sold. These +estimates of future product prices may differ from current market prices of oil +and gas. Any downward revisions to management's estimates of future production +or product prices could result in an impairment of the Company's oil and gas +properties in subsequent periods. If net capitalized costs exceed undiscounted +future net cash flows, the measurement of impairment is based on estimated fair +value which would consider future discounted cash flows. +Transportation +Equipment, Pipelines and Other Equipment +Transportation +equipment, pipelines and other equipment are carried at cost. Depreciation is +provided principally on the straight-line method over useful lives of 3 to 17 +years. The Company adopted FASB Statement No. 144 "Accounting for the +Impairment or Disposal of Long-Lived Assets" on January 1, 2002. The adoption of FASB No. 144 did not affect the Company's financial statements. +In +accordance with FASB Statement No. 144, long-lived assets, such as property, +plant, and equipment, are reviewed for impairment whenever events or changes in +circumstances indicate that the carrying amount of an asset may not be +recoverable. Recoverability of assets to be held and used is measured by a +comparison of the carrying amount of an asset to estimated undiscounted future +cash flows expected to be generated by the asset. If the carrying amount of an +asset exceeds its estimated future cash flows, an impairment charge is +recognized in the amount by which the carrying amount of the asset exceeds the +fair value of the asset. +F-9 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +Maintenance +and repairs are charged to expense as incurred. Major renewals and betterments +are capitalized. Upon the sale or other disposition of assets, the cost and +related accumulated depreciation, depletion and amortization are removed from +the accounts, the proceeds applied thereto and any resulting gain or loss is +reflected in income. +Buildings +Buildings +are carried at cost and depreciated on the straight-line method over estimated useful +lives of 30 years. +Asset +Retirement Obligations +The +Company accounts for asset retirement obligations by recording the fair value +of its plugging and abandonment obligations when incurred, which is at the time +the well is completely drilled. Upon initial recognition of an asset retirement +obligation, the Company increases the carrying amount of the long-lived asset +by the same amount as the liability. Over time, the liabilities are accreted +for the change in their present value, through charges to Interest expense. The +initial capitalized costs are depleted over the useful lives of the related +assets, through charges to depreciation, depletion and amortization. See Note 5 +for a reconciliation of asset retirement obligation activity. +Advances +for Future Drilling Contracts +Advances +for future drilling contracts represents funds received from Partnerships and +other joint ventures for drilling activities which have not been completed and +accordingly have not yet been recognized as revenue in accordance with the +Company's revenue recognition policies. +Retirement +Plans +The +Company has a 401-K contributory retirement plan (401-K Plan) covering +full-time employees. The Company provides a discretionary matching of employee +contributions to the plan. +The +Company has a profit sharing plan covering full-time employees. The Company's +contributions to this plan are discretionary. +The +Company has a deferred compensation arrangement covering executive officers of +the Company as a supplemental retirement benefit. +Revenue +Recognition +The +Company's drilling segment recognizes revenue from our drilling contracts with +our sponsored drilling programs using the percentage of completion method. +These contracts include the sale of equipment and the providing of services at +footage rates and are completed within nine to twelve months after the +commencement of drilling. The Company provides geological, engineering, and +drilling supervision on the drilling and completion process and uses +subcontractors to perform drilling and completion services. Revenues are +recognized under the percentage of completion method based upon the percentage +of contract costs incurred to date to the estimated total contract costs for +each contract. The Company utilizes this method because reasonably dependable +estimates of the total estimated costs can be made. Because the revenue +recognized depends on estimates of the final contract costs, which are assessed +continually during the term of the contract, recognized revenues are subject to +revisions as the contract progresses. Anticipated losses, if any, on +uncompleted contracts would be recorded at the time that our estimated costs +exceeded the contract revenue. In the fourth quarter of 2005, the Company +recorded a loss of $800,000 on uncompleted drilling contracts as cost of oil +and gas well drilling operations with the related liability recorded in other +accrued expenses in the accompanying consolidated balance sheet. The Company +did not experience any contract losses in 2004 or 2003. +Natural gas marketing is +recorded on the gross accounting method. RNG, our marketing subsidiary, +purchases gas from many small producers and bundles the gas together to sell in +larger amounts to purchasers of natural gas for a price advantage. RNG has latitude +in establishing price and discretion in supplier and purchaser selection. +Natural gas marketing revenues and expenses reflect the full cost and revenue +of those transactions because RNG takes title to the gas it purchases from the +various producers and bears the risks and rewards of that ownership. Both the +realized and unrealized portions of the RNG commodity based derivative +transactions for natural gas marketing activities are included in gas sales +from marketing activities or cost of gas marketing activities, as applicable. +F-10 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +Sales of natural gas are +recognized when natural gas has been delivered to a custody transfer point, +persuasive evidence of a sales arrangement exists, the rights and +responsibility of ownership pass to the purchaser upon delivery, collection of +revenue from the sale is reasonably assured and the sales price is fixed or +determinable. Natural gas is sold by the Company under contracts with terms +ranging from one month to three years. Virtually all of the Company's +contracts pricing provisions are tied to a market index, with certain +adjustments based on, among other factors, whether a well delivers to a +gathering or transmission line, quality of natural gas and prevailing supply +and demand conditions, so that the price of the natural gas fluctuates to +remain competitive with other available natural gas supplies. As a result, the +Company's revenues from the sale of natural gas will suffer if market prices +decline and benefit if they increase. The Company believes that the pricing +provisions of its natural gas contracts are customary in the industry. +The Company currently uses +the "Net-Back" method of accounting for transportation arrangements of our +natural gas sales. The Company sells gas at the wellhead and collects a price +and recognizes revenues based on the wellhead sales price since transportation +costs downstream of the wellhead are incurred by our customers and reflected in +the wellhead price. +Sales of oil are recognized +when persuasive evidence of a sales arrangement exists, the oil is verified as +produced and is delivered in a stock tank, collection of revenue from the sale +is reasonably assured and the sales price is determinable. The Company is +currently able to sell all the oil that it can produce under existing sales +contracts with petroleum refiners and marketers. The Company does not refine +any of its oil production. The Company's crude oil production is sold to +purchasers at or near the Company's wells under short-term purchase contracts +at prices and in accordance with arrangements that are customary in the oil +industry. +Well operations and +pipeline income is recognized when persuasive evidence of an arrangement +exists, services have been rendered, collection of revenues is reasonably +assured and the sales price is fixed or determinable. The Company is paid a +monthly operating fee for each well it operates for outside owners including +the limited partnerships sponsored by the Company. The fee covers monthly +operating and accounting costs, insurance and other recurring costs. The +Company may also receive additional compensation for special non-recurring +activities, such as reworks and recompletions. +Income +Taxes +Income +taxes are accounted for under the asset and liability method. +Deferred +tax assets and liabilities are recognized for the future tax consequences +attributable to differences between the financial statement carrying amounts of +existing assets and liabilities and their respective tax bases. Deferred tax +assets and liabilities are measured using enacted tax rates expected to apply +to taxable income in the years in which those temporary differences are +expected to be recovered or settled. The effect on deferred tax assets and +liabilities of a change in tax rates is recognized in income in the period that +includes the enactment date. +Derivative +Financial Instruments +The +Company accounts for derivative financial instruments in accordance with FAS +Statement No. 133 "Accounting for Derivative Instruments and Certain Hedging +Activities" as amended. +During +2005, 2004, and 2003, none of the derivative contracts qualified for hedge +accounting under the terms of FAS No. 133. Accordingly, the derivative +instruments are recorded as an asset or liability on the balance sheet at fair +value and the change in the fair value is recorded in oil and gas price risk +management, net for the Company's oil and gas commodities (derivatives related +to the Company's production only), in gas sales from marketing activities for +RNG's gas sales, in cost of gas marketing activities for RNG's gas purchases +and in interest expense for the Company's interest rate swap (2004 and 2003 +only). See Note 13. +In the +accompanying balance sheet, the Company records the fair value of derivatives +entered into on behalf of the affiliated partnerships and records an offsetting +receivable or payable with the partnerships. See Note 9. +F-11 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +Stock +Compensation +The +Company applies the intrinsic-value based method of accounting prescribed by +Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued +to Employees", and related interpretations including FASB Interpretation No. +44, "Accounting for Certain Transactions involving Stock Compensation, an +interpretation of APB Opinion No. 25", to account for its fixed-plan stock +options. Under this method, compensation expense is recorded on the date of +grant only if the current market price of the underlying stock exceeded the +exercise price. FASB Statement No. 123, "Accounting for Stock-Based +Compensation" and FASB Statement No. 148, "Accounting for Stock Based +Compensation-Transition and Disclosure, an amendment of FASB Statement No. +123", established accounting and disclosure requirements using a +fair-value-based method of accounting for stock-based employee compensation +plans. As permitted by existing accounting standards, the Company has elected +to continue to apply the intrinsic-value-based method of accounting described +above, and has adopted only the disclosure requirements of Statement 123, as +amended. If the fair-value-based method had been applied to all outstanding +and awards in each period, the impact in 2005 and 2004 would have been an +additional expense of $94,700 and $18,400, respectively. There would have been +no impact on reported net income in 2003. +Year Ended December 31, +2005 +2004 +Net income, as +reported +$ +41,451,700 +$ +33,227,600 +Stock-based +employee compensation +expenses +included in reported net +income, net +of related tax effects +413,900 +2,400 +Deduct total +stock-based employee +compensation +expense determined +under +fair-value based method +for all +awards, net of tax +(508,600) +(20,800) +Pro forma net +income +$ +41,357,000 +$ +33,209,200 +Basic earnings +per share as reported +$2.53 +$2.05 +Pro forma +basic earnings per share +$2.53 +$2.05 +Diluted +earnings per share as reported +$2.52 +$2.00 +Pro forma +diluted earnings per share +$2.52 +$2.00 +Compensation +expense for stock options is measured as the excess, if any, of the quoted +market price of the Company stock at the date of the grant over the amount an +optionee must pay to acquire the stock. The Company records compensation +expense for restricted stock awards based on the quoted market price of the +Company's stock at the date of grant and recognizes the cost over the vesting +period. +The +pro forma amounts that would have been reported if FAS No. 123 had been in +effect for all years are based on the fair value of the stock-based awards +granted for each year and recognized over the vesting period. +The +fair value at date of grant for a common stock option granted under Company's +option plan during 2004 was $16.75. There were no common stock options granted +during 2005 or 2003. The fair value of each option granted during 2004 was +estimated on the date of grant using the Black-Scholes option-pricing model +with the following weighted-average assumptions. +F-12 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +Dividend yield +0% +Expected volatility +39.71% +Risk-free interest +rate +4.06% +Expected option +life +(in years) +7.0 +As of December 31, 2005, there was approximately $131,700 of unrecognized, pre-tax compensation +cost related to non-vested stock options. This cost is expected to be +recognized over three years. The Company will adopt the provisions of FASB +Statement No. 123R (revised 2004), "Accounting for Share Based Payments," +effective January 1, 2006 regarding stock compensation as discussed above. Upon +adoption of FASB Statement No. 123R, the fair value of share based awards will +be recognized directly in our consolidated statements of income. +Use +of Estimates +Management +of the Company has made a number of estimates and assumptions relating to the +reporting of assets and liabilities and revenues and expenses and the +disclosure of contingent assets and liabilities to prepare these financial +statements in conformity with generally accepted accounting principles. Actual +results could differ from those estimates. Estimates which are particularly +significant to the consolidated financial statements include estimates of oil +and gas reserves and future cash flows from oil and gas properties. +Fair +Value of Financial Instruments +The +carrying values of the Company's receivables, payables and debt obligations are +estimated to be substantially the same as the fair values as of December 31, 2005, 2004 and 2003. +Reclassifications +Certain +reclassifications of prior year financial statement amounts have been made to +conform to current year presentations. The fair value of derivatives of +$3,266,100 and $6,716,400 were broken out from other current assets and other +accrued expenses, respectively as of December 31, 2004 in the accompanying +consolidated balance sheets. The decrease in restricted cash for the years +ended 2004 and 2003 was reclassified from cash flows from investing activities +to cash flows from operating activities and the proceeds from the retirement of +debt are shown gross instead of net for the years ended 2004 and 2003 in the +accompanying consolidated statements of cash flows. There are certain +reclassifications in the tax rate reconciliation for 2004 and the 2003 deferred +tax asset related to asset retirement obligations and the deferred tax +liability related to properties and equipment were both grossed-up by +approximately $1.4 million. See footnote 4. The oil and gas capitalized costs +as of December 31, 2004 were reclassified from intangible well equipment, +intangible drilling costs, undeveloped properties and capitalized asset +retirement costs to proved oil and gas properties and unproved oil and gas +properties to comply with required disclosures per FASB Statement No. 69. See +footnote 16. Expenditures for segment long-lived assets of $4,583,000 and +$6,168,000 in 2004 and 2003, respectively were reclassified from the drilling +and development segment to the oil and gas sales segment. See footnote 20. +Recently +Adopted Accounting Standards +The +FASB issued FIN 46R, "Consolidation of Variable Interest Entities", +in January 2003 and amended the interpretation in December 2003. A variable +interest entity (VIE) is an entity in which its voting equity investors lack +the characteristics of having a controlling financial interest or where the +existing capital at risk is insufficient to permit the entity to finance its +activities without receiving additional financial support from other parties. +FIN 46R requires the consolidation of entities which are determined to be VIEs +where the reporting company determines itself to be the primary beneficiary +(the entity that will absorb a majority of the VIE's expected losses, receive a +majority of the VIE's residual return, or both). The amended interpretation +was effective for the first interim annual reporting period ending after March 15, 2004, with the exception of special purpose entities for which the statement was +effective for periods ending after December 15, 2003. We have completed a review of our partnership investments and have determined that the partnerships +are not VIEs. +F-13 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +In +June 2005, the EITF reached a consensus on EITF Issue No. 04-5, "Determining +Whether a General Partner, or the General Partners as a Group, Controls a +Limited Partnership or Similar Entity When the Limited Partners Have Certain +Rights". This consensus applies to voting right entities not within the +scope of FASB Interpretation No. 46R, "Consolidation of Variable Interest +Entities", in which the investor is the general partner in a limited +partnership or functional equivalent. The EITF consensus is that the general +partner in a limited partnership is presumed to control that limited +partnership regardless of the extent of the general partner's ownership +interest and, therefore, should include the limited partnership in its +consolidated financial statements unless the limited partners have substantive +participating or kick-out rights. The EITF provided that the presumption may be +overcome if the limited partners possess certain substantive kick-out rights or +participation rights. Pursuant to the partnership agreements which govern the +limited partnerships sponsored by the Company, the presumption of control by +the Company, the general partner, is overcome because the investor partners +have substantive ability to dissolve (liquidate) the limited partnership or +otherwise remove the general partner through substantive kick-out rights that +can be exercised by a vote of simple majority of the investor partner units not +held by the general partners without having to show cause. As a result, the +partnership interests of the Company continue to be proportionately +consolidated as disclosed above. +On April 4, 2005, the FASB issued FASB Staff Position (FSP) FAS 19-1 "Accounting for +Suspended Well Costs." This staff position amends FASB Statement No. 19 +"Financial Accounting and Reporting by Oil and Gas Producing Companies" and +provides guidance about exploratory well costs to companies which use the +successful efforts method of accounting. The Position states that exploratory +well costs should continue to be capitalized if: 1) a sufficient quantity of +reserves are discovered in the well to justify its completion as a producing +well and 2) sufficient progress is made in assessing the reserves and the +well's economic and operating feasibility. If the exploratory well costs do +not meet both of these criteria, these costs should be expensed, net of any +salvage value. Additional annual disclosures are required to provide +information about management's evaluation of capitalized exploratory well +costs. In addition, the FSP requires annual disclosure of: 1) net changes from +period to period of capitalized exploratory well costs for wells that are +pending the determination of proved reserves, 2) the amount of exploratory well +costs that have been capitalized for a period greater than one year after the +completion of drilling and 3) an aging of exploratory well costs suspended for +greater than one year with the number of wells it related to. Further, the +disclosures should describe the activities undertaken to evaluate the reserves +and the projects, the information still required to classify the associated +reserves as proved and the estimated timing for completing the evaluation. The +Company adopted FAS 19-1 during the third quarter of 2005. See Note 16. The +application of this FSP did not have a significant impact on the Company's +financial position or results of operations. +Recently +Issued Accounting Standards +On December 16, 2004, +the FASB issued SFAS No. 123(R) "Accounting for Share Based +Payments" and has issued several subsequent Staff Positions clarifying +this guidance. This guidance replaced previously existing requirements +under SFAS No. 123 and APB No. 25. Under SFAS No. 123(R), +an entity must recognize the compensation cost related to employee services +received in exchange for all forms of share-based payments to employees, +including employee stock options, as an expense in its income statement. +The compensation cost of the award would generally be measured based on the +grant-date fair value of the award. The Company will be required to adopt +SFAS No. 123(R) in the first quarter of 2006. The Company intends to +use the modified prospective method for adoption of SFAS No. 123(R) as +permitted by the guidance. +The Company has determined +that the impact of SFAS No. 123(R) and related guidance will not be +material to its financial statements. In accordance with SFAS +No. 123, the Company has historically disclosed the impact on the +Company's net income and earnings per share had the fair value based method +been adopted. Had the Company adopted SFAS No. 123(R) in prior periods, +the impact of that standard on periods presented in these Consolidated +Financial Statements would have approximated the impact of SFAS No. 123 as +described in the disclosure of pro forma net income and earnings per share +presented earlier in Note 1. +In +December 2004, the FASB issued SFAS 153, "Exchange of Nonmonetary Assets ", +an amendment of APB Opinion 29, "Accounting for Nonmonetary +Transactions ". This amendment eliminates the exception for +nonmonetary exchanges of similar productive assets and replaces it with a general +exception for exchanges of nonmonetary assets that do not have commercial +substance. Under SFAS 153, if a nonmonetary exchange of similar productive +assets meets a commercial-substance criterion and fair value is determinable, +the transaction must be accounted for at fair value resulting in recognition of +any gain or loss. This statement is effective for nonmonetary transactions in +fiscal periods that begin after June 15, 2005. The adoption of SFAS No. 153 will not have a material impact on our results of operations or financial +position. +F-14 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +In +June 2005, the FASB issued SFAS No. 154, "Accounting Changes and Error +Corrections" - a replacement of APB Opinion No. 20 and FASB Statement No. +3, which replaces Accounting Principles Board Opinion No. 20, "Accounting +Changes", and SFAS No. 3, "Reporting Accounting Changes in Interim +Financial Statements", and changes the requirements for the accounting for +and reporting of a change in accounting principle. SFAS No. 154 requires +retrospective application for voluntary changes in accounting principle unless +it is impracticable to do so, and it applies to all voluntary changes in +accounting principle. It also applies to changes required by an accounting +pronouncement in the unusual instance that the pronouncement does not include +specific transition provisions. When a pronouncement includes specific +transition provisions, those provisions should be followed. SFAS No. 154 is +effective for accounting changes and corrections of errors made in fiscal years +beginning after December 15, 2005. Consequently, we will adopt the provisions +of SFAS 154 for our fiscal year beginning January 1, 2006. We currently believe that adoption of the provisions of SFAS No. 154 in 2006 will not have a material +impact on our consolidated financial statements. +(2) Accounts +Receivable +The +allowance for doubtful accounts receivable is determined based on the Company's +historical write-off experience and is the Company's best estimate of the +amount of probable credit losses in the Company's existing accounts receivable. +Included in other assets are noncurrent accounts receivable as of December 31, 2005 and 2004, in the amounts of $382,200 and $608,500 net of an allowance +for doubtful accounts of $161,400 and $244,400, respectively. +The +allowance for doubtful current accounts receivable as of December 31, 2005 and 2004 was $247,600 and $164,600, respectively. +(3) Long-Term +Debt +The +Company has a credit facility with J. P. Morgan Chase Bank, NA (formerly Bank +One, NA) and BNP Paribas of $200 million subject to and secured by required +levels of oil and gas reserves. The current borrowing base, based upon current +oil and gas reserves, is $125 million of which the Company has activated $80 +million of the facility. The Company is required to pay a commitment fee of +0.25 to 0.375 percent per annum on the unused portion of the activated credit +facility. Interest accrues at prime, with LIBOR (London Interbank Market Rate) +alternatives available at the discretion of the Company. No principal payments +are required until the credit agreement expires on November 4, 2010. +As of December 31, 2005 and 2004 the outstanding balance was $24,000,000 and $21,000,000, +respectively. Any amounts outstanding under the credit facility are secured by +substantially all properties of the Company. The credit agreement requires, +among other things, the existence of satisfactory levels of natural gas reserves, +maintenance of certain working capital and tangible net worth ratios along with +a restriction on the payment of dividends. At December 31, 2005, the outstanding balance was subject to a prime interest rate of 7.25%. As of the filing of +this Form 10-K, the Company was in compliance with all covenants in the credit +agreement, except for timely filing of this December 31, 2005 Form 10-K. The Company has received bank waivers to extend the due date of the December 31, 2005 consolidated financial statements until May 31, 2006, and the due date +of the March 31, 2006 consolidated financial statements until June 15, 2006. +(4) Income +Taxes +The +Company's provision for income taxes consisted of the following: +2005 +2004 +2003 +Current: +Federal +$ 17,893,900 +$ 8,649,900 +$ 2,600,700 +State +3,431,600 +1,713,300 +870,500 +Total +current income taxes +21,325,500 +10,363,200 +3,471,200 +Deferred: +Federal +2,833,800 +8,429,700 +7,429,800 +State +516,800 +1,457,600 +1,032,500 +Total +deferred income taxes +3,350,600 +9,887,300 +8,462,300 +Total +income taxes +$ 24,676,100 +$ 20,250,500 +$ 11,933,500 +F-15 +Income tax expense +differed from the amounts computed by applying the U.S. federal income tax rate +of 35%. +2005 +2004 +2003 +Computed +"expected" tax +$ 23,144,700 +$ 18,717,300 +$ 12,116,000 +State +income tax +2,566,500 +2,061,100 +1,236,900 +Percentage +depletion +(770,900) +(648,600) +(736,000) +Domestic +production activities deduction +(399,400) +- +- +Nonconventional +source fuel credit +- +- +(186,600) +Officers +life insurance +- +- +(350,000) +Surtax +exemption +- +- +(100,000) +Other +135,200 +120,700 +(46,800) +$ 24,676,100 +$ 20,250,500 +$ 11,933,500 +The tax effects +of temporary differences that give rise to significant portions of the deferred +tax assets and deferred tax liabilities at December 31, 2005 and 2004 are presented below. +2005 +2004 +Deferred tax +assets: +Allowance +for doubtful accounts +$ 159,100 +$ 159,100 +Drilling +notes +71,200 +57,200 +Deferred +revenue related to cash withheld +for future +plugging costs +823,800 +725,500 +Deferred +compensation +903,900 +692,100 +Asset +retirement obligations +3,241,600 +3,111,300 +Derivatives +1,561,600 +306,700 +Other +8,300 +21,800 +Total +gross deferred tax assets +6,769,500 +5,073,700 +Less +valuation allowance +- +- +Deferred +tax assets +6,769,500 +5,073,700 +Less +current deferred tax assets +(included +in other current assets) +(1,848,300) +(337,300) +Net +non-current deferred tax assets +4,921,200 +4,736,400 +Deferred tax +liabilities: +Properties +and equipment, principally due to differences in +depreciation and amortization +(31,809,700) +(27,712,700) +Total gross +deferred tax liabilities +(31,809,700) +(27,712,700) +Net +non-current deferred tax liability +$ (26,888,500) +$ (22,976,300) +In +assessing whether a valuation allowance for the deferred tax assets should be +recorded, management considers whether it is more likely than not that some +portion or all of the deferred tax assets will not be realized. The ultimate +realization of deferred tax assets is dependent upon the generation of future +taxable income during the periods in which those temporary differences become +deductible. Based upon the level of historical taxable income and projections +for future taxable income over the periods in which the deferred tax assets are +deductible, management believes it is more likely than not that the Company +will realize the benefits of these deductible differences. The amount of the +deferred tax asset considered realizable, however, could be reduced in the near +term if estimates of future taxable income during the carryforward period are +reduced. +Employee stock +options exercised during the year 2004 resulted in an income tax benefit of +$7,394,800 that is reflected in Stockholders' Equity and as a reduction of +current tax payable. +F-16 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +(5) Asset Retirement +Obligations +Changes in carrying +amounts of the asset retirement obligations associated with our working +interest in oil and gas properties are as follows: +2005 +2004 +2003 +Balance at +beginning of year +$7,998,200 +$7,390,800 +$6,046,200 +Obligations +assumed with development activities +and +acquisitions +301,400 +238,600 +997,200 +Obligations +discharged with disposed properties +and asset +retirements +(445,800) +(67,200) +(31,800) +Revisions to +estimates +14,200 +- +- +Accretion expense +465,200 +436,000 +379,200 +Balance at end +of year +$8,333,200 +$7,998,200 +$7,390,800 +Approximately +$50,000 was classified as short-term and included in other accrued expenses as +of December 31, 2005 and 2004. +If the +fair value of the estimated asset retirement obligation changes, an adjustment +is recorded to both the asset retirement obligation and the asset retirement +cost. +Upon +the adoption of FAS No. 143 effective January 1, 2003, the Company recorded a net asset of $2,382,900 and a related liability of $6,046,200 (using a 5.75% +discount rate) and a cumulative effect of change in accounting principle on +prior years of $2,271,300 (net of taxes of $1,392,000). +(6) Common +Stock +Stock-Based +Compensation Plans +As of December 31, 2005, the Company has stock-based compensation plans for certain employees +and officers. These plans are described below: +The +Company maintains a long-term equity compensation plan for officers and certain +key employees of the Company. Under the plan, approved by the shareholders in +June 2004, awards may be issued in the form of stock options, stock +appreciation rights, restricted stock, or performance shares. A total of +750,000 shares of common stock have been reserved for issuance. These awards +vest over periods set at the discretion of the Compensation Committee of the +Company's Board of Directors and have a maximum exercisable period of ten +years. During 2005 and 2004 the Company granted 14,000 shares and 23,380 +shares, respectively, with restriction periods of four years at the market +price on the date of issuance as deferred compensation to certain officers of +the Company. The related compensation amount is being amortized to expense over +the respective vesting periods and totaled $596,700 and $3,700 for the years +ended December 31, 2005 and 2004, respectively. +The +Company also maintains a restricted stock plan for non-employee directors. A +total of 40,000 shares of common stock have been reserved for issuance under +the plan which was approved by shareholders in June 2005. The stock is subject +to restrictions ending on the earliest of various retirement or termination +dates, including certain provisions for change in control. On July 8, 2005, 6,895 shares were granted at a price of $29.00 per share. Compensation +expense for the year ended December 31, 2005 related to these shares of restricted stock was $63,300. +Options +amounting to 16,880 shares were granted during 2004 to certain officers and +directors under the Company's Stock Option Plan. These options were granted +with an exercise price equal to the market value of the Company's common stock +as of the date of grant and vest over a four year period. The outstanding +options expire in 2014. +F-17 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +The +following table summarizes the activity of the Company's option plans: +Average +Range of +Number +Exercise +Exercise +of Shares +Price +Prices +Outstanding +January 1, 2003 +1,160,000 +$4.48 +$1.125 - 6.25 +Granted +- +- +- +Exercised +- +- +- +Outstanding +December 31, 2003 +1,160,000 +4.48 +1.125 - 6.25 +Granted +16,880 +37.15 +37.15 +Exercised +(1,100,000) +4.48 +1.125-6.25 +Outstanding +December 31, 2004 +76,880 +11.64 +3.875-37.15 +Granted +- +- +- +Exercised +(3,000) +3.88 +3.875 +Outstanding +December 31, 2005 +73,880 +$11.96 +$3.875-37.15 +Options +outstanding under the Company's plans as of December 31, 2005: +Option +Range of +Options +Remaining +Options +Weighted-Average +Grant +Expiration +Vesting +Exercise Price +Outstanding +Life +Exercisable +Exercise Price +Date +Date +Period +$3.875 - $6.25 +57,000 +2.9 years +57,000 +$4.50 +1999 +2009 +Less than 1 +year +$37.15 +16,880 +9 years +4,218 +$37.15 +2004 +2014 +1 to 4 years +Total +73,880 +61,218 +Common +Stock Repurchase +On March 13, 2003, the Company publicly announced the authorization by its Board of Directors +to repurchase up to 5% of the Company's common stock (785,000 shares) at fair +market value at the date of purchase. Under the program, management had +discretion as to the dates of purchase and amounts of stock to be purchased and +whether or not to make purchases. From inception of the program until December 31, 2004, the Company has repurchased 109,200 shares at an average price of $6.86 +for a total purchase price of approximately $749,100. This program expired on December 31, 2004. +In +March 2004, the Compensation Committee of the Board of Directors approved a +repurchase of 48,650 shares of common stock from one of the Company's +officers. The repurchase price of the common stock was the closing price on +the date of the repurchase of $26.61 per share and totaled $1,294,600 which +approximated the tax savings to be realized by the Company as a result of the +exercise of said officer's non-qualified stock options in 2004. The Company +also repurchased 1,703 shares from an employee upon retirement from the Company +in June, 2004 and the treasury stock was subsequently cancelled. +On March 18, 2005, the Company publicly announced the authorization by its Board of Directors +to repurchase up to 2% of the Company's outstanding common stock (331,796 +shares) at fair market value at the date of purchase. At a meeting held June 10, 2005, the Board of Directors of Petroleum Development Corporation approved an +amendment of the size of the stock repurchase from 2% to 10% (1,658,980 shares) +of the Company's then outstanding common stock. Under the program, the Board +has discretion as to the dates of purchase and amounts of stock to be purchased +and whether or not to make purchases. This program expired on December 31, 2005. The following activity has occurred since inception of the plan on March 18, 2005 until December 31, 2005. +Month of Purchase +May, 2005 +Average Price Paid +per Share +$23.75 +Broker/Dealer +McDonald Investments +Number of Shares +Purchased +331,796 +Remaining Number of +Shares to Purchase +1,327,184 +F-18 +On January 13, 2006, the Company publicly announced that +its Board of Directors authorized the repurchase of up to 10% (1,627,500 +shares) of the Company's common stock during 2006. Stock repurchases under this +program may be made in the open market or in private transactions, at times and +in amounts that management deems appropriate. The Company may terminate or +limit the stock repurchase program at any time. The following activity has +occurred since inception of the plan on January 13, 2006 until May 10, 2006. +Month of Purchase +January, 2006 +Average Price Paid +per Share +$39.33 +Broker/Dealer +McDonald +Investments +Number of Shares +Purchased +258,169 +Remaining Number +of Shares to Purchase +1,369,331 +Stock +Repurchase Agreement +The +Company had stock repurchase agreements with four executive officers of the +Company. These agreements were eliminated in December, 2005. The agreements +required the Company to maintain life insurance on each executive in the amount +of $1,000,000. The agreements required the Company to utilize the proceeds +from the insurance to purchase from the executives' estates or heirs, at their +option, shares of the Company's stock in the event of the executive's death. +The purchase price for the outstanding common stock was to be based upon the +average closing asked price for the Company's stock as quoted by NASDAQ on the +date of purchase. The Company is not required to purchase any shares in excess +of the amount provided for by such insurance. During the fourth quarter of +2003, the Company received $1,000,000 in life insurance proceeds which was +recorded as other income from the death of the Company's Chief Financial +Officer who had a stock repurchase agreement. In May 2004, the Company repurchased +50,487 shares of common stock from the estate of the Company's former officer +in accordance with the terms of this agreement. The repurchase price of the +stock was $27.73 per share (the 90-day average prior to the repurchase per +contract). The repurchase totaled $1,400,000 of which $1,000,000 was funded by +the life insurance proceeds. +(7) Employee +Benefit Plans +The +Company sponsors a qualified deferred compensation plan (401-K) that enables +eligible employees to contribute a portion of their compensation through +payroll deductions in accordance with specific guidelines. The Company matches +a percentage of the employees' contributions up to certain limits. Expenses +related to this plan amounted to $450,700, $382,700 and $305,500 for 2005, 2004 +and 2003, respectively. +The +Company has a profit sharing plan covering full-time employees. The Company +contributed $420,000, $300,000, and $250,000 to the plan in cash during 2005, +2004 and 2003, respectively. +During +2003 the Company expensed $90,000 under a deferred compensation arrangement +with certain executive officers of the Company. This amount was paid to the +executive officers during 2003. +The +Company has a deferred compensation arrangement covering certain executive +officers of the Company as a supplemental retirement benefit. During 2005, 2004 +and 2003 the Company expensed $169,000, $171,900 and $181,900, respectively, +and has recorded a related liability in the amount $1,129,200 and $1,000,200 as +of December 31, 2005 and 2004, respectively. The Company began paying the +retirement benefit during 2004 to the estate of one of the Company's former +officers. The Company paid $40,000 for each of the years 2005 and 2004. +The +Company maintains a non-qualified deferred compensation plan created for +non-employee directors of the Company. The amount of compensation deferred by +each Participant is based on Participant elections. +F-19 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +(8) Earnings Per +Share +2005 +2004 +2003 +Basic earnings per common share: +Net income before cumulative effect of +change in +accounting principle +$41,451,700 +$33,227,600 +$22,683,700 +Cumulative effect of accounting change, net +of tax +- +- +(2,271,300) +Net income +$ 41,451,700 +$ 33,227,600 +$ 20,412,400 +Weighted average common shares outstanding +16,361,530 +16,239,454 +15,659,591 +Basic earnings per common share +$ 2.53 +$ 2.05 +$ 1.30 +Diluted earnings per common and common +equivalent share: +Net income before cumulative effect of change in +accounting principle +$41,451,700 +$33,227,600 +$22,683,700 +Cumulative effect +of accounting change, net of tax +- +- +(2,271,300 ) +Net income +applicable to common stock +$ 41,451,700 +$ 33,227,600 +$ 20,412,400 +Weighted average +common shares outstanding +16,361,530 +16,239,454 +15,659,591 +Potentially dilutive securities: Stock options and awards +65,619 +367,177 +638,202 +Weighted average +common and common equivalent +shares outstanding +16,427,149 +16,606,631 +16,297,793 +Diluted earnings per common share +$ 2.52 +$ 2.00 +$ 1.25 +(9) Transactions +with Affiliates +Funds +held for future distribution on the consolidated balance sheets of $18,346,300 +and $12,911,800 primarily represents amounts owed to affiliated partnerships as +of December 31, 2005 and 2004, respectively. +The +Company provided oil and gas well drilling services and well operations and +pipeline services to affiliated partnerships. Substantially all of the +Company's revenue and expenses related to oil and gas well drilling operations +and revenues from well operations and pipeline income are associated with +services provided to the investing partners. Amounts due from the affiliated +partnerships as of December 31, 2005 and 2004 were $7,233,800 and $2,230,600, +respectively and are principally amounts due from the Partnerships related to +derivative positions. +Management +fees collected from the affiliated partnerships amounted to $1.7 million, $1.5 +million and $2.0 million for the years ended December 31, 2005, 2004 and 2003, +respectively, and are included in other income on the accompanying consolidated +statements of income. +Revenues +from oil and gas well drilling operations and costs of oil and gas well +drilling operations each include $218,700, $102,500 and $55,800 during 2005, +2004 and 2003, respectively related to investments made by officers of the +Company in working interests in wells drilled during the respective years. +The +Company through its wholly-owned subsidiary, PDC +Securities Incorporated, acts as Dealer-Manager of the Drilling Partnerships. PDC Securities Incorporated receives the applicable +commissions and marketing allowances from the Escrow Agent of the Drilling +Program and distributes them to the Soliciting Broker/Dealers who sell the +programs. The commissions and marketing allowances received by PDC Securities are included in other income net of +the commissions distributed to the soliciting broker/dealer. The net +commissions and marketing allowance amounts included in other income were less +than $1,000 for each of the years ending December 31, 2005, 2004 and 2003, respectively. The commissions and marketing allowances received by PDC +Securities and distributed to the Soliciting Broker/Dealers amounted to +$11,353,400, $9,747,500 and $7,994,300 for the years ended December 31, 2005, 2004, and 2003, respectively. +F-20 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +During +2005, 2004, and 2003, the Company paid $25,900, $22,500, and $30,000, +respectively, to the Corporate Secretary's law firm for various legal services. +(10) Commitments +and Contingencies +The +nature of the independent oil and gas industry involves a dependence on outside +investor drilling capital and involves a concentration of gas sales to a few +customers. The Company sells natural gas to various public utilities, gas +marketers and industrial customers. No customer accounted for 10% or more of +the Company's total revenues in 2005 or 2004. One customer accounted for 11.1% +of total revenues in 2003. +The +Company would be exposed to natural gas price fluctuations on underlying +purchase and sale contracts should the counterparties to the Company's +derivative instruments or the counterparties to the Company's gas marketing +contracts not perform. Nonperformance is not anticipated. There were no +counterparty default losses in 2005, 2004 or 2003. +Substantially +all of the Company's drilling programs contain a repurchase provision where +Investing Partners may request that the Company purchase their partnership +units at any time beginning with the third anniversary of the first cash +distribution. The provision provides that the Company is obligated to purchase +an aggregate of 10% of the initial subscriptions per calendar year (at a +minimum price of four times the most recent 12 months' cash distributions), if +repurchase is requested by investors, and subject to the Company's financial +ability to do so. The maximum annual repurchase obligation as of December 31, +2005 was approximately $9.2 million. The Company has adequate liquidity to meet +this obligation. During 2005 and 2004, the Company paid $352,000 and $408,300, +respectively, under this provision for the repurchase of partnership units. As +of December 31, 2005, outstanding repurchase offers to investing partners +totaled $256,400. In 2006, $70,700 of such outstanding offers were consummated +prior to their expiration. +The Company's drilling +programs formed since 1996 contain a performance supplement that requires the +Company to remit a payment equal to one-half of its share of revenue from the +partnership to the investing partners if certain levels of performance are not +met. During 2005, 2004, and 2003 the Company paid partnerships a total of +$689,700, $597,300 and $385,400, respectively in accordance with the provision. +As of December 31, 2005 based upon current oil and gas reserve reports of the +Partnerships with this provision, the maximum amount of this contingency is +$4.8 million. +As +Managing General Partner of 75 partnerships the Company has liability for any +potential casualty losses in excess of the partnership assets and insurance. +The Company's management believes the casualty insurance coverage carried by +the Company and its subcontractors is adequate to meet this potential +liability. +In +order to secure the services for drilling rigs, the Company made commitments to +the drilling contractors which call for a minimum commitment of $24,000 daily +for a specified amount of time if the Company ceases to use the drilling rigs, +an event that is not anticipated to occur, and a maximum commitment of $55,400 +daily for a specified amount of time for daily use of the drilling rigs. As of December 31, 2005, commitments for these three separate contracts expire in May of 2008, +July of 2009, and May of 2010. As of December 31, 2005, the Company has an outstanding minimum commitment for $22,524,000, and an outstanding maximum +commitment for $59,627,000. +From +time to time the Company is a party to various legal proceedings in the +ordinary course of business. The Company is not currently a party to any +litigation that it believes would have a materially adverse affect on the +Company's business, financial condition, results of operations, or liquidity. +(11) Lease +Obligations +The +Company has entered into operating leases on behalf of itself and its +Partnerships principally for the leasing of natural gas compressors on its Michigan operating facilities and office printing and copying equipment. The future minimum +lease payments under these non-cancelable operating leases as of December 31, 2005 are as follows: +F-21 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +Year +Lease Amount +2006 +$356,300 +2007 +297,500 +2008 +291,600 +2009 +291,000 +2010 +167,800 +Thereafter +28,000 +$ 1,432,200 +The Company's share +of this lease expense for operating leases for the years ended December 31, 2005, 2004 and 2003 was $313,000, $310,000 and $574,700, respectively. +(12) Supplemental +Disclosure of Cash Flows +The +Company paid $101,300, $1,049,200 and $1,274,003 for interest in 2005, 2004 and +2003, respectively. The Company paid income taxes in 2005, 2004 and 2003 in +the amounts of $10,675,000, $5,027,800 and $3,649,600, respectively. +During 2004, 337,360 +options were exercised by employees exchanging 62,999 mature shares of stock +with a fair value of $1,408,300. All these mature shares were subsequently +cancelled. +(13) Derivative +Financial Instruments +The Company utilizes +commodity based derivative instruments to manage a portion of its exposure to +price risk from its oil and natural gas sales and marketing activities. Company +policy prohibits the use of oil and natural gas future and option contracts for +speculative purposes. These instruments consist of NYMEX-traded natural gas +futures contracts and option contracts for Appalachian and Michigan production, +Panhandle-based contracts traded by BNP Paribas and NYMEX-traded contracts for +NECO production and CIG-based contracts traded by JP Morgan for other Colorado +production. These derivative instruments have the effect of locking in for +specified periods (at predetermined prices or ranges of prices) the prices the +Company will receive for the volume to which the derivative relates and, in the +case of RNG, the cost of gas supplies purchased for marketing activities. As a +result, while these derivatives are structured to reduce the Company's exposure +to changes in price associated with the derivative commodity, they also limit +the benefit the Company might otherwise have received from price changes +associated with the derivative commodity. RNG also enters into fixed-price +physical purchase and sale agreements that are derivative contracts. +The fair value of the +commodity based derivatives was $(9,365,700) and $(2,202,300) at December 31, 2005 and 2004, respectively. The Company recognized in the statement of +income an unrealized gain (loss) on commodity based derivatives of +$(3,225,900), $(1,127,900) and $632,600 for the years ended December 31, 2005, 2004, and 2003, respectively. +The following tables +summarize the open derivative option and purchase and sales contracts for Riley +Natural Gas and the Company as of December 31, 2005 and 2004. +F-22 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +Riley Natural Gas +Open Derivative Positions +Quantity +Weighted +Total Contract +Commodity +Type +Gas-Mmbtu +Average Price +Amount +Fair Value +Total +Positions as of December 31, 2005 +Natural Gas +Cash Settled +Futures/Swaps Purchases +1,025,500 +$ 9.05 +$9,283,010 +$ 1,983,352 +Natural Gas +Cash Settled +Futures/Swaps Sales +3,149,000 +$ 7.95 +$25,018,610 +$ (8,688,840) +Natural Gas +Cash Settled +Basis Swap Purchases +450,000 +$ 0.91 +$409,500 +$ (157,663) +Natural Gas +Cash Settled +Basis Swap Sales +240,000 +$ 0.50 +$120,000 +$ 3,700 +Natural Gas +Physical +Purchases +2,819,000 +$ 8.32 +$23,456,726 +$ 7,858,489 +Natural Gas +Physical Sales +585,222 +$ 10.72 +$6,272,822 +$ (670,419) +Natural Gas +Physical Basis +Purchases +240,000 +$ 0.45 +$108,000 +$ 8,300 +Natural Gas +Physical Basis +Sales +450,000 +$ 0.94 +$420,750 +$ 168,913 +Positions +maturing in 12 months following December 31, 2005 +Natural Gas +Cash Settled +Futures/Swaps Purchases +1,025,500 +$ 9.05 +$9,283,010 +$ 1,983,352 +Natural Gas +Cash Settled +Futures/Swaps Sales +2,709,000 +$ 8.12 +$21,991,390 +$ (7,185,253) +Natural Gas +Cash Settled +Basis Swap Purchases +450,000 +$ 0.91 +$409,500 +$ (157,663) +Natural Gas +Cash Settled +Basis Swap Sales +220,000 +$ 0.50 +$110,000 +$ 4,900 +Natural Gas +Physical +Purchases +2,379,000 +$ 8.71 +$20,717,126 +$ 5,966,998 +Natural Gas +Physical Sales +585,222 +$ 10.72 +$6,272,822 +$ (670,419) +Natural Gas +Physical Basis +Purchases +220,000 +$ 0.45 +$99,000 +$ 6,100 +Natural Gas +Physical Basis +Sales +450,000 +$ 0.94 +$420,750 +$ 168,913 +Prior Year +Total Positions as of December 31, 2004 +Natural Gas +Cash Settled +Sale +3,260,000 +$ 5.60 +$18,249,250 +$ (1,982,964) +Natural Gas +Cash Settled +Purchase +1,130,000 +$ 6.77 +$7,644,540 +$ (486,490) +Natural Gas +Cash Settled +Sale Option +530,000 +$ 5.30 +- +$ 134,242 +Natural Gas +Cash Settled +Purchase Option +265,000 +$ 7.00 +- +$ (85,541) +Natural Gas +Physical +Contract Sale +1,136,230 +$ 6.96 +$7,908,865 +$ 1,268,721 +Natural Gas +Physical +Contract Purchase +3,223,000 +$ 5.82 +$18,747,564 +$ 1,882,984 +The maximum +term for the derivative contracts listed above is 34 months. +F-23 +Petroleum Development Corporation +Open Derivative Positions +Quantity +Gas-Mmbtu +Weighted +Total Contract +Commodity +Type +Oil-Barrels +Average Price +Amount +Fair Value +Total +Positions as of December 31, 2005 +Natural Gas +Cash Settled +Option Sales +5,665,000 +$8.17 +$46,273,550 +$ (12,531,796) +Natural Gas +Cash Settled +Option Purchases +14,030,000 +$6.36 +$89,210,000 +$ 2,660,289 +Positions +maturing in 12 months following December 31, 2005 +Natural Gas +Cash Settled +Option Sales +4,930,000 +$8.07 +$39,802,550 +$ (10,411,106) +Natural Gas +Cash Settled +Option Purchases +12,560,000 +$6.38 +$80,165,000 +$ 2,251,533 +Prior Year +Total Positions as of December 31, 2004 +Natural Gas +Purchase +120,000 +$6.63 +$796,150 +$ (45,680) +Natural Gas +Sale Option +7,400,000 +$4.46 +- +$ 917,553 +Natural Gas +Purchase +Option +3,475,000 +$5.42 +- +$ (3,138,210) +Crude Oil +Sale Option +360,000 +$32.30 +- +$ 306,702 +Crude Oil +Purchase +Option +180,000 +$40.00 +- +$ (973,638) +The maximum +term for the derivative contracts listed above is 15 months. +In addition to including +the gross assets and liabilities related to the Company's share of oil and gas +production, the above tables and the accompanying consolidated balance sheets +include the gross assets and liabilities related to derivative contracts +entered into by the Company on behalf of the affiliate Partnerships as the +Managing General Partner. The accompanying consolidated balance sheets include +the negative fair value of derivatives and a corresponding receivable from the +Partnerships of $5,351,500 as of December 31, 2005 and $1,418,000 as of +December 31, 2004. In addition to the short-term fair value of derivatives +shown in the accompanying consolidated balance sheet there are long-term assets +and long-term liabilities which total to a net long-term liability of +approximately $1,323,100 as of December 31, 2005 and which total to a net long-term +asset of approximately $1,248,000 as December 31, 2004, respectively related to +the fair value of derivatives included in accompanying balance sheet. +The Company is required to +maintain margin deposits with brokers for outstanding futures contracts. As of +December 31, 2005 and 2004, cash in the amount of $1,500,600 and $664,900 was +on deposit. +An interest rate swap +agreement was used to reduce the potential impact of increases in interest +rates on variable rate long-term debt. The swap agreement expired in October +2004. The agreement required the Company, on a quarterly basis, to make a +fixed-rate interest payment of 6.89% plus its current LIBOR rate margin (+1.50% +At December 31, 2003) on a $10,000,000 amount related to its outstanding line +of credit. +The fair value of the +interest rate swap agreement was a liability of $592,700 at December 31, 2003. Current market pricing models were used to estimate fair value. The change in the +fair value of the swap is included in interest expense; the related gain was +$592,700 and $477,600 for the years ended December 31, 2004 and, 2003, respectively. +By using derivative +financial instruments to manage exposures to changes in interest rates and +commodity prices, the Company exposes itself to credit risk and market risk. +Credit risk is the failure of the counterparty to perform under the terms of +the derivative contract. When the fair value of a derivative contract is +positive, the counterparty owes the Company, which creates repayment risk. The +Company minimizes the credit or repayment risk in derivative instruments by +entering into transactions with high-quality counterparties. There were no +counterparty defaults during the years ended December 31, 2005, 2004 and 2003. +F-24 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +Changes in the fair value +of commodity based derivatives are recorded in earnings because they do not +qualify for hedge accounting. These changes are included in the following +income statement captions: +Income Statement Caption +Oil +and gas price risk management loss (gain), +net +Includes realized and unrealized gains +and losses on commodity based derivatives related to the +Company's +oil and gas sales. +Gas +sales from marketing activities +Cost +of gas marketing activities +Includes realized and unrealized gains +and losses on +commodity based derivatives +related to the RNG gas +sales and purchases. +(14) Purchases +and Sales of Oil and Gas Properties +During +the first quarter of 2005, the Company sold a portion of one of its undeveloped +Garfield County, Colorado leases to an unaffiliated entity. The proceeds of +the sale were $6.2 million and the Company's carrying value of the property was +zero. The Company was required to remit $1.0 million to the original lessor, +unless it commenced construction of certain facilities adjacent to this +undeveloped property subject to certain timing conditions. The gain of $5.2 +million was recognized during the first quarter of 2005 and is included in +"Other Income" in the accompanying consolidated statements of income. During +the second quarter of 2005, the Company commenced construction of the +facilities and recorded income of $1.0 million which is included in "Other +income" in the accompanying consolidated statements of income. +During +the second quarter of 2005, the Company completed the sale to an unaffiliated +entity of 111 Pennsylvania wells it purchased from Pemco Gas, Inc. in 1998. +The Company received proceeds of $3.4 million and recorded a gain of +approximately $1.7 million which is included in "Other income" in the +accompanying consolidated statements of income. +During +the second quarter of 2003, the Company purchased 166 wells in the Denver Julesburg Basin in northeastern Colorado from Williams Production RMT Company for $28 +million. The Company estimates the acquisition included approximately 22.6 +billion cubic feet (Bcf) of proved developed producing (PDP) and 3.4 Bcf of +proved developed non-producing reserves (PDNP), all of which is natural gas. +The Company received approval for increased density well spacing in 2004. The +Company drilled 20 new Niobrara wells on the property in 2004 and 72 wells in +2005. +During +the fourth quarter of 2003, the Company purchased from one of its unaffiliated +joint venture partners in the Denver-Julesburg Basin in Weld County, Colorado +approximately 3.1 billion cubic feet equivalent (Bcfe) of proved developed +producing reserves from interests in 20.6 net wells (230 gross) and 1.8 Bcfe of +proved developed non-producing reserves from interests in 17 net wells (183 +gross). The purchase price was $5.2 million which also included over 30 +additional drilling locations. +During +the fourth quarter of 2003, the Company purchased from an unaffiliated party 97 +gross wells (73 net) in the Denver-Julesburg Basin located in northeast +Colorado and northwestern Kansas for $6.0 million. This purchase added +approximately 4.5 billion cubic feet equivalent (Bcfe) of proved developed +producing and proved developed non-producing reserves to the Company's oil and +gas reserves along with 100,000 acres of oil and gas leases. +(15) Costs +Incurred in Oil and Gas Property Acquisition, Exploration and Development +Activities (unaudited) +Costs +incurred by the Company in oil and gas property acquisition, exploration and +development are presented below: +Years Ended December 31, +2005 +2004 +2003 +Acquisition of +properties: +Unproved +properties +$16,910,200 +$ 4,583,000 +$ 6,167,800 +Proved +properties +1,608,300 +720,000 +33,946,600 +Development costs +68,605,000 +32,700,500 +30,630,100 +Exploration costs +12,942,700 +4,169,900 +- +$ 100,066,200 +$ 42,173,400 +$ 70,744,500 +F-25 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +The +proved reserves attributable to the development costs in the above table were +85,624,000 Mcf and 1,576,000 Bbls for 2005, 40,716,000 Mcf and 358,000 Bbls for +2004, 27,719,000 Mcf and 517,000 Bbls for 2003 (amounts unaudited). Of the +above development costs incurred for the years ended December 31, 2005, 2004, and 2003 the amounts of $6,935,400, $1,819,619, and $4,289,600, +respectively, were incurred to develop proved undeveloped properties from the +prior year end. +Property +acquisition costs include costs incurred to purchase, lease or otherwise +acquire a property. Development costs include costs incurred to gain access to +and prepare development well locations for drilling, to drill and equip +development wells, recompletions and to provide facilities to extract, treat, +gather and store oil and gas. +(16) Oil +and Gas Capitalized Costs (unaudited) +Aggregate +capitalized costs for the Company related to oil and gas exploration and +production activities with applicable accumulated depreciation, depletion and +amortization are presented below: +December 31, +2005 +2004 +Proved +oil and gas properties +$ 345,533,300 +$ 274,631,900 +Unproved +oil and gas properties +19,846,300 +8,205,300 +365,379,600 +282,837,200 +Less +accumulated depreciation, +depletion +and amortization +102,513,400 +84,576,100 +$ 262,866,200 +$ 198,261,100 +Suspended +Well Costs +The following table lists +the capitalized exploratory well costs which are pending the determination of +proved reserves. +Balance, +January 1, 2003 +$ - +Additions +- +Charged to +expense +- +Balance, +January 1, 2003 +- +Addition - +Fox Federal #1-13 +4,169,900 +Charged to +expense +- +Balance, +December 31, 2004 +4,169,900 +Addition - +Violet Olsen 34-2914 +1,401,500 +Addition - +Norgaard #1 +516,900 +Addition - +Fedora +4,523,400 +Reclassification to wells, facilities and +equipment +based on determination of +proved +reserves +(4,523,400) +Charged to +expense - Fox Federal #1-13 +(4,169,900) +Balance, +December 31, 2005 +$1,918,400 +Both +of the above referenced wells with costs as of December 31, 2005 were drilled in the fourth quarter of 2005. The wells were completed and evaluated in 2006 and +were deemed to have proved reserves. +None +of the wells listed in the table have been capitalized for more than one year waiting +for a proved reserve determination. +F-26 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +Exploratory +dry hole costs of $11.1 million in the accompanying consolidated statements of +income include the $4.2 million above related to costs incurred in 2004 on the +Fox Federal #1-13 well plus $6.9 million of costs incurred and expensed during +2005. The 2005 costs incurred and expensed included an additional $1.2 million +related to the Fox Federal #1-13 well, approximately $5.42 million related to +the Coffeepot Springs #24-34 well in Colorado and four Kansas wells which +totaled $314,200. +(17) Results +of Operations for Oil and Gas Producing Activities (unaudited) +The +results of operations for oil and gas producing activities (excluding +marketing) are presented below: +Years Ended December 31, +2005 +2004 +2003 +(Restated) +(Restated) +Revenue: +Oil and gas sales +$102,559,200 +$69,492,100 +$48,393,800 +Expenses: +Production costs +16,193,400 +14,201,300 +9,714,600 +Oil and gas price risk management loss, net +9,368,100 +3,084,600 +812,400 +Depreciation, depletion and amortization +19,322,200 +16,680,200 +14,157,000 +Exploratory dry hole costs +11,115,100 +- +- +55,998,800 +33,966,100 +24,684,000 +Results of operations for oil and gas +producing activities before provision +for income taxes +46,560,400 +35,526,000 +23,709,800 +Provision for income taxes +18,112,000 +13,819,600 +9,223,100 +Results of operations for oil and gas +producing activities (excluding corporate +overhead and interest costs) +$28,448,400 +$21,706,400 +$14,486,700 +Production +costs include those costs incurred to operate and maintain productive wells and +related equipment, including costs such as labor, repairs, maintenance, +materials, supplies, fuel consumed, insurance and production taxes. In +addition, production costs include administrative expenses and depreciation +applicable to support equipment associated with these activities. Depreciation, +depletion and amortization expense includes those costs associated with +capitalized acquisition, exploration and development costs, but does not +include the depreciation applicable to support equipment. The provision for +income taxes is computed using statutory tax rates. +F-27 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +(18) Net +Proved Oil and Gas Reserves (Unaudited) +The +proved reserves of oil and gas of the Company have been estimated by +independent petroleum engineers at December 31, 2005, 2004 and 2003. These reserves have been prepared in compliance with the Securities and Exchange +Commission and Financial Accounting Standards Board rules which require that +reserve reports be prepared under economic and operating conditions existing at +the Company's year-end with no provision for price and cost escalation except +by contractual arrangements. An analysis of the change in estimated quantities +of oil and gas reserves, all of which are located within the United States, is shown below: +Oil (Bbls) +2005 +2004 +2003 +Proved developed +and undeveloped reserves: +Beginning +of year +3,316,000 +3,029,000 +2,073,000 +Revisions +of previous estimates +80,000 +305,000 +533,000 +Beginning +of year as revised +3,396,000 +3,334,000 +2,606,000 +New +discoveries and extensions: +Rocky +Mountain Region +1,576,000 +358,000 +517,000 +Sales +of reserves to partnerships +- +(12,000) +(112,000) +Purchase +of reserves: +Rocky Mountain +Region +5,000 +17,000 +307,000 +Production +(439,000 ) +(381,000) +(289,000 ) +End +of year +4,538,000 +3,316,000 +3,029,000 +Proved developed +reserves: +Beginning +of year +3,190,000 +2,889,000 +1,849,000 +End +of year +3,860,000 +3,190,000 +2,889,000 +Gas (Mcf) +2005 +2004 +2003 +Proved developed +and undeveloped reserves: +Beginning +of year +197,549,000 +180,998,000 +128,851,000 +Revisions +of previous estimates +(15,850,000 ) +(10,635,000) +4,394,000 +Beginning +of year as revised +181,699,000 +170,363,000 +133,245,000 +New +discoveries and extensions: +Rocky +Mountain Region +85,624,000 +40,716,000 +27,719,000 +Dispositions +to partnerships +(9,556,000) +(4,240,000) +(4,410,000) +Purchases +of reserves: +Michigan Basin +47,000 +96,000 +265,000 +Rocky +Mountain Region +71,000 +242,000 +32,169,000 +Appalachian +Basin +434,000 +744,000 +722,000 +Production +(11,031,000 ) +(10,372,000 ) +(8,712,000 ) +End +of year +247,288,000 +197,549,000 +180,998,000 +Proved developed +reserves: +Beginning +of year +146,152,000 +134,936,000 +94,847,000 +End +of year +155,354,000 +146,152,000 +134,936,000 +F-28 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to Consolidated +Financial Statements +(19) Standardized +Measure of Discounted Future Net Cash Flows and Changes Therein Relating to +Proved Oil and Gas Reserves (Unaudited) +Summarized +in the following table is information for the Company with respect to the standardized +measure of discounted future net cash flows relating to proved oil and gas +reserves. Future cash inflows are computed by applying year-end prices of oil +and gas relating to the Company's proved reserves to the year-end quantities of +those reserves. Future production, development, site restoration and +abandonment costs are derived based on current costs assuming continuation of +existing economic conditions. Future income tax expenses are computed by +applying the statutory rate in effect at the end of each year to the future +pretax net cash flows, less the tax basis of the properties and gives effect to +permanent differences, tax credits and allowances related to the properties. +2005 +2004 +2003 +Future +Estimated Cash Flows +$ +2,381,238,000 +$ +1,298,394,000 +$ +1,088,415,000 +Future +Estimated Production Costs +(545,683,000) +(319,065,000) +(250,735,000) +Future +Estimated Development Costs +(207,164,000) +(95,498,000) +(65,275,000) +Future +Estimated Income Tax Expense +(633,444,000) +(343,810,000) +(1) +(300,466,000) +(1) +Future Net +Cash Flows +994,947,000 +540,021,000 +(1) +471,939,000 +(1) +10% Annual +Discount for Estimated +Timing +of Cash Flows +(589,517,000) +(310,593,000) +(1) +(269,556,000) +(1) +Standardized +Measure of Discounted +Future +Estimated Net Cash Flows +$ +405,430,000 +$ +229,428,000 +(1) +$ 202,383,000 +(1) +(1) +Amounts +restated since the filing of the December 31, 2004 Form 10-K/A. +F-29 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +The +following table summarizes the principal sources of change in the standardized +measure of discounted future estimated net cash flows: +2005 +2004 +2003 +(Restated) +(Restated) +Sales of oil +and gas production +net +of production costs +$ +(86,366,000) +$ +(55,291,000) +$ (38,679,000) +Net changes in +prices and production costs +208,353,000 +26,768,000 +73,241,000 +Extensions, +discoveries, and improved +recovery, +less related costs +150,654,000 +51,413,000 +51,583,000 +Sales of +reserves +(14,456,000) +(7,565,000) +(5,637,000) +Purchase of +reserves +1,266,000 +1,953,000 +68,104,000 +Development +costs incurred during the period +24,035,000 +8,495,000 +10,400,000 +Revisions of +previous quantity estimates +(24,130,000) +6,312,000 +13,906,000 +Changes in +estimated income taxes +(112,054,000) +(16,160,000) +(73,907,000) +Accretion of +discount +38,241,000 +33,500,000 +15,182,000 +Timing and +other +(9,541,000) +22,380,000 +2,363,000 +Total +$ +176,002,000 +$ +27,045,000 +$ +116,556,000 +It is +necessary to emphasize that the data presented should not be viewed as +representing the expected cash flow from, or current value of, existing proved +reserves since the computations are based on a large number of estimates and +arbitrary assumptions. Reserve quantities cannot be measured with precision +and their estimation requires many judgmental determinations and frequent +revisions. The required projection of production and related expenditures over +time requires further estimates with respect to pipeline availability, rates of +demand and governmental control. Actual future prices and costs are likely to +be substantially different from the current prices and costs utilized in the +computation of reported amounts. Any analysis or evaluation of the reported +amounts should give specific recognition to the computational methods utilized +and the limitations inherent therein. +The estimated +present value of future cash flows relating to proved reserves is extremely +sensitive to prices used at any measurement period. The average prices used for +each commodity for the years ended December 31, 2005, 2004 and 2003 were as follows: +Average Price +As of December 31: +Oil +Gas +2005 +$58.25 +$8.56 +2004 +$41.63 +$5.87 +2003 +$31.80 +$5.48 +(20) Business +Segments (Thousands) +The Company's operating activities can be divided into four major +segments: drilling and development, natural gas marketing, oil and gas sales, +and well operations. The Company drills natural gas wells for Company-sponsored +drilling partnerships and retains an interest in each well. A wholly-owned +subsidiary, Riley Natural Gas, engages in the marketing of natural gas to +commercial and industrial end-users. The Company owns an interest in +approximately 2,800 wells from which it derives oil and gas working interests. +The Company charges Company-sponsored partnerships and other third parties +competitive industry rates for well operations and gas gathering. All material +inter-company accounts and transactions between segments have been eliminated. +Segment information for the years ended December 31, 2005, 2004 and 2003 is as follows: +F-30 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +2005 +2004 +2003 +(Restated) +(Restated) +REVENUES +Drilling +and Development +$ 99,963 +$ 94,076 +$ 57,509 +Natural Gas Marketing +121,387 +94,675 +73,186 +Oil and Gas Sales +102,559 +69,492 +48,394 +Well +Operations +8,760 +7,677 +6,907 +Unallocated +amounts (1) +10,464 +1,833 +3,475 +$ 343,133 +$ 267,753 +$ 189,471 +SEGMENT +INCOME BEFORE INCOME TAXES +Drilling +and Development +$ 11,778 +$ 16,380 +$ 10,564 +Natural +Gas Marketing +1,737 +1,784 +815 +Oil +and Gas Sales (3) +46,560 +35,526 +23,710 +Well +Operations +3,539 +3,695 +2,618 +Unallocated +amounts (1) +General +and Administrative expenses +(6,960) +(4,506) +(4,974) +Interest +expense +(682) +(674) +(1,195) +Other +(2) +10,156 +1,273 +3,079 +Total +$ 66,128 +$ 53,478 +$ 34,617 +SEGMENT +ASSETS +Drilling +and Development +$ 89,030 +$ 64,348 +$ 62,546 +Natural +Gas Marketing +56,518 +31,234 +17,007 +Oil +and Gas Sales +256,621 +211,255 +194,371 +Well +Operations +31,407 +16,518 +11,602 +Unallocated +amounts +Cash +3,383 +112 +800 +Other +12,126 +11,561 +11,216 +Total +$ 449,085 +$ 335,028 +$ 297,542 +EXPENDITURES +FOR SEGMENT LONG-LIVED ASSETS +Drilling +and Development +$ - +$ - +$ - +Natural +Gas Marketing +1 +6 +- +Oil +and Gas Sales +100,066 +42,173 +69,756 +Well +Operations +3,949 +1,911 +2,944 +Unallocated +amounts +2,452 +1,302 +342 +Total +$ 106,468 +$ 45,392 +$ 73,042 +(1) Items which are not allocated in assessing +segment performance. +(2) Includes interest on investments, partnership +management fees and gains on sales of assets in 2005, 2004 and 2003 which are +not allocated in assessing segment performance. +(3) Includes $11.1 million in exploratory dry hole +costs for the year ended December 31, 2005. +F-31 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +(21) Quarterly Financial Data (Unaudited) +Quarterly +financial data for the years ended December 31, 2005, 2004 and 2003, are as follows: +2005 +Quarter +Year +First +Second +Third +Fourth +(Restated) +(Restated) +(Restated) +Revenues: +Oil and gas +well drilling operations +$ +25,366,300 +$ 28,110,800 +$ 32,266,600 +$ 14,219,200 +$ +99,962,900 +Gas sales +from marketing activities +17,522,000 +25,917,100 +14,970,300 +62,694,700 +121,104,100 +Oil and gas +sales +18,663,700 +21,542,800 +28,413,400 +33,939,300 +102,559,200 +Well +operations and pipeline income +1,927,100 +2,067,900 +2,290,900 +2,473,700 +8,759,600 +Other income +6,213,800 +3,492,600 +209,400 +831,500 +10,747,300 +Total revenues +69,692,900 +81,131,200 +78,150,600 +114,158,400 +343,133,100 +Costs and +expenses: +Cost of oil +and gas well drilling operations +20,644,100 +23,743,000 +28,733,500 +15,064,300 +88,184,900 +Cost of gas +marketing activities +17,901,600 +26,177,300 +14,269,500 +61,295,300 +119,643,700 +Oil and gas +production costs and well operations costs +3,978,100 +4,481,200 +6,263,000 +5,212,400 +19,934,700 +Exploratory +dry hole costs +- +4,864,000 +135,800 +6,115,300 +11,115,100 +General and +administrative expenses +1,617,500 +1,266,000 +1,645,500 +2,431,300 +6,960,300 +Depreciation, depletion and amortization +4,856,900 +4,845,100 +5,120,000 +6,294,200 +21,116,200 +Total costs and expenses +48,998,200 +65,376,600 +56,167,300 +96,412,800 +266,954,900 +Income from +operations +20,694,700 +15,754,600 +21,983,300 +17,745,600 +76,178,200 +Interest +expense +147,800 +143,000 +142,200 +249,300 +682,300 +Oil and gas +price risk management loss (gain), net +3,659,100 +(858,400) +9,922,300 +(3,354,900) +9,368,100 +Income before +income taxes +16,887,800 +16,470,000 +11,918,800 +20,851,200 +66,127,800 +Income taxes +6,247,900 +6,091,400 +4,413,000 +7,923,800 +24,676,100 +Net income +$ +10,639,900 +$ 10,378,600 +$ +7,505,800 +$ 12,927,400 +$ +41,451,700 +Basic earnings +per common share +$ +0.64 +$ +0.63 +$ +0.46 +$ +0.80 +$ +2.53 +Diluted +earnings per common and +common +equivalent share +$ +0.64 +$ +0.63 +$ +0.46 +$ +0.79 +$ +2.52 +F-32 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +2004 (Restated) +Quarter +Year +First +Second +Third +Fourth +Revenues: +Oil and +gas well drilling operations +$ 22,109,100 +$ +24,065,900 +$ 24,070,300 +$ +23,830,700 +$ 94,076,000 +Gas sales +from marketing actitities +22,058,900 +24,954,300 +22,630,200 +24,983,400 +94,626,800 +Oil and +gas sales +16,316,200 +16,209,000 +16,580,500 +20,386,400 +69,492,100 +Well +operations and pipeline income +1,706,900 +1,737,600 +1,875,000 +2,357,400 +7,676,900 +Other +income +58,100 +622,000 +589,000 +611,600 +1,880,700 +Total revenues +62,249,200 +67,588,800 +65,745,000 +72,169,500 +267,752,500 +Costs and +expenses: +Cost of +oil and gas well drilling operations +17,965,500 +19,579,400 +19,681,300 +20,470,000 +77,696,200 +Cost of +gas marketing activities +21,889,700 +24,605,800 +22,047,400 +24,338,300 +92,881,200 +Oil and +gas production and well operations costs +3,775,500 +3,796,200 +3,753,600 +5,951,900 +17,277,200 +General +and administrative expenses +994,200 +900,900 +926,300 +1,684,200 +4,505,600 +Depreciation, depletion and amoritization +4,544,400 +4,451,300 +4,312,300 +4,847,900 +18,155,900 +Total costs and expenses +49,169,300 +53,333,600 +50,720,900 +57,292,300 +210,516,100 +Income from +operations +13,079,900 +14,255,200 +15,024,100 +14,877,200 +57,236,400 +Interest +expense +209,600 +194,400 +223,100 +46,600 +673,700 +Oil and gas +price risk management loss (gain), net +830,000 +868,700 +2,378,800 +(992,900) +3,084,600 +Income +before income taxes +12,040,300 +13,192,100 +12,422,200 +15,823,500 +53,478,100 +Income taxes +4,334,400 +4,755,400 +4,506,400 +6,654,300 +(1) +20,250,500 +Net income +$ +7,705,900 +$ +8,436,700 +$ +7,915,800 +$ +9,169,200 +$ 33,227,600 +Basic +earnings per common share +$ +0.49 +$ +0.52 +$ +0.49 +$ +0.55 +$ +2.05 +Diluted +earnings per common and +common-equivalent share +$ 0.47 +$ +0.51 +$ +0.47 +$ +0.54 +$ +2.00 +(1) Includes +an adjustment of approximately $600,000 to the tax provision of the prior +three quarters. +F-33 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +2003 (Restated) +Quarter +Year +First +Second +Third +Fourth +Revenues: +Oil and gas +well drilling operations +$ +17,147,000 +$ 9,507,000 +$ 11,325,800 +$ 19,529,800 +$ +57,509,600 +Gas sales +from marketing actitities +20,651,000 +16,805,000 +20,370,200 +15,305,500 +73,131,700 +Oil and gas +sales +9,658,200 +11,213,200 +13,304,200 +14,218,200 +48,393,800 +Well +operations and pipeline income +1,542,800 +1,671,500 +1,747,500 +1,945,300 +6,907,100 +Other +income +327,400 +285,100 +488,300 +2,427,700 +3,528,500 +Total revenues +49,326,400 +39,481,800 +47,236,000 +53,426,500 +$ 189,470,700 +Costs and +expenses: +Cost of oil +and gas well drilling operations +13,325,300 +7,760,600 +9,201,400 +16,658,600 +$ +46,945,900 +Cost of gas +marketing activities +20,937,600 +16,443,700 +19,797,200 +15,182,900 +72,361,400 +Oil and gas +production and well operations cost +2,694,200 +3,363,300 +3,868,500 +3,325,300 +13,251,300 +General and +administrative expenses +1,177,700 +1,186,600 +1,377,300 +1,232,800 +4,974,400 +Depreciation, depletion and amoritization +3,146,400 +3,594,400 +4,140,100 +4,431,900 +15,312,800 +Total costs and expenses +41,281,200 +32,348,600 +38,384,500 +40,831,500 +$ 152,845,800 +Income from +operations +8,045,200 +7,133,200 +8,851,500 +12,595,000 +36,624,900 +Interest +expense +215,500 +257,300 +355,000 +367,500 +1,195,300 +Oil and gas +price risk-management loss(gain), net +788,400 +(426,400) +(550,900) +1,001,300 +812,400 +Income before +income taxes and cumulative +effect of +change in accounting principle +7,041,300 +7,302,300 +9,047,400 +11,226,200 +34,617,200 +Income taxes +2,324,500 +2,410,100 +2,986,900 +4,212,000 +11,933,500 +Net income +before cumulative effect of +change in +accounting principle +4,716,800 +4,892,200 +6,060,500 +7,014,200 +22,683,700 +Cumulative +effect of change in accounting +principle +(net of taxes of $1,392,000) +(2,271,300) +- +- +- +(2,271,300) +Net income +$ +2,445,500 +$ 4,892,200 +$ 6,060,500 +$ 7,014,200 +$ +20,412,400 +Basic earnings +per common share before +accounting +change +$ +0.30 +$ +0.31 +$ 0.39 +$ +0.45 +$ +1.45 +Cumulative +effect of change in +accounting +principle +$ +(0.15) +- +- +- +$ +(0.15) +Basic earnings +per common share +$ +0.15 +$ +0.31 +$ +0.39 +$ +0.45 +$ +1.30 +Diluted +earnings per share before +accounting +change +$ +0.29 +$ +0.30 +$ +0.37 +$ 0.43 +$ +1.39 +Cumulative +effect of change in +accounting +principle +$ +(0.14) +- +- +- +$ +(0.14) +Diluted +earnings per common and +common +equivalent share +$ +0.15 +$ +0.30 +$ +0.37 +$ +0.43 +$ +1.25 +F-34 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +The following tables +set forth the effect of the restatement (See footnote 22 for discussion of +restatement) on the affected line items within the Company's previously +reported consolidated statements of income for the quarters ended March 31, +2005, June 30, 2005 and September 30, 2005 and for each of the quarters in 2004 +and 2003. +Quarterly +Information +2005 +(Unaudited) +(in thousands) +First Quarter +Second Quarter +Third Quarter +As +As +As +Consolidated +Statements +previously +As +previously +As +previously +As +of Income +Data: +reported +restated +reported +restated +reported +restated +Revenues: +Oil and gas +well drilling operations +$ 32,351 +$ 25,366 +$ 36,057 +$ 28,111 +$ 39,711 +$ 32,267 +Well +operations and pipeline income +$ 2,112 +$ 1,927 +$ 2,244 +$ 2,068 +$ 2,483 +$ 2,291 +Other income +$ 6,214 +$ 6,214 +$ 3,573 +$ 3,493 +$ 209 +$ 209 +Total +revenues +$ 76,863 +$ 69,693 +$ 89,334 +$ 81,131 +$ 85,787 +$ 78,150 +Costs and +expenses: +Cost of oil +and gas well drilling operations +$ 27,629 +$ 20,644 +$ 31,689 +$ 23,743 +$ 36,178 +$ 28,734 +Oil and gas +production +and well +operations costs +$ 4,163 +$ 3,978 +$ 4,738 +$ 4,482 +$ 6,455 +$ 6,263 +Total costs +and expenses +$ 56,168 +$ 48,998 +$ 73,579 +$ 65,376 +$ 63,804 +$ 56,167 +Income from +operations +$ 20,695 +$ 20,695 +$ 15,755 +$ 15,755 +$ 21,983 +$ 21,983 +Quarterly +Information (Unaudited) +(in +thousands) +2004 +First Quarter +Second Quarter +Third Quarter +Fourth Quarter +Consolidated Statements +As +As +As +As +of +Income Data: +previously +As +previously +As +previously +As +previously +As +reported +restated +reported +restated +reported +restated +reported +restated +Revenues: +Oil and +gas well drilling operations +$ 29,499 +$ 22,109 +$ 29,454 +$ 24,066 +$ 30,394 +$ 24,070 +$ 29,864 +$ 23,831 +Well +operations and pipeline income +$ 1,838 +$ 1,707 +$ 1,912 +$ 1,738 +$ 2,074 +$ 1,875 +$ 2,561 +$ 2,357 +Other +income +$ 58 +$ 58 +$ 687 +$ 622 +$ 589 +$ 589 +$ 612 +$ 612 +Total +revenues +$ 69,770 +$ 62,249 +$ 73,217 +$ 67,589 +$ 72,268 +$ 65,745 +$ 78,405 +$ 72,169 +Costs and +expenses: +Costs of +oil and gas well drilling +operations +$ 25,356 +$ 17,966 +$ 24,967 +$ 19,579 +$ 26,005 +$ 19,681 +$ 26,503 +$ 20,470 +Oil and +gas production and well +operations +costs +$ 3,906 +$ 3,776 +$ 4,036 +$ 3,796 +$ 3,952 +$ 3,754 +$ 6,156 +$ 5,952 +Total +costs and expenses +$ 56,690 +$ 49,169 +$ 58,961 +$ 53,333 +$ 57,244 +$ 50,721 +$ 63,528 +$ 57,292 +Income from operations +$ 13,080 +$ 13,080 +$ 14,255 +$ 14,255 +$ 15,024 +$ 15,024 +$ 14,877 +$ 14,877 +F-35 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +Quarterly +Information (Unaudited) +(in +thousands) +2003 +First Quarter +Second Quarter +Third Quarter +Fourth Quarter +Consolidated Statements +As +As +As +As +of Income +Data: +previously +As +previously +As +previously +As +previously +As +reported +restated +reported +restated +reported +restated +reported +restated +Revenues: +Oil and +gas well drilling operations +$ 21,498 +$ 17,147 +$ 11,866 +$ 9,507 +$ 14,080 +$ 11,326 +$ 24,398 +$ 19,530 +Well +operations and pipeline income +$ 1,648 +$ 1,543 +$ 1,769 +$ 1,672 +$ 1,865 +$ 1,747 +$ 2,066 +$ 1,945 +Other +income +$ 385 +$ 327 +$ 285 +$ 285 +$ 488 +$ 488 +$ 2,428 +$ 2,428 +Total +revenues +$ 53,840 +$ 49,326 +$ 41,938 +$ 39,482 +$ 50,108 +$ 47,236 +$ 58,415 +$ 53,426 +Costs and +expenses: +Costs of +oil and gas well +drilling +operations +$ 17,676 +$ 13,325 +$ 10,120 +$ 7,761 +$ 11,956 +$ 9,201 +$ 21,526 +$ 16,659 +Oil and +gas production and well +operations costs +$ 2,857 +$ 2,694 +$ 3,460 +$ 3,363 +$ 3,986 +$ 3,869 +$ 3,446 +$ 3,325 +Total +costs and expenses +$ 45,795 +$ 41,281 +$ 34,805 +$ 32,349 +$ 41,256 +$ 38,384 +$ 45,820 +$ 40,831 +Income +from operations +$ 8,045 +$ 8,045 +$ 7,133 +$ 7,133 +$ 8,852 +$ 8,852 +$ 12,595 +$ 12,595 +(22) Restatement +In this Annual Report on +Form 10-K for the year ended December 31, 2005, the Company is amending and +restating its prior consolidated statements of income for the years ended December 31, 2004 and 2003, and for each of the quarters ended in the years 2004 and +2003. This Annual Report on Form 10-K is also amending and restating our consolidated +statements of income for the quarterly periods ended March 31, 2005, June 30, 2005, and September 30, 2005. +As previously announced in +a Form 8K as filed with the Securities and Exchange Commission on April 3, +2006, the Company identified that corrections were needed to certain revenues +and expenses to properly reflect the elimination of transactions between the +Company and the limited partnerships. The corrections resulted in +elimination of revenues and expenses of equal amounts. The restatement had no +effect on Net Income, Earnings per Share, Cash Flow, Proved Oil and Gas +Reserves, or the Company's financial position. In addition, the Company made +other corrections that in the prior periods were considered immaterial both +individually and in the aggregate. +Effects +of the Restatement +The +restatement also impacted or made changes to the following financial statement +footnotes; Note 17, 19, 20, 21 and added Note 22, Restatement. +F-36 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +The +following tables set forth the effects of the restatement on the affected line +items within the Company's previously reported Consolidated Statements of Income +for the years 2004 and 2003. +For the year +ended December 31, +(in +thousands) +Consolidated +Statements +2004 +2003 +of Income +Data: +As +As +previously +As +previously +As +reported +restated +reported +restated +Revenues: +Oil and gas +well drilling operations +$ 119,211 +$ 94,076 +$ 71,842 +$ 57,510 +Well +operations and pipeline income +$ 8,385 +$ 7,677 +$ 7,348 +$ 6,907 +Other Income +$ 1,946 +$ 1,881 +$ 3,586 +$ 3,529 +Total +revenues +$ 293,660 +$ 267,753 +$204,301 +$189,471 +Costs and +expenses: +Costs of oil +and gas well drilling operations +$ 102,831 +$ 77,696 +$ 61,278 +$ 46,946 +Oil and gas +production +and +well operations costs +$ 18,050 +$ 17,277 +$ 13,749 +$ 13,251 +Total costs +and expenses +$ 236,423 +$ 210,516 +$167,676 +$152,846 +Income from +operations +$ 57,236 +$ 57,236 +$ 36,625 +$ 36,625 +F-37 +PETROLEUM DEVELOPMENT CORPORATION AND +SUBSIDIARIES +Notes to +Consolidated Financial Statements +SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES +Years Ended December 31, 2005, 2004 and 2003 +Column +A +Column B +Column C +Column +D +Column E +Additions, +Balance at +Charged to +Balance +Beginning +Costs and +At End +Description +of Period +Expenses +Deductions +of Period +Allowance for doubtful +accounts deducted +from accounts receivable in the +Balance sheet +2005 +$409,000 +$ - +$ +- +$409,000 +2004 +$487,300 +$ - +$ 78,300 (a) +$409,000 +2003 +$524,500 +$ - +$ 37,200 (a) +$487,300 +(a) +Deduction relates to +the write-off of accounts receivable deemed uncollectible. +F-38 \ No newline at end of file diff --git a/raw/filings/0000077877/2005/0000077877-06-000037/rp_note.txt b/raw/filings/0000077877/2005/0000077877-06-000037/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2005/0000077877-06-000037/rpt_disclosure.txt b/raw/filings/0000077877/2005/0000077877-06-000037/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..6df376e7fdbe87981001154f9d0ce06315e2bad1 --- /dev/null +++ b/raw/filings/0000077877/2005/0000077877-06-000037/rpt_disclosure.txt @@ -0,0 +1,7 @@ +Item 13. Certain Relationships and Related Transactions +During the year ended December 31, 2005, there was no transaction or +series of transactions to which we were or are a party in which the amount +involved exceeded or exceeds $60,000 and in which any director, executive +officer, holder of more than 5% of our common stock or any member of the +immediate family of any of the foregoing persons had or will have a direct or +indirect material interest. \ No newline at end of file diff --git a/raw/filings/0000077877/2006/0001140361-07-010649/filing.txt b/raw/filings/0000077877/2006/0001140361-07-010649/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..56623cf9ba484009b4e13435f4ccbd1d3f1cc939 --- /dev/null +++ b/raw/filings/0000077877/2006/0001140361-07-010649/filing.txt @@ -0,0 +1,15467 @@ +10-K +1 +form10-k.htm +PETROLEUM DEVELOPMENT CORP. 10-K 12-31-2006 +form10-k.htm +UNITED +STATES +SECURITIES +AND EXCHANGE COMMISSION +Washington, +D.C. 20549 +FORM +10-K +T +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF +THE SECURITIES EXCHANGE ACT OF 1934 +For +the +fiscal year ended December 31, 2006 +or +£ +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE +ACT +OF 1934 +Commission +File Number 000-07246 +PETROLEUM +DEVELOPMENT CORPORATION +( Exact +name of registrant as specified in its charter) +Nevada +95-2636730 +(State +of incorporation) +(I.R.S. +Employer Identification +No.) +120 +Genesis Boulevard +Bridgeport, +West Virginia 26330 +(Address +of principal executive offices) (Zip Code) +Registrant's +telephone number, including area code: (304) 842-3597 +Securities +Registered Pursuant to Section 12(b) of the Act: +Title +of each class +Name +of exchange on which registered +Common +Stock, par value $.01 per share +NASDAQ +Global Select Market +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 £ +No +T +Indicate +by check mark if registrant is not required to file reports pursuant to Section +13 or Section 15(d) of the Act. Yes £ +No +T +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 and (2) has been subject to such filing requirements for +the +past 90 days. Yes T +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. T +Indicate +by check mark whether the registrant is a large accelerated filer, an +accelerated filer, or non-accelerated file. See definition of "accelerated +filer +and larger accelerated filer" in Rule 12b-2 of the Exchange Act: +Large +Accelerated Filer £ +Accelerated +Filer T +Non-Accelerated +Filer £ +Indicate +by check mark whether the registrant is a shell company (as defined in Rule +12b-2 of the Exchange Act). Yes £ +No +T +As +of +April 30, 2007, 14,887,530 shares of the Registrant's Common Stock were issued +and outstanding. +The +aggregate market value of such shares held by non-affiliates of the Registrant +on June 30, 2006, the last business day of the Registrant's most recently +completed second quarter was $610,385,733 (based on the last traded price of +$37.70). +DOCUMENTS +INCORPORATED BY REFERENCE +None. +PET ROLEUM +DEVELOPMENT CORPORATION +INDEX +TO REPORT ON FORM 10-K +Glossary +of Terms +PART +I +Page +Item +1: +Business +5 +Item +1A: +Risk +Factors +15 +Item +1B: +Unresolved +Staff Comments +24 +Item +2: +Properties +24 +Item +3: +Legal +Proceedings +28 +Item +4: +Submission +of Matters to a Vote of Security +Holders +28 +PART +II +Item +5: +Market +for Registrant’s Common Equity, Related Stockholder +Matters and Issuer Purchases of Equity Securities +28 +Item +6: +Selected +Financial Data +30 +Item +7: +Management’s +Discussion and Analysis of Financial Condition +and Results of Operations +31 +Item +7A: +Quantitative +and Qualitative Disclosures About Market +Risk +49 +Item +8: +Financial +Statements and Supplementary +Data +51 +Item +9: +Changes +in and Disagreements With Accountants on Accounting +and Financial Disclosure +52 +Item +9A: +Controls +and Procedures +52 +Item +9B: +Other +Information +57 +PART +III +Item +10: +Directors, +Executive Officers and Corporate +Governance +57 +Item +11: +Executive +Compensation +60 +Item +12: +Security +Ownership of Certain Beneficial Owners and +Management and Related Stockholder Matters +74 +Item +13: +Certain +Relationships and Related Transactions, and +Director Independence +75 +Item +14: +Principal +Accounting Fees and Services +76 +PART +IV +Item +15: +Exhibits, +Financial Statement Schedules +77 +SIGNATURES +78 +2 +Index +GLO SSARY +OF TERMS +The +following are abbreviations and definitions of terms commonly used in the oil +and gas industry and this Form 10-K. +Bbl +- One +barrel, or 42 U.S. gallons of liquid volume. +Bcf +- One +billion cubic feet. +Bcfe +- One +billion cubic feet of natural gas equivalents. +Completion +- The +installation of permanent equipment for the production of oil or +gas. +Credit +Facility +- +A +line of +credit provided by a group of banks, secured by oil and gas +properties. +DD&A +- +Refers +to +depreciation, depletion and amortization of the Company’s property and +equipment. +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. +Division +order +- A +contract setting forth the interest of each owner of an oil and gas property, +and serves as the basis on which the purchasing company pays each owner’s +respective share of the proceeds of the oil and gas purchased. +Dry +hole +- A well +found to be incapable of producing hydrocarbons in sufficient quantities to +justify completion as an oil or gas well. +Exploratory +well +- A well +drilled to find and produce oil or natural gas reserves not classified as +proved, to find a new productive reservoir in a field previously found to be +productive of oil or natural gas in another reservoir or to extend a known +reservoir. +Extensions +and discoveries +- As to +any period, the increases to proved reserves from all sources other than the +acquisition of proved properties or revisions of previous +estimates. +Gross +acres or wells +- Refers +to the total acres or wells in which the Company has a working +interest. +Horizontal +drilling +- A +drilling technique that permits the operator to contact and intersect a larger +portion of the producing horizon than conventional vertical drilling techniques +and may, depending on the horizon, result in increased production rates and +greater ultimate recoveries of hydrocarbons. +MBbls +- One +thousand barrels. +Mcf +- One +thousand cubic feet. +Mcfe +- One +thousand cubic feet of natural gas equivalents, based on a ratio of 6 Mcf for +each barrel of oil, which reflects the relative energy content. +MMbtu +- +One +million British thermal units. One British thermal unit is the heat required +to +raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees +Fahrenheit. +MMcf +- One +million cubic feet. +MMcfe +- +One +million cubic feet of natural gas equivalents. +Natural +gas liquids +- Liquid +hydrocarbons that have been extracted from natural gas, such as ethane, propane, +butane and natural gasoline. +Net +acres or wells +- Refers +to gross acres or wells multiplied, in each case, by the percentage working +interest owned by the Company. +Net +production +- Oil +and gas production that is owned by the Company, less royalties and production +due others. +NYMEX +- New +York Mercantile Exchange, the exchange on which commodities, including crude +oil +and natural gas futures contracts, are traded. +3 +Index +Oil +- Crude +oil or condensate. +Operator +- The +individual or company responsible for the exploration, development and +production of an oil or gas well or lease. +Present +value of proved reserves +- The +present value of estimated future revenues, discounted at 10% annually, to +be +generated from the production of proved reserves determined in accordance with +Securities and Exchange Commission guidelines, net of estimated production +and +future development costs, using prices and costs as of the date of estimation +without future escalation, without giving effect to (i) estimated future +abandonment costs, net of the estimated salvage value of related equipment, +(ii) non-property related expenses such as general and administrative +expenses, debt service and future income tax expense, or +(iii) depreciation, depletion and amortization. +Proved +developed non-producing reserves +- +Reserves that consist of (i) proved reserves from wells which have been +completed and tested but are not producing due to lack of market or minor +completion problems which are expected to be corrected and (ii) proved reserves +currently behind the pipe in existing wells and which are expected to be +productive due to both the well log characteristics and analogous production +in +the immediate vicinity of the wells. +Proved +developed producing reserves +- +Proved +reserves that can be expected to be recovered from currently producing zones +under the continuation of present operating methods. +Proved +developed reserves +- +The +combination of proved developed producing and proved developed non-producing +reserves. +Proved +reserves +- 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, i.e., prices and costs as of the date the estimate is +made. Prices include consideration of changes in existing prices provided +only by contractual arrangements, but not on escalations based upon future +conditions. +Proved +undeveloped reserves ("PUD") +- Proved +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 +- A +recompletion occurs when the producer reenters a well to complete (i.e., +perforate) a new formation from that in which a well has previously been +completed. +Royalty +- An +interest in an oil and gas lease that gives the owner of the interest the right +to receive a portion of the production from the leased acreage (or of the +proceeds of the sale thereof), but generally does not require the owner to +pay +any portion of the costs of drilling or operating the wells on the leased +acreage. Royalties may be either landowner’s royalties, which are reserved +by the owner of the leased acreage at the time the lease is granted, or +overriding royalties, which are usually reserved by an owner of the leasehold +in +connection with a transfer to a subsequent owner. +SEC +- The +United States Securities and Exchange Commission. +Standardized +measure of discounted future net cash flows +- +Present value of proved reserves, as adjusted to give effect to +(i) estimated future abandonment costs, net of the estimated salvage value +of related equipment, and (ii) estimated future income taxes. +Tcf +- One +trillion cubic feet. +Undeveloped +acreage +- Leased +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 proved reserves. +Working +interest +- An +interest in an oil and gas lease that gives the owner of the interest the right +to drill for and produce oil and gas on the leased acreage and requires the +owner to pay a share of the costs of drilling and production operations. +The share of production to which a working interest is entitled will be smaller +than the share of costs that the working interest owner is required to bear +to +the extent of any royalty burden. +Workover +- +Operations on a producing well to restore or increase production. +4 +Index +PART +I +ITE M +1: BUSINESS +Petroleum +Development Corporation is an independent energy company engaged primarily +in +the development, production and marketing of natural gas and oil. Since it +began +oil and gas operations in 1969, the Company has grown primarily through drilling +and development activities, the acquisition of producing natural gas and oil +wells and the expansion of its natural gas marketing activities. As of December +31, 2006, the Company has interests in approximately 3,100 wells located in +the +Rocky Mountain Region, Appalachian Basin and Michigan with gross proved reserves +of 719 billion cubic feet equivalent of natural gas (“Bcfe”, based on one barrel +of oil equaling six thousand cubic feet equivalent of natural gas (“Mcfe”)) of +which the Company's share is 323 Bcfe. The Company's share of production for +the +fourth quarter of 2006 averaged 52,000 Mcfe per day. +Unless +the context otherwise requires, the terms "PDC" or "Company" refer to Petroleum +Development Corporation, its subsidiaries and proportionately consolidated +drilling partnerships, collectively. The Company’s corporate headquarters are +located at 120 Genesis Boulevard, Bridgeport, West Virginia 26330 where the +telephone number is (304) 842-3597. +Business +Segments +The +Company’s operations are divided into four segments for management and reporting +purposes: (1) drilling and development, (2) natural gas marketing, (3) oil +and +gas sales and (4) well operations and pipeline income. See Note 17 to the +consolidated financial statements. +Drilling +and Development +The +Company drills wells not only for itself, but also for its investor partners. +When the Company drills wells for others it earns profit above the cost of +the +wells. Beginning with the last Company-sponsored partnership of 2005 (for which +revenue generating activities did not commence until early 2006), partnership +wells are drilled on a “cost-plus” basis, where the Company bills investors for +the actual cost of the wells plus an agreed upon mark-up above the costs. Prior +to that, most of the Company’s third-party drilling activities were conducted on +a footage-based basis, where the Company drills the wells for a fixed price +per +foot drilled with additional chargeable items per the drilling agreement. +Since +1984, the Company has sponsored limited partnerships formed to engage in +drilling operations. The Company typically purchases a 20% to 37% ownership +working interest in these drilling limited partnerships. In 2006, the Company, +through one private drilling partnership, raised approximately $90 million +in +investor subscriptions, making it one of the largest sponsors of oil and gas +partnership programs in the United States, as it has been for the last several +years. PDC’s working interest is 37% in the 2006 partnership. Through the +partnerships, the Company has been able to expand its drilling opportunities, +reduce its drilling risk through greater diversification, and share the costs +of +the infrastructure necessary to support such activities. +Natural +Gas Marketing +The +Company’s wholly-owned subsidiary, Riley Natural Gas ("RNG"), purchases, +aggregates and resells natural gas developed by the Company and other producers. +This allows the Company to diversify its operations beyond natural gas drilling +and production. RNG has established relationships with many of the natural +gas +producers in the Appalachian Basin and has significant expertise in the natural +gas end-user market. In addition, RNG has extensive experience in the use of +risk management strategies, which the Company utilizes to help manage the +financial impact of changes in the price of natural gas and oil on the Company +and its partnerships. RNG also manages the marketing of oil and gas for the +Company's wells outside the Appalachian Basin, but does not market gas or oil +for the non-affiliated producers in those areas. +Oil +and Gas Sales +Revenue +and expenses from the production and sale of oil and natural gas from the +Company’s interests in oil and gas wells is reported in this segment. The +Company has interests in approximately 3,100 wells ranging from a few percent +to +100%. During 2006, approximately 9% of the Company’s production was generated by +Appalachian Basin wells, 8% by Michigan Basin wells and 83% by Rocky Mountain +Region wells. As of the end of 2006, the Company's total proved reserves were +located as follows: Appalachian Basin (11%), Michigan (7%) and Rocky Mountain +Region (82%). The majority of the Company's undeveloped acreage is in the Rocky +Mountain Region and the Company's planned drilling for 2007 will be focused +in +that area. See Note 3 to the consolidated financial statements for disclosure +of +significant customers. +5 +Index +Well +Operations and Pipeline Income +The +Company operates approximately 95% of the wells in which it owns an interest. +When the Company owns less than 100% of the working interest in a well, it +charges the other owners a competitive fee for operating the well. These +revenues and the associated costs are reflected in the Well Operations +segment. +Areas +of Operations +The +Company's operations are divided into three regions: the Appalachian Basin, +Michigan, and the Rocky Mountain Region. The Company has conducted operations +in +the Appalachian Basin since its inception in 1969, in Michigan since 1997, +and +in the Rocky Mountain Region since 1999. The Company includes its North Dakota +operations in the Rocky Mountain Region. +In +all +three regions, the Company has historically targeted developmental natural +gas +reserves at depths of less than 10,000 feet. In some areas of the Rocky Mountain +Region, Michigan and the Appalachian Basin, the wells also produce oil in +conjunction with natural gas. Recently the Company has begun to drill to +progressively deeper targets in the Rocky Mountain Region. In particular, the +Company has drilled several wells with depths of more than 12,000 feet and +horizontal wells with a total drilled footage approaching 20,000 feet. The +Company’s management believes these deeper and horizontal wells, although more +expensive to drill, offer attractive economics and reserves. The probability +of +encountering problems when drilling wells at depths greater than 12,000 feet +or +horizontally is generally greater than when drilling a vertical well of lesser +depth. With increasing costs for and declining availability of proved developed +drilling locations, the Company’s management believes the additional risk +associated with exploratory drilling is justified by the potential to generate +additional proved locations at a significantly lower cost than would be required +to purchase proved undeveloped locations. +Business +Strategy +The +Company's primary objective is to increase shareholder value by expanding its +oil and natural gas reserves, production and revenues through a strategy that +includes the following key elements: +Drill +and Develop +Drilling +developmental natural gas wells has been the mainstay of the Company’s drilling +program for a number of years. The Company drilled 231 wells in 2006, compared +to 242 wells in 2005. In addition, the Company seeks to maximize the value +of +its existing wells through a program of well recompletions. The Company’s +management believes that it will be able to drill a substantial number of new +wells on its current undeveloped leased properties. As of December 31, 2006, +the +Company had leases or other development rights to +200 +undeveloped acres in the Michigan Basin, 12,800 undeveloped acres in the +northern Appalachian Basin and 187,500 undeveloped acres in the Rocky Mountain +Region . +The +Company also plans to recomplete about 164 Wattenberg Field wells (Colorado) +during 2007. +To +support future development activities the Company has conducted exploratory +drilling in the past and will continue exploratory drilling plans in 2007. +The +goal of the exploration program is to develop several significant new areas +for +the Company to include in its future development drilling activity. +Acquire +The +Company's acquisition efforts are focused on producing properties that fit +well +within existing operations or in areas where the Company is establishing new +operations. Preferred properties have most of their value in producing wells, +behind pipe reserves or high quality proved undeveloped locations. Acquisitions +have historically offered economies in management and administration costs, +and +the Company’s management believes that with its growing operations staff it can +acquire and manage more producing wells without incurring substantial increases +in its administrative costs. See Notes 2, 15 and 16 to Consolidated Financial +Statements. +Diversify +and Focus +With +operations in the Rocky Mountains, Michigan and the Appalachian Basin, the +Company has proven its ability to grow through operations in geographically +diverse areas. While these areas provide geographic diversification, within +each +area, the Company has concentrated positions that lend themselves to effective +development and operation. The Company plans to conduct the majority of its +drilling activities in the Rocky Mountain Region during 2007, but will continue +to seek additional opportunities for expansion in areas where the Company's +experience and expertise can be applied successfully. +6 +Index +Manage +Risk +The +Company seeks opportunities to reduce the risks inherent in the oil and gas +industry in a variety of ways. For a number of years, an integral part of the +Company's strategy has been to concentrate on development drilling and +geographical diversification to reduce risk levels associated with natural +gas +and oil drilling, production and markets. Development drilling is less risky +than exploratory drilling and is likely to generate cash returns more quickly. +Development drilling will remain the foundation of the Company’s drilling +activities in 2007. However, the Company’s management believes the increasing +cost of high quality development locations has made exploratory drilling +relatively more attractive for future efforts. Exploratory wells have the +potential of identifying new development opportunities at a significantly lower +cost than the current cost of acquiring proven locations. While successful +exploratory efforts could add to the Company’s future drilling opportunities at +favorable costs, under the successful efforts method of accounting, exploratory +dry holes are expensed at the time it is recognized that they are unproductive. +This could result in greater short-term expenses and a reduction in the +near-term profitability of the Company. +To +help +offset the relatively high business risk inherent in the oil and gas industry +the Company maintains a conservative financial structure. The Company’s +management believes that successful natural gas marketing is essential to risk +management and profitable operations in a deregulated gas market. To further +this goal, the Company utilizes RNG to manage the marketing of the Company’s oil +and natural gas and its use of oil and gas commodity derivatives as risk +management tools. This allows the Company to maintain better control over third +party risk in sales and derivative activities. The Company uses natural gas +and +oil derivatives to reduce the effects of volatile energy prices. +Available +Information Posted on the Company's Website +The +Company files Annual Reports on Form 10-K, Quarterly Reports on +Form 10-Q, Current Reports on Form 8-K, registration statements and +other items with the Securities and Exchange Commission ("SEC"). PDC provides +free access to all of these SEC filings, as soon as reasonably practicable +after +filing, on its internet site located at www.petd.com. The Company will also +make +available to any shareholder, without charge, a copy of its Annual Report on +Form 10-K as filed with the SEC. For a copy of the Company’s Annual Report, +or any other filings, please contact: Petroleum Development Corporation, +Investor Relations and Communications Department, P.O. Box 26, Bridgeport, +WV +26330, or call toll free (800) 624-3821. +In +addition to the Company's SEC filings, other information, including the +Company's press releases, current drilling program sales, Bylaws, Committee +Charters, Code of Business Conduct and Ethics, Shareholder Communication Policy, +Board Nomination Procedures and the Whistleblower and Qualified Legal Compliance +Committee Hotline, is also available at the Company’s internet site, +www.petd.com. +The +public may read and copy any materials the Company files with the SEC at the +SEC’s Public Reference Room at 100 F Street, NE, Room 1580, Washington, DC +20549. The public may obtain information on the operation of the Public +Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an +internet site (www.sec.gov) that contains reports, proxies, information +statements and other information regarding issuers, like PDC, that file +electronically with the SEC. +Natural +Gas I ndustry +Overview +Natural +gas is one of the largest energy sources in the United States. The estimated +21.9 Tcf of natural gas consumed in 2006 represented approximately 22% of the +total energy used in the United States. Natural gas is consumed in the United +States as follows: 35% by industrial end-users as feedstock for products such +as +plastic and fertilizer or as the energy source for producing products such +as +glass; 21% and 14% by residential and commercial end-users, respectively, for +uses including heating, cooling and cooking; 28% by utilities for the generation +of electricity; and 2% for other users. (Source U.S. Energy Information +Administration) +The +Company’s management believes that the market for natural gas will continue to +grow in the future. Natural gas burns cleaner than most fossil fuels and +produces less greenhouse gas per unit of energy released. Relative to other +energy sources, natural gas usage and losses during transportation from source +to destination are slight, averaging only about 2% of the natural gas energy. +The delivery of natural gas is among the safest means of distributing energy +to +customers, as the natural gas transmission system is fixed and is located +underground. +The +deregulation of the natural gas industry and a favorable regulatory environment +have resulted in end-users' ability to purchase natural gas on a competitive +basis from a greater variety of sources. Increasing international demand for +petroleum combined with supply constraints kept oil prices near record high +levels throughout 2006. Continuing increases in world energy demand appear +likely in 2007 and beyond. This makes natural gas more competitive in domestic +markets as a replacement for oil and increases the value of domestic oil and +natural gas reserves. +The +Company’s management believes that the foregoing factors, together with the +increased availability of natural gas as a form of energy for residential, +commercial and industrial uses, should increase the demand for natural gas +as +well as create new markets for natural gas, even at prices that are high by +historical standards. +7 +Index +Because +local supplies of natural gas are inadequate to meet demand in some sections +of +the United States, areas including the West Coast and the Northeast import +natural gas from producing areas via interstate natural gas pipelines. The +cost +of transporting natural gas from the major producing areas to markets creates +a +price advantage for production located closer to the consuming regions. Natural +gas producers in the Appalachian Basin and Michigan benefit from proximity +to +the Northeastern and Midwestern United States markets. +In +contrast, much of the production in the Rocky Mountains is transported +significant distances to end user markets. As a result, the price received +for +gas in the Rocky Mountains is generally less than the price received in areas +closer to the primary consuming areas. The Rocky Mountain Region is believed +to +hold substantial undeveloped natural gas resources. Recent and planned additions +to pipeline capacity in the region have made the area more attractive for +development. Although in the near term, gas from the region will generally +sell +for less than gas in the Appalachian and Michigan Basins, development costs +per +Mcfe may be less. +Operations +Exploration +and Development Activities +The +Company's development activities focus on the identification and drilling of +new +productive wells, the acquisition of existing producing wells from other +operators, and maximizing the value of the Company’s current properties through +infill drilling, recompletions, and other production enhancements. +Prospect +Generation +The +Company's staff of professional geologists is responsible for identifying areas +with potential for economic production of natural gas and oil. These geologists +have decades of cumulative experience evaluating prospects and drilling natural +gas and oil wells. They utilize results from logs, seismic data and other tools +to evaluate existing wells and to predict the location of economically +attractive new natural gas and oil reserves. To further this process, the +Company has collected and continues to collect logs, core data, production +information and other raw data available from state and private agencies, other +companies and individuals actively drilling in the regions being evaluated. +From +this information the geologists develop models of the subsurface structures +and +formations that are used to predict areas for prospective economic development. +On +the +basis of these models, the Company's land department obtains available natural +gas and oil leaseholds, farmouts and other development rights in these +prospective areas. In most cases to secure a lease, the Company pays a lease +bonus and annual rental payments, converting, upon initiation of production, +to +a royalty. In addition, overriding royalty payments may be made to third parties +in conjunction with the acquisition of drilling rights initially leased by +others. As of December 31, 2006, the Company had leasehold rights to +approximately 200,500 acres available for development. See "Properties--Oil +and +Natural Gas Leases." +Drilling +Activities +When +prospects have been identified, leased and all regulatory approvals obtained, +the Company develops these properties by drilling wells. In 2006, the Company +drilled a total of 222 development wells, which 216 wells were designated +successful. As of December 31, 2006, 82 of the 216 successful wells were +awaiting gas pipeline connection. As of April 30, 2007, 67 of the wells awaiting +pipeline connection were connected and turned in line. Typically, the Company +will act as driller-operator for these prospects, frequently selling interests +in the wells to Company-sponsored partnerships and other entities that are +interested in exploration or development of the prospects. The Company retains +a +working interest in each well it drills. +The +Company also drilled nine exploratory wells in 2006, eight (including one +pending determination as of December 31, 2006) were determined to be productive +and one was determined to be dry. Costs related to the dry hole of $1.3 million +were expensed in 2006. The Company plans to conduct additional exploratory +drilling activities in 2007. See "Financing of Company Drilling and Development +Activities" and “Drilling and Development Activities Conducted for Company +Sponsored Partnerships” for additional discussion regarding the Company's +drilling activities. +Much +of +the work associated with drilling, completing and connecting wells, including +drilling, fracturing, logging and pipeline construction is performed under +the +Company’s direction by subcontractors specializing in those operations, as is +common in the industry. When judged advantageous, material and services used +by +the Company in the development process are acquired through competitive bidding +by approved vendors. The Company also directly negotiates rates and costs for +services and supplies when conditions indicate that such an approach is +warranted. +8 +Index +The +following tables summarize the Company's development and exploratory drilling +activity for the last five years. There is no correlation between the number +of +productive wells completed during any period and the aggregate reserves +attributable to those wells. +Development +Wells Drilled +Total +Productive +Dry +Drilled +Net +Drilled +Net +Drilled +Net +2002 +70 +13.7 +70 +13.7 +- +- +2003 +110 +28.5 +110 +28.5 +- +- +2004 +157 +43.0 +153 +42.4 +4 +0.6 +2005 +234 +103.4 +232 +102.0 +2 +1.4 +2006 +222 +134.4 +216 +129.8 +6 +4.6 +Total +793 +323.0 +781 +316.4 +12 +6.6 +Exploratory +Wells Drilled +Total +Productive +Dry +Drilled +Net +Drilled +Net +Drilled +Net +2002 +- +- +- +- +- +- +2003 +1 +1.0 +- +- +1 +1.0 +2004 +1 +1.0 +- +- +1 +1.0 +2005 +8 +7.3 +3 +2.3 +5 +5.0 +2006 +9 +3.3 +8 +2.8 +1 +0.5 +Total +19 +12.6 +11 +5.1 +8 +7.5 +Financing +of Company Drilling and Development Activities +The +Company conducts development drilling activities for its own account and acts +as +operator for other owners. When conducting activities for its own account, +the +Company uses cash flow from operations and capital provided from its long term +credit facility to fund its share of operations. +Drilling +and Development Activities Conducted for Company Sponsored +Partnerships +In +addition to wells and interests in wells that it drills for itself, the Company +also acts as operator for other oil and gas owners. Historically, these other +owners have included individuals, corporations, partnerships formed by +non-affiliated parties and other investors. Currently, the Company’s drilling +partners consist primarily of public and private partnerships sponsored by +the +Company. The Company contributes a cash investment to purchase an interest +in +the drilling and development activities and serves as the managing general +partner for each partnership; accordingly, the Company is subject to substantial +cash commitments at the closing of each drilling partnership. +In +1984, +the Company began sponsoring drilling partnerships. The Company-sponsored +partnerships had $90 million in subscriptions in 2006, $116 million in +subscriptions in 2005, and $100 million in subscriptions in 2004. During 2006, +the Company sponsored one drilling partnership to which it contributed $38.9 +million and received a 37% working interest in the partnership. While funds +were +received by the Company pursuant to drilling contracts in the years indicated, +the Company recognizes revenues from drilling operations on the percentage +of +completion method as the wells are drilled, rather than when funds are received. +Substantially all of the Company's drilling and development funds are now +received from partnerships in which the Company serves as managing general +partner. However, because wells produce for a number of years, the Company +continues to serve as operator for a number of unaffiliated parties. The Company +plans to offer $110 million in subscriptions through a private placement in +2007. +The +Company enters into a development agreement with an investor partner, pursuant +to which the Company agrees to sell some or all of its rights in a well to +be +drilled to the partnership or other entity. The partnership or other entity +thereby becomes owner of a working interest in the well. +The +Company's drilling contracts with its investor partners have historically taken +many different forms. Beginning with the last Company-sponsored partnership +of +2005 (for which revenue generating activities did not commence until early +2006), partnership wells are drilled on a “cost-plus” basis, whereby the Company +bills investors for the actual cost of the wells plus an agreed upon mark-up +above the costs. In the past the drilling contracts could be classified as +on a +footage-based rate, whereby the Company received drilling and completion +payments based on the depth of the well. The Company may also purchase an +additional working interest in the partnership properties. In its financial +reporting, the Company reports only its proportionate share of oil and gas +reserves, production, oil and gas sales and costs associated with wells in +which +other investors participate. The level of the Company's drilling and development +activity is dependent upon the amount of subscriptions in its public drilling +partnerships and investments from other partnerships or other joint venture +partners. Accepting investments from third party investors and Company sponsored +partnerships enables the Company to diversify its holdings, thereby reducing +the +risk of the Company’s investments. The Company’s management believes that +investments in drilling activities, whether through Company-sponsored +partnerships or other sources, are influenced in part by the favorable treatment +that such limited partner investments receive under the federal income tax +laws. +No assurance can be given that the Company will continue to have access to +funds +generated through these financing vehicles or that the favorable tax treatment +will continue. +9 +Index +Purchases +of Producing Properties +In +addition to drilling new wells, the Company continues to pursue opportunities +to +purchase existing wells from other owners, as well as greater ownership +interests in the wells it operates. Generally, outside interests purchased +include a majority interest in the wells and the right to operate the wells. +During 2006, the Company successfully acquired the stock of Unioil, Inc., a +small independent producer with properties primarily in the Wattenberg Field +in +Colorado, for a total of $18.6 million. In addition, in January 2007, the +Company completed the purchase of approximately 144 oil and gas wells and 8,160 +acres of leaseholds in the Wattenberg Field from EXCO Resources. Also in January +2007, the Company purchased the outside partnership interests in 44 partnerships +which had been formed primarily in the late 1980s and 1990s. These interests +constituted the majority of the interests in 718 wells, primarily in the +Appalachian and Michigan Basins. In February 2007, the Company acquired 28 +producing wells and associated undeveloped acreage in Colorado for $11.8 +million. +Production +The +following table shows the Company's net production in thousands of barrels +("MBbl") of crude oil and in million cubic feet ("MMcf") of natural gas and +the +costs and weighted average selling prices of oil in barrels (Bbl) and gas in +thousands of cubic feet (Mcf). +Year +Ended December 31, +2006 +2005 +2004 +2003 +2002 +Production +(1): +Oil +(MBbl) +631 +439 +381 +289 +227 +Natural +Gas (MMcf) +13,161 +11,031 +10,372 +8,712 +6,462 +Equivalent +(MMcfe) (2) +16,949 +13,665 +12,659 +10,449 +7,824 +Average +sales price: +Oil +(per Bbl) (3) +$ +59.33 +$ +50.56 +$ +38.00 +$ +29.43 +$ +24.41 +Natural +gas (per Mcf) (3) +$ +5.91 +$ +7.29 +$ +5.30 +$ +4.58 +$ +2.65 +Equivalent +average sales price (per Mcfe) +$ +6.80 +$ +7.51 +$ +5.49 +$ +4.63 +$ +2.90 +Average +production cost (lifting cost) +Per +equivalent (Mcfe) (4) +$ +1.23 +$ +1.19 +$ +1.12 +$ +0.93 +$ +0.76 +(1) +Production +as shown in the table is net to the Company and is determined by +multiplying the gross production volume of properties in which the +Company +has an interest by the percentage of the leasehold or other property +interest owned by the Company. +(2) +A +ratio of energy content of natural gas and oil (six Mcf of natural +gas +equals one barrel of oil) was used to obtain a conversion factor +to +convert oil production into equivalent Mcf of natural +gas. +(3) +The +Company utilizes commodity based derivative instruments to manage +a +portion of its exposure to price volatility of its natural gas and +oil +sales. The above table does not include the results of derivative +transactions. +(4) +Production +costs represent oil and gas operating expenses which include severance +and +ad valorem taxes as reflected in the financial statements of the +Company. +See “Oil and Gas Production and Well Operations Costs” in Management's +Discussion and Analysis. +Natural +Gas Sales +Natural +gas produced by the Company’s well interests is generally sold under contracts +with monthly pricing provisions. Virtually all of the Company's contracts +include provisions wherein prices change monthly with changes in the market +with +certain adjustments based on, among other factors, whether a well delivers +to a +gathering or transmission line, quality of natural gas and prevailing supply +and +demand conditions, so that the price of the natural gas fluctuates to remain +competitive with other available natural gas supplies. As a result, the +Company's revenues from the sale of natural gas will suffer if market prices +decline and benefit if they increase. The Company’s management believes that the +pricing provisions of its natural gas contracts are customary in the +industry. +10 +Index +The +Company sells its natural gas to industrial end-users, utilities, other gas +marketers, and other wholesale gas purchasers. During 2006, natural gas produced +by the Company was sold at prices ranging from $2.26 to $15.70 per Mcf, +depending upon well location, the date of the sales contract and other factors. +The weighted net average price of natural gas sold by the Company during 2006 +was +$5.91 +per +Mcf. +In +general, the Company, together with its marketing subsidiary, RNG, has been +and +expects to continue to be able to produce and sell natural gas from its wells +without significant curtailment by providing natural gas to purchasers at +competitive prices. Open access transportation through the country's interstate +pipeline system makes a broad range of markets accessible to the Company. +Whenever feasible, the Company obtains access to multiple pipelines and markets +from each of its gathering systems seeking the best available market for its +natural gas at any point in time. +Oil +Sales +The +majority of the Company's wells in the Wattenberg Field in Colorado and the +Company's North Dakota wells produce oil in addition to natural gas. As of +December 31, 2006, oil represented about 13% of the Company's total equivalent +reserves and accounted for approximately 33% of the Company's oil and gas sales +for the year ended December 31, 2006. +The +Company is currently able to sell all the oil that it can produce under existing +sales contracts with petroleum refiners and marketers. The Company does not +refine any of its oil production. The Company's crude oil production is sold +to +purchasers at or near the Company's wells under short-term purchase contracts. +During 2006, oil produced by the Company sold at prices ranging from +$53.75 to +$71.77 +per barrel, depending upon the location and quality of oil. In 2006, the +weighted net average price per barrel of oil sold by the Company was +$59.33. +Oil +production is subject to many of the same operating hazards and environmental +concerns as natural gas production, but is also subject to the risk of oil +spills. Federal regulations require certain owners or operators of facilities +that store or otherwise handle oil, including the Company, to procure and +implement Spill Prevention, Control and Counter-measures ("SPCC") plans relating +to the possible discharge of oil into surface waters. The Oil Pollution Act +of +1990 ("OPA") subjects owners of facilities to strict joint and several liability +for all containment and cleanup costs and certain other damages arising from +oil +spills. Noncompliance with OPA may result in varying civil and criminal +penalties and liabilities. Operations of the Company are also subject to the +Federal Clean Water Act and analogous state laws relating to the control of +water pollution, which laws provide varying civil and criminal penalties and +liabilities for release of petroleum or its derivatives into surface waters +or +into the ground. +Natural +Gas Marketing +The +Company's natural gas marketing activities involve the purchase of natural +gas +from other producers and the sale of that natural gas along with natural gas +produced by the Company. The Company’s management believes that in a deregulated +market, successful natural gas marketing is an essential component of profitable +operations. A variety of factors affect the market for natural gas, including +the availability of other domestic production, natural gas imports, the +availability and price of alternative fuels, the proximity and capacity of +natural gas pipelines, general fluctuations in the supply and demand for natural +gas, and the effects of state and federal regulations on natural gas production +and sales. The natural gas industry also competes with other industries in +supplying the energy and fuel requirements of industrial, commercial and +individual customers. +RNG, +a +wholly owned subsidiary, is a natural gas marketing company that specializes +in +the purchase, aggregation and sale of natural gas production in the Company's +Eastern operating areas. RNG markets natural gas produced by the Company and +also purchases natural gas from other producers and resells to utilities, end +users or other marketers. The employees of RNG have extensive knowledge of +natural gas markets in the Company's areas of operations. Such knowledge assists +the Company in maximizing its prices as it markets natural gas from +Company-operated wells. The gas is marketed to natural gas utilities, industrial +and commercial customers as well as other marketers, either directly through +the +Company's gathering system, or utilizing transportation services provided by +regulated interstate pipeline companies. +Commodity +Risk Management Activities +The +Company utilizes commodity based derivative instruments to manage a portion +of +the exposure to price volatility stemming from its oil and natural gas sales +and +marketing activities. These instruments consist of over the counter swaps and +options and NYMEX-traded natural gas futures and option contracts for +Appalachian and Michigan production and Colorado Interstate Gas Index ("CIG") +and Panhandle Eastern Pipeline ("PEPL")-based contracts for Colorado natural +gas +production and NYMEX traded oil futures and option contracts for Colorado oil +production. The Company may utilize derivatives based on other indices or +markets where appropriate. The contracts economically provide price protection +for committed and anticipated natural gas purchases and sales and anticipated +oil sales, generally forecasted to occur within the next two to three year +period. Company policy prohibits the use of natural gas or oil futures or +options for speculative purposes and permits utilization of derivatives only +if +there is an underlying physical position. +11 +Index +RNG +has +extensive experience with the use of cash-settled derivatives to reduce the +risk +and impact of natural gas price changes. These financial derivatives are used +by +RNG to coordinate fixed purchases and sales, and by the Company to establish +"floors" and "ceilings" or "collars" on the possible range of the prices +realized for the sale of natural gas and oil. RNG also enters into back-to-back +fixed-price purchases and sales contracts with counterparties. These fixed +physical contracts meet the FAS 133 definition of a derivative. Both types +of +derivatives (i.e., the physical deals and the cash settled contracts) are +carried on the balance sheet at fair value with changes in fair values +recognized currently in the income statement. +The +Company is subject to price fluctuations for natural gas sold in the spot market +and under market index contracts. The Company continues to evaluate the +potential for reducing these risks by entering into derivative transactions. +In +addition, the Company may close out any portion of derivatives that may exist +from time to time which may result in a realized gain or loss on that derivative +transaction. The Company economically manages the price risk on only a portion +of its anticipated production, so some of the production is subject to the +full +fluctuation of market pricing. +Well +Operations +At +December 31, 2006, the Company had an interest in approximately 1,365 wells +in +the Appalachian Basin, 206 wells in the Michigan Basin and 1,530 wells in the +Rocky Mountain Region. The Company's ownership interest in these wells ranges +from greater than 0% to 100% and, on average, the Company has an approximate +51.4% ownership interest in the wells it operates. +The +Company is paid a monthly operating fee for each well it operates for the +portion of these wells owned by others, including the limited partnerships +sponsored by the Company. The fee is competitive with rates charged by other +operators in the area. The fee covers monthly operating and accounting costs, +insurance and other recurring costs. The Company may also receive additional +compensation, at competitive rates, for special non-recurring activities, such +as reworks and recompletions. +Transportation +Natural +gas wells are connected by pipelines to natural gas markets. Over the years, +the +Company has developed, owns and operates gathering systems in some of its areas +of operations. The Company also continues to construct new trunk lines as +necessary to provide for the marketing of natural gas being developed from +new +areas and to enhance or maintain its existing systems. +Governmental +Regulation +While +the +price of natural gas is set by the market, other aspects of the Company's +business and the natural gas industry in general are heavily regulated. The +availability of a ready market for natural gas production depends on several +factors beyond the Company's control. These factors include regulation of +natural gas production, federal and state regulations governing environmental +quality and pollution control, the amount of natural gas available for sale, +the +availability of adequate pipeline and other transportation and processing +facilities and the marketing of competitive fuels. State and federal regulations +generally are intended to protect consumers from unfair treatment, control +and +reduce the risk to the public and workers from the drilling, completion, +production and transportation of oil and natural gas, prevent waste of natural +gas, protect rights to produce natural gas between owners in a common reservoir +and control contamination of the environment. Pipelines are subject to the +jurisdiction of various federal, state and local agencies. In the western part +of the United States, the federal and state governments own a large percentage +of the land and the rights to develop oil and natural gas. Recently the Company +has increased its positions in these types of leases. Generally, government +leases are subject to additional regulations and controls not commonly seen +on +private leases. The Company takes the steps necessary to comply with applicable +regulations both on its own behalf and as part of the services it provides +to +its investor partnerships. The Company’s management believes that it is in +compliance with such statutes, rules, regulations and governmental orders, +although there can be no assurance that this is or will remain the case. The +following discussion of the regulation of the United States natural gas industry +is not intended to constitute a complete discussion of the various statutes, +rules, regulations and environmental orders to which the Company's operations +may be subject. +Regulation +of Oil and Natural Gas Exploration and Production +The +Company's exploration and production business is subject to various +federal, state and local laws and regulations on taxation, the development, +production and marketing of oil and gas, and environmental and safety matters. +Many laws and regulations require drilling permits and govern the spacing of +wells, rates of production, water discharge, prevention of waste and other +matters. Prior +to +commencing drilling activities for a well, the Company must procure permits +and/or approvals for the various stages of the drilling process from the +applicable state and local agencies in the state in which the area to be drilled +is located. The permits and approvals include those for the drilling of wells, +and the regulation includes maintaining bonding requirements in order to drill +or operate wells and regulating the location of wells, the method of drilling +and casing wells, the surface use and restoration of properties on which wells +are drilled, the plugging and abandoning of wells and the disposal of fluids +used in connection with operations. The Company's operations are also subject +to +various conservation laws and regulations. These include the regulation of +the +size of drilling and spacing units or proration units and the density of wells +which may be drilled and the unitization or pooling of properties. In this +regard, some states allow the forced pooling or integration of tracts to +facilitate exploration while other states rely primarily or exclusively on +voluntary pooling of lands and leases. In areas where pooling is voluntary, +it +may be more difficult to form units, and therefore, more difficult to develop +a +project if the operator owns less than 100% of the leasehold. In addition, +state +conservation laws may establish maximum rates of production from oil and natural +gas wells, generally prohibiting the venting or flaring of natural gas and +imposing certain requirements regarding the ratability of production. Where +wells are to be drilled on state or federal leases, additional regulations +and +conditions may apply. The effect of these regulations may limit the amount +of +oil and natural gas the Company can produce from its wells and may limit the +number of wells or the locations at which the Company can drill. Such +laws +and regulations have increased the costs of planning, designing, drilling, +installing, operating and abandoning the Company’s oil and gas wells and other +facilities. In addition, these laws and regulations, and any others that are +passed by the jurisdictions where the Company has production, could limit the +total number of wells drilled or the allowable production from successful wells, +which could limit its reserves. +Inasmuch +as such laws and regulations are frequently expanded, amended and reinterpreted, +the Company is unable to predict the future cost or impact of complying with +such regulations. +12 +Index +Regulation +of Sales and Transportation of Natural Gas +Historically, +the price of natural gas was subject to limitation by federal legislation. +The +Natural Gas Wellhead Decontrol Act (the "Decontrol Act") removed, as of January +1, 1993, all remaining federal price controls from natural gas sold in "first +sales" on or after that date. The Federal Energy Regulatory Commission +("FERC")'s jurisdiction over natural gas transportation was unaffected by the +Decontrol Act. While sales by producers of natural gas and all sales of crude +oil, condensate and natural gas liquids can currently be made at market prices, +there are a number of proposed bills in the United States Congress to reenact +price controls or impose “windfall profits” or similar taxes in the future on +oil and gas prices. The passage of one of those bills or similar legislation +could have the impact of reducing the price received by the Company for its +production, or substantially increasing the tax burden associated with its +production operations. +The +Company moves gas through pipelines owned by other companies, and sells gas +to +other companies that also utilize common carrier pipeline facilities. Gas +pipeline interstate transmission and storage activities are subject to +regulation by the FERC under the Natural Gas Act of 1938 ("NGA") and under +the Natural Gas Policy Act of 1978, and, as such, rates and charges for the +transportation of natural gas in interstate commerce, accounting, and the +extension, enlargement or abandonment of its jurisdictional facilities, among +other things, are subject to regulation. Each gas pipeline company holds +certificates of public convenience and necessity issued by the FERC authorizing +ownership and operation of all pipelines, facilities and properties for which +certificates are required under the NGA. Each gas pipeline company is also +subject to the Natural Gas Pipeline Safety Act of 1968, as amended, which +regulates safety requirements in the design, construction, operation and +maintenance of interstate natural gas transmission facilities. FERC Order 2004 +“Standards of Conduct for Transmission Providers” governs how interstate +pipelines communicate and do business with their energy affiliates. One of +the +cornerstones of Order 2004 is that interstate pipelines will not operate their +pipeline systems to preferentially benefit their energy affiliates. +Each +interstate natural gas pipeline company establishes its rates primarily through +the FERC’s ratemaking process. Key determinants in the ratemaking process +are: +• +costs +of providing service, including depreciation +expense; +• +allowed +rate of return, including the equity component of the capital structure +and related income taxes; +• +volume +throughput assumptions. +The +Company's sales of natural gas are affected by the availability, terms and +cost +of transportation. In the past, FERC has undertaken various initiatives to +increase competition within the natural gas industry. As a result of initiatives +like FERC Order No. 636, issued in April 1992, the interstate natural gas +transportation and marketing system was substantially restructured to remove +various barriers and practices that historically limited non-pipeline natural +gas sellers, including producers, from effectively competing with interstate +pipelines for sales to local distribution companies and large industrial and +commercial customers. The most significant provisions of Order No. 636 require +that interstate pipelines provide transportation separate or "unbundled" from +their sales service, and require that pipelines provide firm and interruptible +transportation service on an open access basis that is equal for all natural +gas +suppliers. In many instances, the result of Order No. 636 and related +initiatives has been to substantially reduce or eliminate the interstate +pipelines' traditional role as wholesalers of natural gas in favor of providing +only storage and transportation services. Another effect of regulatory +restructuring is the greater transportation access available on interstate +pipelines. In some cases, producers and marketers have benefited from this +availability. However, competition among suppliers has greatly increased and +traditional long-term producer-pipeline contracts are rare. Furthermore, +gathering facilities of interstate pipelines are no longer regulated by FERC, +thus allowing gatherers to charge higher gathering rates. +13 +Index +Additional +proposals and proceedings that might affect the natural gas industry occur +frequently in Congress, FERC, state commissions, state legislatures, 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 FERC and Congress will continue. The Company cannot +determine to what extent future operations and earnings of the Company will +be +affected by new legislation, new regulations, or changes in existing regulation, +at federal, state or local levels. +Environmental +Regulations +The +Company's operations are subject to numerous laws and regulations governing +the +discharge of materials into the environment or otherwise relating to +environmental protection. Public interest in the protection of the environment +has increased dramatically in recent years. The trend of more expansive and +stricter environmental legislation and regulations could continue. To the extent +laws are enacted or other governmental action is taken that restricts drilling +or imposes environmental protection requirements that result in increased costs +and reduced access to the natural gas industry in general, the business and +prospects of the Company could be adversely affected. +The +Company generates wastes that may be subject to the Federal Resource +Conservation and Recovery Act ("RCRA") and comparable state statutes. The U.S. +Environmental Protection Agency ("EPA") and various state agencies have limited +the approved methods of disposal for certain hazardous and non-hazardous wastes. +Furthermore, certain wastes generated by the Company's operations that are +currently exempt from treatment as "hazardous wastes" may in the future be +designated as "hazardous wastes," and therefore be subject to more rigorous +and +costly operating and disposal requirements. +The +Company currently owns or leases numerous properties that for many years have +been used for the exploration and production of oil and natural gas. Although +the Company’s management believes that it has utilized good operating and waste +disposal practices, prior owners and operators of these properties may not +have +utilized similar practices, and hydrocarbons or other wastes may have been +disposed of or released on or under the properties owned or leased by the +Company or on or under locations where such wastes have been taken for disposal. +These properties and the wastes disposed thereon may be subject to the +Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), +RCRA and analogous state laws as well as state laws governing the management +of +oil and natural gas wastes. Under such laws, the Company 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) or to perform remedial plugging operations to prevent +future contamination. +CERCLA +and similar state laws impose liability, without regard to fault or the legality +of the original conduct, on certain classes of persons that are considered +to +have contributed to the release of a "hazardous substance" into the environment. +These persons include the owner or operator of the disposal site or sites where +the release occurred and companies that disposed of or arranged for the disposal +of the hazardous substances found at the site. Persons who are or were +responsible for release of 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, and 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. +The +Company's operations may be subject to the Clean Air Act ("CAA") and comparable +state and local requirements. Amendments to the CAA were adopted in 1990 and +contain provisions that may result in the gradual imposition of certain +pollution control requirements with respect to air emissions from the operations +of the Company. The EPA and states have been developing regulations to implement +these requirements. The Company may be required to incur certain capital +expenditures in the next several years for air pollution control equipment +in +connection with maintaining or obtaining operating permits and approvals +addressing other air emission-related issues. +The +Company's expenses relating to preserving the environment during 2006 were +not +significant in relation to operating costs and the Company expects no material +change in 2007. Environmental regulations have had no materially adverse effect +on the Company's operations to date, but no assurance can be given that +environmental regulations will not, in the future, result in a curtailment +of +production or otherwise have a materially adverse effect on the Company's +business, financial condition or results of operations. +14 +Index +Operating +Hazards and Insurance +The +Company's exploration and production operations include a variety of operating +risks, including the risk of fire, explosions, blowouts, cratering, pipe +failure, casing collapse, abnormally pressured formations, and environmental +hazards such as gas leaks, ruptures and discharges of toxic gas, the occurrence +of any of which could result in substantial losses to the Company due to injury +and loss of life, severe damage to and destruction of property, natural +resources and equipment, pollution and other environmental damage, clean-up +responsibilities, regulatory investigation and penalties and suspension of +operations. The Company's pipeline, gathering and distribution operations are +subject to the many hazards inherent in the natural gas industry. These hazards +include damage to wells, pipelines and other related equipment, and surrounding +properties caused by hurricanes, floods, fires and other acts of God, +inadvertent damage from construction equipment, leakage of natural gas and +other +hydrocarbons, fires and explosions and other hazards that could also result +in +personal injury and loss of life, pollution and suspension of +operations. +Any +significant problems related to its facilities could adversely affect the +Company's ability to conduct its operations. In accordance with customary +industry practice, the Company maintains insurance against some, but not all, +potential risks; however, there can be no assurance that such insurance will +be +adequate to cover any losses or exposure for liability. The occurrence of a +significant event not fully insured against could materially adversely affect +the Company's operations and financial condition. The Company cannot predict +whether insurance will continue to be available at premium levels that justify +its purchase or whether insurance will be available at all. +Competition +The +Company’s management believes that its exploration, drilling and production +capabilities and the experience of its management and professional staff +generally enable it to compete effectively. The Company encounters competition +from numerous other oil and natural gas companies, drilling and income programs +and partnerships in all areas of its operations, including drilling and +marketing oil and natural gas and obtaining desirable oil and natural gas leases +and producing properties. Many of these competitors possess larger staffs and +greater financial resources than the Company, which may enable them to identify +and acquire desirable producing properties and drilling prospects more +economically. The Company's ability to explore for oil and natural gas prospects +and to acquire additional properties in the future depends upon its ability +to +conduct its operations, to evaluate and select suitable properties and to +consummate transactions in this highly competitive environment. The Company +competes with a number of other companies that offer interests in drilling +partnerships with a wide range of investment objectives and program structures. +Competition for investment capital for both public and private drilling programs +is intense. The Company also faces intense competition in the marketing of +natural gas from competitors including other producers as well as marketing +companies. Also, international developments and the possible improved economics +of domestic natural gas exploration may influence other companies to increase +their domestic oil and natural gas exploration. Furthermore, competition among +companies for favorable prospects can be expected to continue, and it is +anticipated that the cost of acquiring properties may increase in the future. +During 2006, the industry experienced continued strong demand for drilling +services and supplies. This is resulting in increasing costs, and in some cases +the demand for supplies and services exceeds the available supplies. This can +result in higher well costs and delays in the execution of planned drilling +operations. Factors affecting competition in the oil and natural gas industry +include price, location of drilling, availability of drilling prospects and +drilling rigs, pipeline capacity, quality of production and volumes produced. +The Company’s management believes that it can compete effectively in the oil and +natural gas industry on each of the foregoing factors. Nevertheless, the +Company's business, financial condition or results of operations could be +materially adversely affected by competition. +Employees +As +of +December 31, 2006, the Company had 189 employees, including 104 in production +and seven in natural gas marketing, 32 in exploration and development, 31 in +finance, accounting and data processing, and 15 in administration. The Company's +engineers, supervisors and well tenders are responsible for the day-to-day +operation of wells and pipeline systems. In addition, the Company retains +subcontractors to perform drilling, fracturing, logging, and pipeline +construction functions at drilling sites, with the Company's employees +supervising the activities of the subcontractors. In 2006, the total number +of +Company employees increased by 39. +The +Company's employees are not covered by a collective bargaining agreement. The +Company considers relations with its employees to be excellent. +ITE M +1A. RISK FACTORS +You +should carefully consider the following risk factors in addition to the other +information included in this report. Each of these risk factors could adversely +affect the Company’s business, operating results and financial condition, as +well as adversely affect the value of an investment in its common stock or +other +securities. +15 +Index +Oil +and natural gas prices fluctuate unpredictably and a decline in oil and natural +gas prices can significantly affect the Company’s financial results and impede +its growth. +The +Company’s revenue, profitability and cash flow depend in large part upon the +prices and demand for oil and natural gas. The markets for these commodities +are +very volatile and even relatively modest drops in prices can significantly +affect the Company’s financial results and impede its growth. Changes in oil and +natural gas prices have a significant impact on the value of the Company’s +reserves and on its cash flow. Prices for oil and natural gas may fluctuate +widely in response to relatively minor changes in the supply of and demand +for +oil and natural gas, market uncertainty and a variety of additional factors +that +are beyond the Company’s control, including national and international economic +and political factors and federal and state legislation. +The +prices of oil and natural gas are quite volatile, often fluctuating greatly. +Lower oil and natural gas prices may not only reduce the Company’s revenues, but +also may reduce the amount of oil and natural gas that the Company can produce +economically. This may result in the Company having to make substantial downward +adjustments to its estimated proved reserves. If this occurs or if the Company’s +estimates of development costs increase, production data factors change or +the +Company’s exploration results deteriorate, accounting rules may require the +Company to write-down operating assets to fair value, as a non-cash charge +to +earnings. The +Company assesses impairment of capitalized costs of proved oil and gas +properties by comparing net capitalized costs to estimated undiscounted future +net cash flows on a field-by-field basis using estimated production based upon +prices at which management reasonably estimates such products to be sold. +The +Company may incur impairment charges in the future, which could have a material +adverse effect on its results of operations. +The +Company’s estimated oil and gas reserves are based on many assumptions that may +turn out to be inaccurate. Any material inaccuracies in these reserve estimates +or underlying assumptions may materially affect the quantities and present +value +of the Company’s reserves. +No +one +can measure underground accumulations of oil and natural gas in an exact way. +Oil and natural gas reserve engineering requires subjective estimates of +underground accumulations of oil and natural gas and assumptions concerning +future oil and natural gas prices, production levels, and operating and +development costs over the economic life of the properties. As a result, +estimated quantities of proved reserves and projections of future production +rates and the timing of development expenditures may be inaccurate. The +Company’s estimates of oil and gas reserves are prepared by independent +petroleum engineers, using pricing, production, cost, tax and other information +provided by the Company. The reserve estimates are based on certain assumptions +regarding future oil and natural gas prices, production levels, and operating +and development costs that may prove incorrect. Any significant variance from +these assumptions to actual figures could greatly affect the estimates of +reserves, the economically recoverable quantities of oil and natural gas +attributable to any particular group of properties, future depreciation, +depletion and amortization rates and amounts, the classifications of reserves +based on risk of recovery, and estimates of the future net cash flows. Some +of +the Company’s reserve estimates must be made with limited production history, +which renders these reserve estimates less reliable than estimates based on +a +lengthy production history. Numerous changes over time to the assumptions on +which the reserve estimates are based, as described above, often result in +the +actual quantities of oil and gas recovered being different from earlier reserve +estimates. +The +present value of estimated future net cash flows from proved reserves is not +necessarily the same as the current market value of the estimated oil and +natural gas reserves (the Securities and Exchange Commission requires the use +of +year end prices). The estimated discounted future net cash flows from proved +reserves are based on selling prices in effect on the day of estimate (year +end) +and future estimated costs. However, actual future net cash flows from the +Company’s oil and natural gas properties also will be affected by factors such +as actual prices it receives for oil and natural gas and hedging instruments, +the amount and timing of actual production, amount and timing of future +development costs, supply of and demand for oil and natural gas, and changes +in +governmental regulations or taxation. +The +timing of both the Company’s production and incurrence of expenses in connection +with the development and production of oil and natural gas properties will +affect the timing of actual future net cash flows from proved reserves, and +thus +their actual present value. In addition, the 10% discount factor (the rate +required by the Securities and Exchange Commission) the Company uses when +calculating discounted future net cash flows may not be the most appropriate +discount factor based on interest rates currently in effect and risks associated +with its oil and gas properties or the oil and natural gas industry in general. +16 +Index +Unless +oil and natural gas reserves are replaced as they are produced, the Company’s +reserves and production will decline, which would adversely affect the Company’s +future business, financial condition and results of +operations. +Producing +oil and natural gas reservoirs generally are characterized by declining +production rates that vary depending upon reservoir characteristics and other +factors. The rate of decline will change if production from existing wells +declines in a different manner than the Company has estimated and can change +due +to other circumstances. Thus, the Company’s future oil and natural gas reserves +and production and, therefore, its cash flow and income are highly dependent +on +efficiently developing and exploiting the Company’s current reserves and +economically finding or acquiring additional recoverable reserves. The Company +may not be able to develop, discover or acquire additional reserves to replace +its current and future production at acceptable costs. As a result, the +Company's future operations, financial condition and results of operations +would +be adversely affected. +Prospects +drilled by the Company may not yield natural gas or oil in commercially viable +quantities. +A +prospect is a property on which the Company's geologists have identified what +they believe, based on available information, to be indications of natural +gas +or oil bearing rocks. However, the use of available data and other technologies +and the study of producing fields in the same area will not enable the +geologists to know conclusively prior to drilling and testing whether natural +gas or oil will be present or, if present, whether natural gas or oil will +be +present in sufficient quantities to repay drilling or completion costs and +generate a profit. If a well is determined to be dry or uneconomic, which can +occur even though it contains some oil or gas, it is classified as a dry hole +and must be plugged and abandoned in accordance with applicable regulations. +This generally results in the loss of the entire cost of drilling and completion +to that point, the cost of plugging, and lease costs associated with the +prospect. Even wells that are completed and placed into production may not +produce sufficient oil and gas to be profitable. If the Company drills a dry +hole or non-profitable well on current and future prospects, the profitability +of its operations will decline and the value of the Company will likely be +reduced. In sum, the cost of drilling, completing and operating any well is +often uncertain and new wells may not be productive. +The +Company may not be able to identify enough attractive prospects on a timely +basis to meet its own development needs and those of the partnerships it forms +for investors, which could limit the Company’s development opportunities and/or +force it to reduce partnership activity. +The +Company’s geologists have identified a number of potential drilling locations on +existing acreage. These drilling locations must be replaced as they are drilled +for the Company to continue to grow its reserves and production, and for it +to +be able to continue its partnership drilling activities. The Company’s ability +to identify and acquire new drilling locations depends on a number of +uncertainties, including the availability of capital, regulatory approvals, +oil +and natural gas prices, competition, costs, availability of drilling rigs, +drilling results and the ability of the Company’s geologists to successfully +identify potentially successful new areas to develop. Because of these +uncertainties, the Company’s profitability and growth opportunities may be +limited by the timely availability of new drilling locations, and it could +be +forced to terminate or curtail its partnership activities because of a lack +of +suitable prospects for the partnerships. As +a +result, the Company's operations and profitability could be adversely +affected. +Drilling +for and producing oil and natural gas are high risk activities with many +uncertainties that could adversely affect the Company’s business, financial +condition and results of operations. +Drilling +activities are subject to many risks, including the risk that the Company will +not discover commercially productive reservoirs. Drilling for oil and natural +gas can be unprofitable, not only from dry holes, but from productive wells +that +do not produce sufficient revenues to return a profit. In addition, drilling +and +producing operations may be curtailed, delayed or canceled as a result of other +factors, including unusual or unexpected geological formations, pressures, +fires, blowouts, loss of drilling fluid circulation, title problems, facility +or +equipment malfunctions, unexpected operational events, shortages or delivery +delays of equipment and services, compliance with environmental and other +governmental requirements, and adverse weather conditions. +Any +of +these risks can cause substantial losses, including personal injury or loss +of +life, damage to or destruction of property, natural resources and equipment, +pollution, environmental contamination or loss of wells and regulatory +penalties. The Company maintains insurance against various losses and +liabilities arising from operations; however, insurance against all operational +risks is not available. Additionally, the Company management may elect not +to +obtain insurance if the cost of available insurance is excessive relative to +the +perceived risks presented. Thus, losses could occur for uninsurable or uninsured +risks or in amounts in excess of existing insurance coverage. The occurrence +of +an event that is not fully covered by insurance could have a material adverse +impact on the Company’s business activities, financial condition and results of +operations. +17 +Index +Increased +drilling activity, particularly in the Rocky Mountain Region, may create a +shortage of drilling rigs, service providers, or materials, forcing the Company +to curtail its drilling operations for itself and its partnerships thereby +reducing revenue and profits from new oil and gas wells and from the Company’s +drilling and completion activities. +With +high +levels of oil and gas prices, many oil and gas companies have increased their +levels of drilling and completing new wells and reworking old wells. At the +same +time there is a limited supply of drilling rigs, completion equipment and +qualified personnel to provide the services necessary to drill, complete and +rework new wells. In particular, the Rocky Mountain Region has seen a great +increase in activity over the past few years. If the demand for these goods +and +services continues to increase, shortages may develop, which could result in +increased prices for these goods and services or the Company’s inability to +complete all of the drilling it has planned. This could result in less drilling +by the Company and the temporary or permanent loss of part or all of its +partnership drilling activity and less profitability for the Company. +The +Company’s drilling and development segment receives virtually all of its revenue +from the partnerships it sponsors, and a reduction or loss of that business +could reduce or eliminate the revenue and profits associated with those +activities. +The +Company’s drilling margins associated with its limited partnership programs are +dependent upon the capital raised by the Company as a sponsor of limited +partnerships. The Company sells oil and natural gas partnerships through a +network of non-affiliated NASD broker dealers. The largest of those broker +dealers sold about 11% of the partnership units in 2006. Investors in the +partnerships benefit from the tax deductions generated by the intangible +drilling costs and the cash flow generated by the partnerships. If the tax +laws +were changed to reduce or eliminate the tax advantages, if the cash flow from +the partnerships were to decline due to poor performing wells or lower energy +prices, or if the brokers decide to stop offering the Company’s partnerships for +some reason, the sales of the partnership units would decline, reducing or +eliminating the revenue and profits associated with the drilling and development +business segment. As a result, the Company's operations and profitability would +be adversely affected. +Under +the Successful Efforts accounting method used by the Company unsuccessful +exploratory wells must be expensed in the period when they are determined to +be +non-productive which results in a reduction of the Company's net income and +profitability and could have a negative impact on the Company’s stock +price. +The +Company conducted exploratory drilling in 2006 and plans to continue exploratory +drilling in 2007 in order to identify additional opportunities for future +development. Under the "successful efforts" method of accounting used by the +Company, the cost of unsuccessful exploratory wells must be charged to expense +in the period when they are determined to be unsuccessful. In addition lease +costs for acreage condemned by the unsuccessful well must also be expensed. +In +contrast, unsuccessful development wells are capitalized as a part of the +investment in the field where they are located. Because exploratory wells +generally are more likely to be unsuccessful than development wells, the Company +anticipates that some or all of its exploratory wells may not be productive. +The +costs of such unsuccessful exploratory wells could result in a significant +reduction in the Company’s profitability in periods when the costs are required +to be expensed. +The +Company may incur substantial impairment write-down, if the price of oil and +natural gas declines or due to revisions in its estimates of its +reserves. +If +oil +and natural gas prices decline, if development costs exceed previous estimates, +or if management's estimate of the recoverable reserves on a property is revised +downward, the Company may be required to record additional non-cash impairment +write-downs in the future, which would result in a negative impact to its +financial position. The Company reviews its proved oil and gas properties for +impairment on a quarterly basis. To determine if a depletable unit is impaired, +the Company compares the carrying value of the depletable unit to the +undiscounted future net cash flows by applying management's estimates of future +oil and gas prices to the estimated future production of oil and gas reserves +over the economic life of the property. Future net cash flows are based upon +the +Company’s independent reserve engineers' estimates of proved reserves. In +addition, other factors such as probable and possible reserves are taken into +consideration when justified by economic conditions. For each property +determined to be impaired, the Company recognizes an impairment loss equal +to +the difference between the estimated fair value and the carrying value of the +property on a depletable unit basis. Fair value is estimated to be the present +value of the aforementioned expected future net cash flows. Any impairment +charge incurred is recorded as a reduction to the asset value. This calculation +is subject to a large degree of judgment, including the determination of the +future depletable units, future cash flows and fair value. In 2006, the Company +recorded an impairment charge of $1.5 million related to its Nesson Field in +North Dakota. There were no impairments during 2005 or 2004. +Rising +finding and development costs may impair the Company’s profitability. +In +order +to continue to grow and maintain its profitability, the Company must annually +add new reserves exceeding its yearly production at a finding and development +cost that yields an acceptable operating margin and depreciation, depletion +and +amortization rate. Without cost effective exploration, development or +acquisition activities, production, reserves and profitability will decline +over +time. Given the relative maturity of most gas basins in North America and the +high level of activity in the industry, the cost of finding new reserves through +exploration and development operations has been increasing. The acquisition +market for natural gas properties has become extremely competitive among +producers for additional production and expanded drilling opportunities in +North +America. Acquisition values climbed toward historic highs during 2006 on a +per +unit basis, particularly in the Rocky Mountain Region, and the Company believes +these values may continue to increase in 2007. This increase in finding and +development costs is resulting in higher depreciation, depletion and +amortization rates. If the upward trend in finding and development costs +continues, the Company will be exposed to an increased likelihood of a +write-down in carrying value of its natural gas and oil properties in response +to falling prices and reduced profitability of operations. +18 +Index +The +Company’s development and exploration operations require substantial capital and +it may be unable to obtain needed capital or financing on satisfactory terms, +which could lead to a loss of properties and a decline in natural gas and oil +reserves and production. +The +oil +and natural gas industry is capital intensive. The Company makes and expects +to +continue to make substantial capital expenditures in its business and operations +for the exploration for and development, production and acquisition of oil +and +natural gas reserves. The Company finances capital expenditures primarily with +cash generated by operations and proceeds from bank borrowings. Cash flows +from +operations and access to capital are subject to a number of variables, including +the Company’s proved reserves, the level of oil and natural gas the Company is +able to produce from existing wells, the prices at which oil and natural gas +are +sold, and the Company’s ability to acquire, locate and produce new +reserves. +If +the +Company’s revenues or the borrowing base under its revolving credit facility +decrease as a result of lower oil and natural gas prices, or it incurs operating +difficulties, declines in reserves or for any other reason, it may have limited +ability to obtain the capital necessary to sustain its operations at planned +levels. +If +additional capital is needed, the Company may not be able to obtain debt or +equity financing on favorable terms, or at all. If cash generated by operations +or sale of limited partnerships or available under the revolving credit facility +is not sufficient to meet the capital requirements, failure to obtain additional +financing could result in a curtailment of the exploration and development +of +the Company’s prospects, which in turn could lead to a possible loss of +properties and a decline in its natural gas and oil reserves and a decline +in +its profitability. +The +Company’s credit facility and other debt financing have substantial restrictions +and financial covenants and the Company may have difficulty obtaining additional +credit, which could adversely affect its operations. +The +Company depends on its revolving credit facility for future capital needs. +The +terms of the borrowing agreement require the Company to comply with certain +financial covenants and ratios. The Company’s ability to comply with these +restrictions and covenants in the future is uncertain and will be affected +by +the levels of cash flows from operations and events or circumstances beyond +its +control. The Company’s failure to comply with any of the restrictions and +covenants under the revolving credit facility or other debt financing could +result in a default under those facilities, which could cause all of its +existing indebtedness to be immediately due and payable. +The +revolving credit facility limits the amounts the Company can borrow to a +borrowing base amount, determined by the lenders in their sole discretion, +based +upon projected revenues from the oil and natural gas properties securing its +loan. The lenders can unilaterally adjust the borrowing base and the borrowings +permitted to be outstanding under the revolving credit facility. Outstanding +borrowings in excess of the borrowing base must be repaid immediately, or the +Company must pledge other oil and natural gas properties as additional +collateral. The Company does not currently have any substantial unpledged +properties, and it may not have the financial resources in the future to make +any mandatory principal prepayments required under the revolving credit +facility. The Company’s inability to borrow additional funds under its credit +facility could adversely affect its operations. +A +substantial part of the Company’s oil and gas production is located in the Rocky +Mountains, making it vulnerable to risks associated with operating in one major +geographic area. +The +Company’s operations are becoming increasingly focused on the Rocky Mountain +Region, which means its producing properties and new drilling opportunities +are +geographically concentrated in that area. As a result, the Company, the success +of its operations, and its profitability may be disproportionately exposed +to +the impact of delays or interruptions of production from existing or planned +new +wells by significant governmental regulation, transportation capacity +constraints, curtailment of production, interruption of transportation, or +fluctuations in prices of oil and natural gas produced from the wells in the +region. +Seasonal +weather conditions and lease stipulations adversely affect the Company’s ability +to conduct drilling activities in some of the areas where it +operates. +Oil +and +natural gas operations in the Rocky Mountains are adversely affected by seasonal +weather conditions and lease stipulations designed to protect various wildlife. +In certain areas, including parts of the Piceance Basin in Colorado, drilling +and other oil and natural gas activities are restricted or prohibited by lease +stipulations, or prevented by weather conditions, for up to six months out +of +the year. This limits operations in those areas and can intensify competition +during those months for drilling rigs, oil field equipment, services, supplies +and qualified personnel, which may lead to periodic shortages. These constraints +and the resulting shortages or high costs could delay operations and materially +increase operating and capital costs and therefore adversely affect +profitability. +19 +Index +Properties +that the Company buys may not produce as projected and the Company may be unable +to determine reserve potential, identify liabilities associated with the +properties or obtain protection from sellers against those +liabilities. +One +of +the Company’s growth strategies is to acquire producing oil and natural gas +reserves in its current areas of operations and in new areas. However, reviews +of potential acquisitions are inherently incomplete because it generally is +not +feasible to review in depth every individual property. Ordinarily, the Company +focuses review efforts on the higher value properties and will sample the +remainder. However, even a detailed review of records and properties may not +necessarily reveal existing or potential problems, nor will it permit a buyer +to +become sufficiently familiar with the properties to assess fully their +deficiencies and potential. Inspections may not always be performed on every +well, and environmental problems, such as ground water contamination, are not +necessarily observable or detectable even when an inspection is undertaken. +Even +when problems are identified, the Company may choose to assume certain +environmental and other risks and liabilities in connection with acquired +properties. +The +Company has limited control over activities on properties it does not operate, +which could reduce its production and revenues. +The +Company operates most of the wells in which it owns an interest. However, there +are some wells the Company does not operate because it participates through +joint operating agreements under which it owns partial interests in oil and +natural gas properties operated by other entities. If the Company does not +operate the properties in which it owns an interest, it does not have control +over normal operating procedures, expenditures or future development of +underlying properties. The failure of an operator to adequately perform +operations, or an operator’s breach of the applicable agreements, could reduce +production and revenues and affect the Company’s profitability. The success and +timing of drilling and development activities on properties operated by others +therefore depends upon a number of factors outside of the Company’s control, +including the operator’s timing and amount of capital expenditures, expertise +and financial resources, inclusion of other participants in drilling wells, +and +use of technology. +Market +conditions or operational impediments could hinder access to oil and natural +gas +markets or delay production. +Market +conditions or the unavailability of satisfactory oil and natural gas +transportation arrangements may hinder access to oil and natural gas markets +or +delay production. The availability of a ready market for oil and natural gas +production depends on a number of factors, including the demand for and supply +of oil and natural gas and the proximity of reserves to pipelines and terminal +facilities. The Company’s ability to market its production depends in +substantial part on the availability and capacity of gathering systems, +pipelines and processing facilities owned and operated by third parties. Failure +to obtain such services on acceptable terms could materially harm the Company’s +business. The Company may be required to shut in wells for lack of market or +because of inadequacy, unavailability or the pricing associated with natural +gas +pipeline, gathering system capacity or processing facilities. If that were +to +occur, the Company would be unable to realize revenue from those wells until +production arrangements were made to deliver the production to market and its +profitability would be adversely affected. +The +Company’s derivative activities could result in financial losses or could reduce +its income. +To +achieve a more predictable cash flow, to reduce exposure to adverse fluctuations +in the prices of oil and natural gas and to allow its gas marketing company +to +offer pricing options to gas sellers and purchasers, the Company uses +derivatives for a portion of its oil and natural gas production from its own +wells, its partnerships and for gas purchases and sales by its marketing +subsidiary. These arrangements expose the Company to the risk of financial +loss +in some circumstances, including when purchases or sales are different than +expected, the counter-party to the derivative contract defaults on its contract +obligations, or when there is a change in the expected differential between +the +underlying price in the derivative agreement and actual prices received. In +addition, derivative arrangements may limit the benefit from changes in the +prices for oil and natural gas and may require the use of Company resources +to +meet cash margin requirements. Since the Company’s derivatives do not currently +qualify for use of hedge accounting, changes in the fair value of derivatives +are recorded in the statements of income and earnings are subject to greater +volatility. +The +inability of one or more of the Company’s customers to meet their obligations +may adversely affect the Company’s financial results. +Substantially +all of the Company’s 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 the Company’s +overall credit risk in that these entities may be similarly affected by changes +in economic and other conditions. In addition, the Company’s oil and natural gas +derivatives as well as the derivatives used by its marketing subsidiary expose +the Company to credit risk in the event of nonperformance by counterparties. +20 +Index +The +Company depends on a limited number of key personnel who would be difficult +to +replace. +The +Company depends on the performance of its executive officers and other key +employees. The loss of any member of senior management or other key employees +could negatively impact the Company’s ability to execute its strategy. +Terrorist +attacks or similar hostilities may adversely impact the Company’s results of +operations. +Increasing +terrorist attacks around the world have created many economic and political +uncertainties, some of which may materially adversely impact the Company’s +business. Uncertainty surrounding military strikes or a sustained military +campaign may affect the Company’s operations in unpredictable ways, including +disruptions of fuel supplies and markets, particularly oil, and the possibility +that infrastructure facilities, including pipelines, production facilities, +processing plants and refineries, could be direct targets of, or indirect +casualties of, an act of terror or war. The continuation of these attacks may +subject the Company’s operations to increased risks and depending on their +ultimate magnitude, could have a material adverse effect on its business, +results of operations, financial condition and prospects. +The +Company’s insurance coverage may not be sufficient to cover some liabilities or +losses that the Company may incur. +The +occurrence of a significant accident or other event not fully covered by +insurance could have a material adverse effect on the Company’s operations and +financial condition. Insurance does not protect the Company against all +operational risks. The Company does not carry business interruption insurance +at +levels that would provide enough funds for it to continue operating without +access to other funds. For some risks, the Company may not obtain insurance +if +it believes the cost of available insurance is excessive relative to the risks +presented. In addition, pollution and environmental risks generally are not +fully insurable. +The +Company may not be able to keep pace with technological developments in its +industry. +The +natural gas and oil industry is characterized by rapid and significant +technological advancements and introductions of new products and services using +new technologies. As others use or develop new technologies, the Company may +be +placed at a competitive disadvantage, and competitive pressures may force it +to +implement those new technologies at substantial cost. In addition, other natural +gas and oil companies 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 the Company can. The +Company may not be able to respond to these competitive pressures and implement +new technologies on a timely basis or at an acceptable cost. If one or more +of +the technologies the Company uses now or in the future were to become obsolete +or if it was unable to use the most advanced commercially available technology, +its business, financial condition and results of operations could be materially +adversely affected. +Competition +in the oil and natural gas industry is intense, which may adversely affect +the +Company’s ability to succeed. +The +oil +and natural gas industry is intensely competitive, and the Company competes +with +other companies that have greater resources. Many of these companies not only +explore for and produce oil and natural gas, but also carry on refining +operations and market petroleum and other products on a regional, national +or +worldwide basis. These companies may be able to pay more for productive oil +and +natural gas properties and exploratory prospects or define, evaluate, bid for +and purchase a greater number of properties and prospects than the Company’s +financial or human resources permit. In addition, these companies may have +a +greater ability to continue exploration activities during periods of low oil +and +natural gas market prices. Larger competitors may be able to absorb the burden +of present and future federal, state, local and other laws and regulations +more +easily than the Company can, which would adversely affect the Company’s +competitive position. The Company’s ability to acquire additional properties and +to discover reserves in the future will be dependent upon its ability to +evaluate and select suitable properties and to consummate transactions in a +highly competitive environment. In addition, because many companies in its +industry have greater financial and human resources, the Company may be at +a +disadvantage in bidding for exploratory prospects and producing oil and natural +gas properties. These factors could adversely affect the success of the +Company’s operations and its profitability. +The +Company is subject to complex federal, state, local and other laws and +regulations that could adversely affect the cost, manner or feasibility of +doing +business. +The +Company’s exploration, development, production and marketing operations are +regulated extensively at the federal, state and local levels. Environmental +and +other governmental laws and regulations have increased the costs to plan, +design, drill, install, operate and abandon oil and natural gas wells. Under +these laws and regulations, the Company could also be liable for personal +injuries, property damage and other damages. Failure to comply with these laws +and regulations may result in the suspension or termination of operations and +subject the Company to administrative, civil and criminal penalties. Moreover, +public interest in environmental protection has increased in recent years, +and +environmental organizations have opposed, with some success, certain drilling +projects. +21 +Index +Part +of +the regulatory environment includes, in some cases, federal requirements for +obtaining environmental assessments, environmental impact studies and/or plans +of development before commencing exploration and production activities. In +addition, the Company’s activities are subject to the regulation by oil and +natural gas-producing states of conservation practices and protection of +correlative rights. These regulations affect operations and limit the quantity +of oil and natural gas that can be produced and sold. A major risk inherent +in +the Company’s drilling plans is the need to obtain drilling permits from state +and local authorities. Delays in obtaining regulatory approvals, drilling +permits, 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 the Company’s ability to explore on or develop its properties. +Additionally, the oil and natural gas regulatory environment could change in +ways that might substantially increase the financial and managerial costs to +comply with the requirements of these laws and regulations and, consequently, +adversely affect profitability. Furthermore, the Company may be put at a +competitive disadvantage to larger companies in the industry who can spread +these additional costs over a greater number of wells and larger operating +staff. See “Business — Governmental Regulation — Regulation of Oil and +Natural Gas Exploration and Production” and “Business — Governmental +Regulation — Environmental Regulations” for a description of the laws and +regulations that affect us. +If +litigation were commenced against the Company for alleged royalty practices +and +payments, the cost of our defending the lawsuit could be significant and any +resulting judgments against the Company could have a material adverse impact +upon our financial condition. +Recent +litigation has commenced against several companies in the Company's industry +regarding royalty practices and payments in jurisdictions where the Company +conducts business. While the Company's business model differs from those of +the +litigants in those cases, and the Company has not been named in any litigation, +has not had similar litigation commenced, and has not been threatened with +such +litigation, there can be no assurance that the Company will not become a party +to such litigation or to similar litigation in the future. If litigation of +this +nature were commenced against us, even if the ultimate outcome of the litigation +resulted in a judgment for the Company, the cost of defending the Company could +be significant. These costs would be reflected in terms of dollar outlay as +well +as the amount of time, attention and other resources that the Company's +management would have to appropriate to the defense. Although the Company cannot +predict an eventual outcome were litigation to be commenced against us, a +judgment in favor of the plaintiffs could have a material adverse impact upon +the Company's financial condition. +Material +weaknesses in the Company’s internal control over financial reporting and +disclosure controls and procedures could adversely impact the reliability of +its +internal control over financial reporting, its ability to timely file certain +reports with the SEC, the liquidity of the market for its common stock and +its +ability to raise investment capital to support its drilling operations in the +future. +Management +has assessed the effectiveness of internal control over financial reporting +as +of December 31, 2006, and this assessment identified material weaknesses in +internal control over financial reporting and disclosure controls and +procedures. For discussion of these material weaknesses and the Company’s +remediation plans, please see Part II, Item 9A, “Controls and Procedures” of +this report. As a result of these material weaknesses, management concluded +that +the Company's internal control over financial reporting and disclosure controls +and procedures were not effective as of December 31, 2006. +Material +weaknesses were also identified during management’s assessment of the internal +control environment as of December 31, 2005. A description of these material +weaknesses can be found in Part II, Item 9A, “Controls and Procedures” of the +Annual Report for fiscal year 2005. As a result of these material weaknesses, +management concluded that the Company's internal control over financial +reporting was not effective as of December 31, 2005. +The +Company’s material weaknesses have led to restatements of its consolidated +financial statements in connection with the filing of its annual report on +Form +10-K for the year ended December 31, 2005. These material weaknesses have also +contributed to the delays the Company has experienced in filing its annual +reports on Form 10-K for the years ended December 31, 2006 and 2005. In +addition, the Company did not timely file with the SEC its Form 10-Q for the +quarters ended March 31, 2007 and 2006. A continued inability to timely file +its +periodic reports with the SEC could involve a number of significant risks, +which +could have an adverse impact on the Company’s operations, on the market for its +stock and investors generally, including: +· +The +potential delisting of the Company’s common stock. The Company's failure +to file its periodic reports timely constitutes a violation of the +listing +standards of the NASDAQ Stock Market. If the NASDAQ Stock Market +ceases to +grant the Company extensions of time in which to file its reports, +NASDAQ +has the right to begin proceedings to delist the Company’s common stock. +The Company had a hearing before the NASDAQ Listing Qualifications +Panel +("Panel") on May 10, 2007, regarding the Company's failure to file +timely +its Form 10-K for the year ended December 31, 2006. The Panel also +considered the Company's failure to file timely its Form 10-Q for +the +period ended March 31, 2007. It is possible that the Panel might +order the +delisting of the Company's stock from NASDAQ. The delisting of the +Company’s common stock could have a material adverse effect on the Company +by: +22 +Index +· +reducing +the liquidity and market price for its common stock; +· +reducing +the number of investors willing to hold or acquire its common stock, +which +in turn could further reduce its stock's liquidity; +and +· +limiting +the ability of investors to sell the Company’s common +stock. +If +the +Company is unable to prepare and file its annual report on Form 10-K in a timely +manner, and to a lesser degree, if the Company is unable to prepare and file +one +or more of its quarterly reports on Form 10-Q in a timely manner, the Company +might be unable to raise capital for Company operations, either by its selling +of its securities or through a borrowing facility. In this regard, under those +circumstances the Company could be faced with any of the following +risks: +· +If +the Company were unable to file its financial statements because +it is +unable to file its annual report on Form 10-K and/or its quarterly +financial reports on Form 10-Q, the Company would not be able to +raise +capital from the public markets through the sale of its stock or +debt +securities through an SEC-registered public offering. Likewise, the +Company’s inability to file its required periodic reports with the SEC in +a timely fashion may hinder its ability to raise capital through +the +private placement of its +securities. +· +A +major component of the Company's business plan is to raise drilling +capital through its public and private sales of partnership interests. +If +the Company is unable to file its annual reports and/or quarterly +reports +in a timely fashion, it will not be able to access the public markets +through an SEC-registered securities offering; and it may have difficulty +in accessing the private placement market for capital through an +SEC-exempt securities offering. +· +The +Company’s credit facility with JPMorgan Chase and BNP Paribas ("Lenders") +requires the Company to be current in its filing of its required +periodic +reports with the SEC. If the Company is unable to file its annual +reports +and/or quarterly reports with the SEC when due, the Lenders might +declare +the credit facility to be in default and any loans then outstanding +under +the credit facility would be immediately due and payable. Additionally, +even if the Lenders did not declare a default and accelerate repayment +of +outstanding amounts, the Company might not be able to borrow further +amounts under the facility. Moreover, the Company under those +circumstances might not be able to negotiate and arrange alternative +financing to support its drilling operations. See Note 5 to consolidated +financial statements for discussion related to the current waiver +the +Company has received under the credit +facility. +If +the +Company is unable to raise drilling capital and funding for its operations +as +cited in the three preceding paragraphs, then it would be likely that its +drilling operations would be materially adversely affected; and that its ability +to grow the Company in the historical manner would be severely hampered. +Moreover, it is likely that the Company’s business operations could be +materially adversely damaged. +· +Currently, +the Company has several employee and director stock benefit plans +in which +its common stock available under the plans has been registered by +SEC Form +S-8 under the Securities Act of 1933. Under SEC regulations, the +Company’s +failure to file with the SEC required annual reports on Form 10-K +will +cause its Form S-8 registration statement to be stale - that is, +not +current as to information about the Company. The result is that the +Form +S-8 would no longer be in compliance with the requirements of the +Securities Act, compliance with which allowed the Company to offer +these +stock benefits to Company employees for their investment. Consequently, +if +the Company does not file its annual reports with the SEC in a timely +fashion, the Company will have to suspend the availability of these +plans, +including the Company's 401(k) and Profit Sharing Plan, to allow +Company +employees to exercise any Company stock options that they hold or +to +choose to invest in Company common stock under the 401(k) and Profit +Sharing Plan. Additionally, those Company employees who own shares +of the +Company's common stock might find it more difficult to sell their +shares +in the market if the Company's common stock is delisted from the +NASDAQ +Stock Market. +Furthermore, +the number of subsequent failures to timely file any future periodic reports +with the SEC could increase the likelihood, frequency of occurrence, and +severity of the impact of any of the risks described above. +Since +the +identification of these material weaknesses, the Company has implemented and +is +continuing to implement various procedures intended to improve its internal +control over financial reporting and disclosure controls and procedures. No +assurance can be given that the Company will be effective in remedying all +identified deficiencies in its internal control over financial reporting and +disclosure controls and procedures. The Company has implemented procedures +to +remediate the material weaknesses identified during fiscal year 2005, and while +management believes that the reconciliation, capitalization assessment, +valuation, completeness determination and monitoring procedures and controls +implemented since December 31, 2006, will, when demonstrated to be operating +effectively, allow management to conclude that the material weaknesses +identified in 2006 have been remediated, there can also be no assurance that +the +material weaknesses will be rectified in a timely fashion or that additional +material weaknesses will not arise and be identified. +23 +Index +ITE M +1B. UNRESOLVED STAFF COMMENTS +In +September 2006, the Company received written comments from the staff of the +SEC +regarding its Annual Report on Form 10-K for the year ended December 31, 2005 +("2005 Form 10-K"), to which the Company has subsequently provided responses. +The staff have since indicated to the Company that they have no further +outstanding comments related to the Company's 2005 Form 10-K. As a result, +the +Company does not believe it has any currently outstanding comments with the +staff with regard to its own filings. +However, +the Company, as managing general partner, has not yet filed all +Company-sponsored partnerships' 2005 Forms 10-K, related to which the Company +has previously issued filings on Forms 8-K (dated August 25, 2005, and November +15, 2005) advising that, due to errors in its accounting policies and practices, +no reliance should be placed on the related financial information, nor on the +auditors' opinion related thereto. As of the date of this filing, the Company +has not completed the corrections of these errors and is delinquent in its +filing requirements for 24 such Company-sponsored partnerships with regard +to +the year ended December 31, 2005. Additionally, for each of the same +Company-sponsored partnerships, the Company has not filed related Forms 10-Q +for +the quarterly periods ended March 31, 2006, June 30, 2006, September 30, 2006, +and March 31, 2007, or Forms 10-K for the year ended December 31, +2006. +ITE M +2. PROPERTIES +Summary +of Productive Wells +The +table +below shows the number of the Company's productive gross and net wells at +December 31, 2006. +Productive +Wells +Gas +Oil +Location +Gross +Net +Gross +Net +Colorado +1,445 +794.0 +25 +19.3 +Kansas +40 +39.0 +- +- +Michigan +199 +106.0 +7 +2.7 +North +Dakota +5 +1.1 +12 +6.2 +Pennsylvania +420 +93.1 +- +- +Tennessee +1 +0.7 +35 +13.7 +West +Virginia +905 +515.9 +4 +1.7 +Wyoming +- +- +3 +0.7 +Total +3,015 +1,549.8 +86 +44.3 +Oil +and Gas Reserves +All +of +the Company's natural gas and oil reserves are located in the United States. +The +Company's approximate net proved reserves were estimated by independent +petroleum engineers, to be 279,078 MMcf of natural gas and 7,272 MBbls of oil +at +December 31, 2006, 247,288 MMcf of natural gas and 4,538 MBbls of oil at +December 31, 2005, and 197,549 MMcf of natural gas and 3,316 MBbls of oil at +December 31, 2004. +The +Company's approximate net proved developed reserves were estimated, by +independent petroleum engineers, to be 158,978 MMcf of natural gas and 4,629 +MBbls of oil at December 31, 2006, 155,354 MMcf of natural gas and 3,860 MBbls +of oil at December 31, 2005, and 146,152 MMcf of natural gas and 3,190 MBbls +of +oil at December 31, 2004. +The +Company utilized the services of two independent petroleum engineers for its +2006 independent reserve report. Wright & Company prepared the reserve +report for the Appalachian and Michigan Basin and Northeast Colorado ("NECO") +properties. Ryder Scott Company, LLP prepared the reserve report for the Rocky +Mountain Region, with the exception of the NECO properties. Wright & Company +prepared all of the reserve reports for the Company for 2005 and 2004 with +the +exception of 2005 North Dakota wells which were prepared by Ryder Scott +Company. +24 +Index +The +Company's oil and natural gas reserves by region are as follows as of December +31, 2006: +Oil +(MBbl) +Gas +(MMcf) +Natural +Gas +Equivalent +(MMcfe) +% +Proved +Developed Reserves +Appalachian +Basin +29 +35,840 +36,014 +19.3 +% +Michigan +Basin +36 +20,331 +20,547 +11.0 +% +Rocky +Mountain Region +4,564 +102,807 +130,191 +69.7 +% +Total +Proved Developed Reserves +4,629 +158,978 +186,752 +100.0 +% +Proved +Undeveloped Reserves +Appalachian +Basin +- +- +- +0.0 +% +Michigan +Basin +- +685 +685 +0.5 +% +Rocky +Mountain Region +2,643 +119,415 +135,273 +99.5 +% +Total +Proved Undeveloped +2,643 +120,100 +135,958 +100.0 +% +Total +Proved Reserves +Appalachian +Basin +29 +35,840 +36,014 +11.2 +% +Michigan +Basin +36 +21,016 +21,232 +6.6 +% +Rocky +Mountain Region +7,207 +222,222 +265,464 +82.2 +% +Total +Proved Reserves +7,272 +279,078 +322,710 +100.0 +% +No +major +discovery or other favorable or adverse event that would cause a significant +change in estimated reserves on the properties owned by the Company as of +December 31, 2006, is believed by the Company to have occurred since December +31, 2006, with the exception of the following acquisitions: +· +In +January 2007, the Company acquired 144 oil and gas wells and 8,160 +acres +of leasehold in the Wattenberg Field area of the DJ Basin, Colorado +and an +increased net interest in 718 wells currently operated by the +Company. +· +In +February 2007, the Company acquired 28 producing wells and associated +undeveloped acreage in the Wattenberg Field. +Reserves +cannot be measured exactly, because reserve estimates involve subjective +judgment. The estimates must be reviewed periodically and adjusted to reflect +additional information gained from reservoir performance, new geological and +geophysical data and economic changes. +The +standardized measure of discounted future estimated net cash flows attributable +to the Company's proved oil and gas reserves, giving effect to future estimated +income tax expenses, was estimated by the Company’s independent petroleum +engineers to be $215.7 million as of December 31, 2006, $405.4 million as of +December 31, 2005, and $229.4 million as of December 31, 2004. These amounts +are +based on December 31 commodity prices in the respective years. The values +expressed are estimates only, and may not reflect realizable values or fair +market values of the natural gas and oil ultimately extracted and recovered. +The +standardized measure of discounted future net cash flows may not accurately +reflect proceeds of production to be received in the future from the sale of +natural gas and oil currently owned and does not necessarily reflect the actual +costs that would be incurred to acquire equivalent natural gas and oil +reserves. +Net +Proved Natural Gas and Oil Reserves +The +proved reserves of natural gas and oil of the Company as estimated by the +Company’s independent petroleum engineers at December 31, 2006, are set forth +below. These reserves have been prepared in compliance with the rules of the +SEC +based on December 31, 2006, prices. These reserve estimates were not filed +with +another Federal authority or agency since the Company filed its Form 10-K with +the SEC on May 31, 2006, for the year ended December 31, 2005. An analysis +of +the change in estimated quantities of natural gas and oil reserves from January +1, 2006 to December 31, 2006, all of which are located within the United States, +is shown below: +25 +Index +Natural +Gas +(MMcf) +Oil +(MBbl) +Proved +developed and undeveloped reserves: +Beginning +of year +247,288 +4,538 +Revisions +of previous estimates +(28,067 +) +35 +Beginning +of year as revised +219,221 +4,573 +New +discoveries and extensions +Rocky +Mountain region +70,499 +3,148 +Dispositions +to partnerships +(1,215 +) +(92 +) +Acquisitions +Michigan +basin +35 +- +Rocky +Mountain region +3,477 +274 +Appalachian +basin +222 +- +Production +(13,161 +) +(631 +) +End +of year +279,078 +7,272 +Proved +developed reserves: +Beginning +of year +155,354 +3,860 +End +of year +158,978 +4,629 +Standardized +Measure of Discounted Future Net Cash Flows and Changes Therein Relating to +Proved Natural Gas and Oil Reserves +Summarized +in the following table is information for the Company with respect to the +standardized measure of discounted future net cash flows relating to proved +natural gas and oil reserves at December 31, 2006. Future cash inflows are +computed by applying year-end prices of natural gas and oil relating to the +Company's proved reserves to year-end quantities of those reserves. Future +production, development, site restoration and abandonment costs are derived +based on current costs, assuming continuation of existing economic conditions. +Future income tax expenses are computed by applying the statutory rate in effect +at December 31, 2006, to the future pretax net cash flows, less the tax basis +of +the properties, and gives effect to permanent differences, tax credits and +allowances related to the properties. (in thousands) +Future +estimated cash flows +$ +1,804,796 +Future +estimated production costs +(571,346 +) +Future +estimated development costs +(373,460 +) +Future +estimated income tax expense +(334,536 +) +Future +net cash flows +525,454 +10% +annual discount for estimated timing of cash flows +(309,792 +) +Standardized +measure of discounted future estimated net cash flows +$ +215,662 +26 +Index +The +following table summarizes the principal sources of change in the standardized +measure of discounted future estimated net cash flows from January 1, 2006, +through December 31, 2006: (in thousands) +Sales +of oil and gas production net of production costs +$ +(94,337 +) +Net +changes in prices and production costs +(299,721 +) +Extensions, +discoveries, and improved recovery, less related costs +46,109 +Sales +of reserves +(3,356 +) +Purchase +of reserves +11,003 +Development +costs incurred during the period +20,051 +Revisions +of previous quantity estimates +(23,146 +) +Changes +in estimated income taxes +120,818 +Accretion +of discount +62,838 +Timing +and other +(30,027 +) +Total +$ +(189,768 +) +It +is +necessary to emphasize that the data presented should not be viewed as +representing the expected cash flow from, or current value of, existing proved +reserves, because the computations are based on a large number of estimates +and +assumptions. Reserve quantities cannot be measured with precision, and their +estimation requires many judgmental determinations and frequent revisions. +The +required projection of production and related expenditures over time requires +further estimates with respect to pipeline availability, rates of demand and +governmental control. Actual future prices and costs are likely to be +substantially different from the current prices and costs utilized in the +computation of reported amounts. Any analysis or evaluation of the reported +amounts should give specific recognition to the computational methods and their +inherent limitations. +Substantially +all of the Company's natural gas and oil reserves have been mortgaged or pledged +as security for the Company's credit agreement. See Note 5 to the notes to +the +Company's financial statements. +Oil +and Natural Gas Leases +The +following table sets forth the by state leased acres available to the Company +for development of oil and natural gas as of December 31, 2006. +Colorado +42,900 +Kansas +23,000 +Michigan +200 +New +York +12,800 +North +Dakota +89,600 +Wyoming +32,000 +Total +200,500 +Title +to Properties +The +Company’s management believes that it holds good and indefeasible title to its +properties, in accordance with standards generally accepted in the natural +gas +industry, subject to such exceptions stated in the opinion of counsel employed +in the various areas in which the Company conducts its exploration activities. +Those exceptions, in the Company's judgment, do not detract substantially from +the use of such property. As is customary in the natural gas industry, only +a +perfunctory title examination is conducted at the time the properties believed +to be suitable for drilling operations are acquired by the Company. Prior to +the +commencement of drilling operations, a title examination is conducted and +curative work is performed with respect to defects which the Company deems +to be +significant. A title examination has been performed with respect to +substantially all of the Company's producing properties. No single property +owned by the Company represents a material portion of the Company's holdings. +27 +Index +The +properties owned by the Company are subject to royalty, overriding royalty +and +other outstanding interests customary in the industry. The properties are also +subject to burdens such as liens incident to operating agreements, current +taxes, development obligations under natural gas and oil leases, farm-out +arrangements and other encumbrances, easements and restrictions. The Company +does not believe that any of these burdens will materially interfere with the +use of the properties. +Facilities +The +Company completed the construction of its new corporate headquarters in +Bridgeport, West Virginia, which was occupied in December 2006. The Company +intends to begin construction of a second office building adjacent to its new +corporate headquarters in 2007. The Company’s prior Bridgeport offices, +consisting of two buildings, will be placed on the market and available for +sale +sometime in 2007. The Company has an operating lease for its Denver Office +in +Denver, Colorado. +The +Company owns a field operating facility in each of Harrison and Gilmer Counties, +West Virginia, Alpena County, Michigan and Weld County, Colorado. The Company +has operating leases for two field offices in Colorado and one in +Pennsylvania. +ITE M +3. LEGAL PROCEEDINGS +From +time +to time the Company is a party to various legal proceedings in the ordinary +course of business. The Company is not currently a party to any litigation +that +it believes would have a materially adverse affect on the Company's business, +financial condition, results of operations, or liquidity. +Recent +litigation has commenced against several companies in our industry regarding +royalty practices and payments in jurisdictions where the Company conducts +business. While the Company's business model differs from those of the litigants +in those cases, and the Company has not been named in any litigation, has not +had similar litigation commenced, nor has such litigation been threatened, +there +can be no assurance that the Company will not be a party to any litigation +or to +similar litigation in the future. +ITE M +4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY +HOLDERS +No +matters were submitted to a vote of security holders during the fourth quarter +of the fiscal year covered by this report. +PART +II +ITE M +5. MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED +STOCKHOLDERS MATTERS AND ISSUER PURCHASES OF EQUITY +SECURITIES. +The +authorized capital stock of the Company consists of 50,000,000 shares of common +stock, par value $0.01 per share. There were 14,887,530 shares of common stock +issued and outstanding as of April 30, 2007. The common stock of the Company +is +traded on the NASDAQ Global Select Market under the ticker symbol PETD. +The +following table sets forth the range of high and low sales prices for the +Company's common stock as reported on the NASDAQ Global Select Market for the +periods indicated below. +High +Low +2006 +First +Quarter +$ +46.06 +$ +32.46 +Second +Quarter +45.07 +32.89 +Third +Quarter +44.54 +33.32 +Fourth +Quarter +46.61 +36.96 +2005 +First +Quarter +44.19 +35.72 +Second +Quarter +37.28 +22.65 +Third +Quarter +40.00 +32.54 +Fourth +Quarter +39.55 +30.53 +28 +Index +As +of +April 30, 2007, there were approximately 908 record holders of the Company's +common stock. +The +Company has not paid any dividends on its common stock and currently intends +to +retain earnings for use in its business. Therefore, it does not expect to +declare cash dividends in the foreseeable future. +ISSUER +PURCHASES OF EQUITY SECURITIES +Period +Total +Number +of +Shares +Purchased +Average +Price +Paid +per Share +Total +Number +of +Shares +Purchased +as +Part +of Publicly +Announced +Plans +or +Programs +Maximum +Number of +Shares +that May +Yet +Be Purchased +Under +the Plans +or +Programs +October +1 - 20, 2006 +334,242 +$ +40.93 +334,242 +1,477,109 +Total +334,242 +$ +40.93 +334,242 +1,477,109 +In +January 2006, the Company announced that its Board of Directors had authorized +the Company to purchase up to 10% (1,627,500 shares) of its outstanding common +stock during 2006. Stock purchases under this program were made in the open +market or in private transactions, at times and in amounts that management +deemed appropriate. On +October 20, 2006, the Company completed its January 2006 share purchase program. +Total shares purchased in 2006 pursuant to the program were 1,627,500 common +shares at a cost of $66.3 million ($40.75 average price paid per share), +including 100,000 shares from an executive officer of the Company at a cost +of +$4.1 million ($40.66 price paid per share). All shares purchased in accordance +with the program were subsequently retired. +On +October 16, 2006, the Board of Directors of the Company approved a second 2006 +share purchase program authorizing the Company to purchase up to 10% of the +Company’s then outstanding common stock (1,477,109 shares) through April 2008. +Stock purchases under this program may be made in the open market or in private +transactions, at times and in amounts that management deems appropriate. The +Company may terminate or limit the stock purchase program at any time. +29 +Index +ITE M +6. SELECTED FINANCIAL DATA (in thousands, except per share +data) +Year +Ended December 31, +2006 +2005 +2004 +2003 +2002 +Revenues: +Oil +and gas well drilling operations +$ +17,917 +$ +99,963 +$ +94,076 +$ +57,510 +$ +45,842 +Gas +sales from marketing activities +131,325 +121,104 +94,627 +73,132 +43,537 +Oil +and gas sales +115,189 +102,559 +69,492 +48,394 +22,688 +Well +operations and pipeline income +10,704 +8,760 +7,677 +6,907 +5,771 +Oil +and gas price risk management gains (losses), net +9,147 +(9,368 +) +(3,085 +) +(812 +) +(370 +) +Other +income +2,221 +2,180 +1,696 +3,338 +2,549 +Total +revenues +286,503 +325,198 +264,483 +188,469 +120,017 +Costs +and expenses: +Cost +of oil and gas well drilling operations +12,617 +88,185 +77,696 +46,946 +37,859 +Cost +of gas marketing activities +130,150 +119,644 +92,881 +72,361 +43,168 +Oil +and gas production and well operations costs +29,021 +20,400 +17,713 +13,630 +8,672 +Exploration +cost +8,131 +11,115 +- +- +- +General +and administrative expense +19,047 +6,960 +4,506 +4,975 +4,392 +Depreciation, +depletion and amortization +33,735 +21,116 +18,156 +15,313 +12,602 +Total +costs and expenses +232,701 +267,420 +210,952 +153,225 +106,693 +Gain +on sale of leaseholds +328,000 +7,669 +- +- +- +Income +from operations +381,802 +65,447 +53,531 +35,244 +13,324 +Interest +income +8,050 +898 +185 +190 +248 +Interest +expense +(2,443 +) +(217 +) +(238 +) +(816 +) +(1,505 +) +Income +before income taxes and cumulative effect of change in accounting +principle +387,409 +66,128 +53,478 +34,618 +12,067 +Income +taxes +149,637 +24,676 +20,250 +11,934 +3,186 +Income +before cumulative effect of change in accounting principle +237,772 +41,452 +33,228 +22,684 +8,881 +Cumulative +effect of change in accounting principle (net of taxes of +$1,392) +- +- +- +(2,271 +) +- +Net +income +$ +237,772 +$ +41,452 +$ +33,228 +$ +20,413 +$ +8,881 +Basic +earnings per common share +$ +15.18 +$ +2.53 +$ +2.05 +$ +1.30 +$ +0.56 +Diluted +earnings per share +$ +15.11 +$ +2.52 +$ +2.00 +$ +1.25 +$ +0.55 +December +31, +2006 +2005 +2004 +2003 +2002 +Total +Assets +$ +884,287 +$ +444,361 +$ +329,453 +$ +294,004 +$ +198,838 +Working +Capital (Deficit) +$ +29,180 +$ +(16,763 +) +$ +231 +$ +7,287 +$ +2,645 +Long-Term +Debt +$ +117,000 +$ +24,000 +$ +21,000 +$ +53,000 +$ +25,000 +Stockholders' +Equity +$ +360,144 +$ +188,265 +$ +154,021 +$ +112,559 +$ +92,887 +30 +Index +ITE M +7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL +CONDITION AND RESULTS OF OPERATIONS +Safe +Harbor Statement Under the Private Securities Litigation Reform Act of +1995 +Statements, +other than historical facts, contained in this Annual Report on Form 10-K, +including statements of estimated oil and gas production and reserves, drilling +plans, future cash flows, anticipated capital expenditures and Management's +strategies, plans and objectives, are "forward looking statements" within the +meaning of Section 27A of the Securities Act of 1933, as amended, and Section +21E of the Securities Exchange Act of 1934, as amended. Although the Company’s +management believes that its forward looking statements are based on reasonable +assumptions, it cautions that such statements are subject to a wide range of +risks and uncertainties incidental to the exploration for, acquisition, +development, production and marketing of oil and gas, and it can give no +assurance that its estimates and expectations will be realized. Important +factors that could cause actual results to differ materially from the forward +looking statements include, but are not limited to, changes in production +volumes, worldwide demand, and commodity prices for petroleum natural resources; +the timing and extent of the Company's success in discovering, acquiring, +developing and producing oil and gas reserves; the Company's ability to acquire +leases, drilling rigs, supplies and services at reasonable prices; the +availability of capital to the Company; the Company’s ability to raise funds +through its Partnership Drilling Programs; risks incident to the drilling and +operation of oil and gas wells; future production and development costs; the +effect of existing and future laws, governmental regulations and the political +and economic climate of the United States; the effect of oil and gas derivatives +activities; and conditions in the capital markets. Other risk factors are +discussed elsewhere in this Form 10-K. +Results +of Operations +Management +Overview +The +Company recorded strong revenues and cash flows for 2006. Although average +commodity prices declined during 2006 compared to 2005, a record 24% production +increase more than compensated for the price decline, as oil and gas sales +increased $12.6 million over 2005. The recent trend in declining profit margins +on the Company's oil and gas well drilling operations segment reversed during +the latter part of the year, as the Company switched from footage-based drilling +contracts, which lead to the declining margins, to cost-plus contracts where +the +Company does not bear the risk of cost changes on the wells it drills for the +partnerships. However, this change in type of contract, which allowed the +Company to recognize a contracted rate of profit from oil and gas well drilling +operations, resulted in an equal $74.6 million decline in revenue and related +costs. See "Drilling Operations" below for further discussion. +The +principal business event of the year was the sale of undeveloped property in +the +Grand Valley Field in the third quarter for a gain of $328 million, with +approximately $26 million in additional gains on the transaction deferred to +future periods, to be recognized if wells are drilled on certain properties. +The +proceeds of the sale, the qualification of the sale for like-kind exchange +tax +status and the property purchased during 2006 and 2007 have substantially +strengthened the Company's financial position and positioned it for continuing +growth in the coming periods. +Year +Ended December 31, 2006, Compared to December 31, 2005 +Revenues +Total +revenues for the year ended December 31, 2006, were $286.5 million compared +to +$325.2 million for the year ended December 31, 2005, a decrease of approximately +$38.7 +million, +or 11.9 %. +The +decrease was primarily attributable to a decrease in drilling revenues of $82.1 +million partially offset by the increased oil and gas sales from both gas +marketing activities and the Company’s share of production for a total of $22.9 +million and the swing from a $9.4 million loss in oil and gas price risk +management for the year ended December 31, 2005, to a gain of $9.1 million +for +the year ended December 31, 2006. See "Drilling Operations" below for an +explanation of the impact the new cost-plus drilling arrangements and related +accounting had on drilling revenues for the year 2006. +Costs +and Expenses +Total +costs and expenses for the year ended December 31, 2006, were $232.7 million +compared to $267.4 million for the year ended December 31, 2005, a decrease +of +approximately $34.7 million, or 13%. The decrease was primarily +attributable to decreases in the cost of oil and gas well drilling operations +of +$75.6 million and exploration cost of $3 million offset in part by increases +in +the cost of gas marketing activities of $10.5 million, oil and gas production +and well operations costs of $8.6 million, general and administrative expenses +of $12.1 million and depreciation, depletion and amortization of $12.6 million. +See "Drilling Operations” below for an explanation of the impact of the new cost +plus drilling arrangements and related accounting had on drilling expenses +for +the year 2006. +31 +Index +Drilling +Operations +During +the first quarter of 2006, the Company began operating and recognizing revenues +for its cost-plus service arrangements with new partnerships, in addition to +its +footage-based drilling arrangements on earlier partnerships. The cost-plus +drilling arrangements became effective with the private program partnership +funded by the Company in December 2005 and continued in the 2006 partnership +funded on September 1, 2006. Drilling revenues for the year ended December +31, +2006, were $17.9 million, net of $74.6 million of costs related to drilling +arrangements accounted for on the cost-plus basis, compared to $100 million +for +the year ended December 31, 2005, a decrease of $82.1 million. The decrease +was +primarily due to the change in the Company’s drilling contracts, which resulted +in net revenue recognition related to the new contracts. +The +costs +of oil and gas well drilling operations for the year ended December 31, 2006, +was $12.6 million compared to $88.2 million for the year ended December 31, +2005, a decrease of $75.6 million. The decrease in costs is primarily +attributable to the Company’s revenue reporting for its new cost-plus drilling +arrangements, which reduced drilling costs by $74.6 million for the year as +discussed above. +The +new +cost-plus drilling arrangement eliminates the Company's risk of loss from the +contract drilling services it provides the partnerships. The Company’s drilling +revenues and corresponding costs are presented net as a one-lined income +statement item representing only the gross profit portion of the drilling +arrangement. The new cost-plus contract impacted the current year period by +reducing drilling revenues and drilling costs by $74.6 million as outlined +in +the table below (in millions): +Year +ended December 31, +2006 +2005 +Drilling +Service +Revenue/Cost +Direct +Reimbursed +Cost +Revenue/Cost +Including +reimbursement +from +Partnerships +Drilling +Service +Revenue/Cost +Oil +and gas well drilling operations +$ +17.9 +$ +74.6 +$ +92.5 +$ +100.0 +Total +revenues +$ +286.5 +$ +74.6 +$ +361.1 +$ +325.2 +Cost +of oil and gas well drilling operations +$ +12.6 +$ +74.6 +$ +87.2 +$ +88.2 +Total +costs and expenses +$ +232.7 +$ +74.6 +$ +307.3 +$ +267.4 +Although +the Company changed to cost-plus drilling arrangements with its two recent +partnerships, prior footage-based contracts continue to be in effect, and +realized a loss of $2.1 million during 2006. This loss contributed to the +decrease in the drilling and development segment gross margin from $11.8 million +for the year ended December 31, 2005, to $5.3 million +for the year ended December 31, 2006. This loss was due to some drilling and +completion difficulties incurred and significantly increasing well drilling +and +completion costs, particularly the costs of fracturing and rising steel costs +for casing and other well equipment and oil field services. Future partnerships +will be drilled on a “cost-plus basis,” which should reduce these fluctuations +in drilling gross margins. See Note 1 to the consolidated financial +statements. +Natural +Gas Marketing Activities +Natural +gas sales from the marketing activities of RNG, the Company's marketing +subsidiary, increased for the year ended December 31, 2006, to $131.3 million +compared to $121.1 million for the year ended December 31, 2005, an increase +of +approximately $10.2 million, or 8.4%. The increase was the result of a 9% +increase in volumes sold at prices 17.2% lower than 2005 levels and significant +unrealized gains on derivative transactions which amounted to approximately +$12.3 million for the year ended December 31, 2006, compared to unrealized +losses of $8.5 million for the year ended December 31, 2005. +The +costs +of gas marketing activities for the year ended December 31, 2006, were $130.2 +million compared to $119.6 million for the year ended December 31, 2005, an +increase of $10.6 million, or 8.9%. The increase was due to higher average +volumes of natural gas purchased for resale and a significant increase in +unrealized losses on derivative transactions, which amounted to approximately +$11.9 million for the year ended December 31, 2006, compared to an unrealized +gain of $8.3 million for the year ended December 31, 2005. Income before income +taxes for the Company's natural gas marketing subsidiary increased from $1.7 +million for the year ended December 31, 2005, to $1.8 million for the year +ended +December 31, 2006. Based on the nature of the Company's gas marketing +activities, derivatives did not have a significant impact on the Company's +net +margins from marketing activities during either period. +32 +Index +Oil +and Gas Sales +Oil +and +gas sales from the Company's producing properties for the year ended December +31, 2006, were $115.2 million compared to $102.6 million for the year ended +December 31, 2005, an increase of $12.6 million, or 12.3%. The increase was +due +to a 24% increase in volumes sold at lower average sales prices of natural +gas +and, in part, to higher average sales prices and higher volumes sold of oil. +The +volume of natural gas sold for the year ended December 31, 2006, was 13.2 Bcf +at +an average price of $5.91 per Mcf compared to 11.0 Bcf at an average sales +price +of $7.29 per Mcf for the year ended December 31, 2005. Oil sales for the year +ended December 31, 2006, were 631,000 barrels at an average sales price of +$59.33 per barrel compared to 439,000 barrels at an average sales price of +$50.56 per barrel for the year ended December 31, 2005. The increase in natural +gas and oil volumes was the result of the Company's increased investment in +oil +and gas properties, primarily the increase in net wells drilled for the +Company’s own account, recompletions of existing wells, and the investment in +oil and gas properties it owns in drilling program partnerships. +Oil +and Gas Production +The +Company's oil and gas production by area of operations along with average sales +price (excluding derivative gains and losses) is presented below: +Year +Ended December 31, 2006 +Year +Ended December 31, 2005 +Oil +(Bbl) +Natural +Gas +(Mcf) +Natural +Gas +Equivalents +(Mcfe)* +Oil +(Bbl) +Natural +Gas +(Mcf) +Natural +Gas +Equivalents +(Mcfe)* +Appalachian +Region +1,837 +1,451,729 +1,462,751 +3,973 +1,631,552 +1,655,390 +Michigan +Region +4,439 +1,399,852 +1,426,486 +4,732 +1,555,958 +1,584,350 +Rocky +Mountain Region +625,119 +10,309,203 +14,059,917 +430,266 +7,843,250 +10,424,846 +Total +631,395 +13,160,784 +16,949,154 +438,971 +11,030,760 +13,664,586 +Average +Sales Price +$ +59.33 +$ +5.91 +$ +6.80 +$ +50.56 +$ +7.29 +$ +7.51 +*Six +Bbl +equals one Mcfe +Financial +results depend upon many factors, particularly the price of natural gas and +the +Company’s ability to market its production effectively. Natural gas and oil +prices have been among the most volatile of all commodity prices. These price +variations can have a material impact on the Company’s financial results. +Natural gas and oil prices also vary by region, and locality, depending upon +the +distance to markets, and the supply and demand relationships in that region +or +locality. This can be especially true in the Rocky Mountain Region. The +combination of increased drilling activity and the lack of local markets can +entail a local oversupply situation from time to time. There are a number of +different pipelines in various stages of construction which will help to +maintain a balance between supply and demand. However, there may be times in +which there may be oversupply situations for short or longer terms, which may +affect the amount of gas or oil that the Company can sell, and the price at +which it sells gas or oil. Like most other producers in the region, the Company +relies on major interstate pipeline companies to construct these facilities, +so +their timing is not within its control. +Oil +and Gas Derivative Activities +Because +of uncertainty surrounding natural gas prices, the Company has used various +derivative instruments to manage some of the impact of fluctuations in prices. +Through October 2008, the Company has in place a series of floors and ceilings +associated with part of its natural gas production. Under the arrangements, +if +the applicable index rises above the ceiling price, the Company pays the +counterparty; however, if the index drops below the floor, the counterparty +pays +us. During the three months ended December 31, 2006, the Company averaged +natural gas volumes sold of 1,283,000 Mcf per month and oil sales of 52,000 +barrels per month. The positions in effect as of May 10, 2007, on the Company's +share of production (the +table below does not include positions related to RNG activities or derivative +contracts entered into by the Company on behalf of the affiliate Partnerships +as +the Managing General Partner) +by area +are shown in the following table. +33 +Index +Floors +Ceilings +Monthly +Quantity +Gas-MMbtu +Oil-Bbls +Contract +Price +Monthly +Quantity +MMbtu +Contract +Price +Month +Set +Months +Covered +Colorado +Interstate Gas (CIG) Based Hedges (Piceance Basin) +Feb-06 +May +2007 – Oct 2007 +44,000 +$ +5.50 +- +$ +- +Sep-06 +May +2007 – Oct 2007 +194,500 +4.50 +- +- +Dec-06 +Nov +2007 – Mar 2008 +100,000 +5.25 +- +- +Jan-07 +Nov +2007 – Mar 2008 +100,000 +5.25 +100,000 +9.80 +May-07 +Apr +2008 – Oct 2008 +197,250 +5.50 +197,250 +10.35 +NYMEX +Based Hedges - (Appalachian and Michigan Basins) +Feb-06 +May +2007 – Oct 2007 +85,000 +7.00 +- +- +Feb-06 +May +2007 – Oct 2007 +85,000 +7.50 +34,000 +10.83 +Sep-06 +May +2007 – Oct 2007 +85,000 +6.25 +- +- +Jan-07 +May +2007 – Oct 2007 +85,000 +5.25 +- +- +Dec-06 +Nov +2007 – Mar 2008 +144,500 +7.00 +- +- +Jan-07 +Nov +2007 – Mar 2008 +144,500 +7.00 +153,000 +13.70 +Jan-07 +Apr +2008 – Oct 2008 +144,500 +6.50 +153,000 +10.80 +Panhandle +Based Hedges (NECO) +Feb-06 +May +2007 – Oct 2007 +60,000 +6.00 +- +- +Feb-06 +May +2007 – Oct 2007 +60,000 +6.50 +60,000 +9.80 +Jan-07 +May +2007 – Oct 2007 +90,000 +4.50 +- +- +Dec-06 +Nov +2007 – Mar 2008 +70,000 +5.75 +- +- +Jan-07 +Nov +2007 – Mar 2008 +90,000 +6.00 +90,000 +11.25 +Jan-07 +Apr +2008 – Oct 2008 +90,000 +5.50 +90,000 +9.85 +DJ +Basin +Jan-07 +May +2007 – Oct 2007 +161,000 +4.00 +- +- +Jan-07 +Nov +2007 – Mar 2008 +90,000 +5.25 +90,000 +9.80 +May-07 +Apr +2008 – Oct 2008 +216,000 +5.50 +216,000 +10.35 +DJ +Basin EXCO Property Acquisition +Jan-07 +May +2007 – Oct 2007 +60,000 +4.00 +- +- +Jan-07 +Nov +2007 – Mar 2008 +30,000 +5.25 +30,000 +9.80 +May-07 +Apr +2008 – Oct 2008 +90,000 +5.50 +90,000 +10.35 +Oil +– NYMEX Based (Wattenberg/ND) +Sep-06 +May +2007 – Oct 2007 +12,350 +50.00 +- +- +Well +Operations and Pipeline Income +Well +operations and pipeline income for the year ended December 31, 2006, were $10.7 +million compared to $8.8 million for the year ended December 31, 2005, an +increase of approximately $1.9 million, or 21.6%. The increase was due to an +increase in the number of wells and pipeline systems operated by the Company +for +drilling partnerships, as well as for third parties. +Oil +and Gas Price Risk Management Gains (Losses), Net +Oil +and +gas price risk management gains (losses), net for the year ended December 31, +2006, was an aggregate gain of $9.1 million compared to a loss of approximately +$9.4 million for the year ended December 31, 2005, a favorable change of $18.5 +million. For the year ended December 31, 2006, the Company recorded realized +gains of $1.9 million and unrealized gains of $7.2 million compared to the +year +ended December 31, 2005, which is comprised of unrealized losses of $3 million +and realized losses of $6.4 million. The Company’s strategy is to provide +protection in the event of declining oil and natural gas prices. During 2006, +the Company experienced decreasing natural gas and rising oil pricing +environments. This trend and the timing, extent and nature of the derivative +trades executed caused the Company to record gains in its derivative +transactions as a result of gains on the natural gas positions. Oil and gas +price risk management gains (losses), net is comprised of the change in fair +value of oil and natural gas derivatives related to oil and gas production +(this +line item does not include commodity-based derivative transactions related +to +transactions from gas marketing activities, which are included in the revenues +and expenses of the related purchase and sales transactions). +34 +Index +Other +Income +Other +income, consisting primarily of management fees associated with +Company-sponsored drilling programs, was relatively unchanged at $2.2 million +for each of the years ended December 31, 2006 and 2005. +Oil +and Gas Production and Well Operations Costs +Oil +and gas production and well +operations costs from the Company’s producing properties for the year ended +December 31, 2006, were $29.0 million compared to $20.4 million for the year +ended December 31, 2005, an increase of approximately $8.6 million, or +42.2%. The increase was due to the increased production costs +associated with the 24% increase in production volumes, along with the increased +number of wells and pipelines operated by the Company. Lifting costs +per Mcfe increased from $1.19 per Mcfe for the year ended December 31, 2005, +to +$1.23 per Mcfe for the year ended December 31, 2006, due to the significant +inflation of oil field production services along with additional well workovers +and production enhancements work performed. +Exploration +Cost +The +Company’s exploration cost for December 31, 2006, decreased $3 million from +$11.1 million for the same period last year to $8.1 million. The +decrease is primarily attributable to fewer exploratory dry holes being drilled +in 2006. In 2006, exploratory dry hole expenses were $1.8 million +compared to $11.1 million in 2005. In 2006, the Company recorded an +impairment charge of $1.5 million on its Nesson Field in North Dakota and +incurred geological and geophysical costs of $2.2 million which relate to +an +exploratory seismic program initiated on the Company’s Northeast Colorado +properties. The Company anticipates additional geological and +geophysical activities and related costs in 2007. +General +and Administrative Expense +General +and administrative expense for +the year ended December 31, 2006, increased to $19 million compared to $7 +million for the year ended December 31, 2005, an increase of approximately +$12 +million, or 171.4%. A substantial portion of the increase was +attributable to the costs of the Company’s financial statement restatement and +the restatement of the Company-sponsored partnerships’ financial +statements. In addition, the Company continues to experience a high +level of costs complying with the various provisions of Sarbanes-Oxley, in +particular Section 404 (internal and external costs of assessing Internal +Controls over Financial Reporting). Approximately $3.2 million of the +increase is attributable to the external costs incurred in connection with +restatement of financial statements and compliance with the provisions of +Sarbanes-Oxley. Finally, the Company added over 39 new +employees in 2006 and experienced increased payroll and payroll-related costs +of +$4.3 million. +Depreciation, +Depletion, and Amortization +Depreciation, +depletion, and +amortization costs for the year ended December 31, 2006, increased to $33.7 +million from approximately $21.1 million for the year ended December 31, +2005, +an increase of approximately $12.6 million, or 59.7%. The increase +was due to the 24% increase in production volumes, significant investments +in +oil and gas properties by the Company in 2006, and increased per unit cost +of +depreciation, depletion and amortization as a result of rising costs of +drilling, completing and equipping wells. +Gain +on Sale of Leaseholds +Gain +on +sale of leaseholds for the year ended December 31, 2006, was $328 million +compared to $7.7 million in 2005, an increase of $320.3 million. The increase +is +attributable to the sale of undeveloped leaseholds in Garfield County, Colorado +in the third quarter of 2006, for which a portion of the gain to be recognized +was deferred to future periods. See Note 15 to consolidated financial +statements. The prior year period included a gain of $6.2 million for the sale +of a portion of one of the Company’s undeveloped leases in Garfield County, +Colorado and a gain of $1.5 million for the sale to an unaffiliated party of +some Pennsylvania wells. +35 +Index +Interest +Income +For +the +year ended December 31, 2006, interest income increased $7.2 million to $8.1 +million compared to $0.9 million for the prior year period. The increase was +primarily due to the interest income on the temporary investment, in cash +equivalents, of cash proceeds of $353.6 million from the sale of undeveloped +leaseholds. +Interest +Expense +Interest +expense for the year ended December 31, 2006, was $2.4 compared to $0.2 million +for the year ended December 31, 2005, an increase of $2.2 million. The increase +in interest expense was due to rising interest rates on significantly higher +average outstanding balances of the credit facility, offset in part by $1.6 +million of capitalized construction period interest. The Company utilizes its +daily cash balances to reduce its line of credit to lower its cost of borrowing. +The average outstanding debt balance for the year ended December 31, 2006, +was +$44.2 million compared to $4.1 million for the year ended December 31, 2005. +Provision +for Income Taxes +The +effective income tax rate for the Company's provision for income taxes increased +from 37.3% for the year ended December 31, 2005, to 38.6% for the year ended +December 31, 2006, primarily as a result of the gain on sale of leasehold being +taxed at the full federal and state statutory rates because there are no +offsetting permanent deductions, such as percentage depletion, available on +such +a sale. In addition, the domestic production activities deduction was not +utilized in 2006 due to the Company’s decision, for tax purposes only, to +expense the majority of its intangible drilling costs. +Year +Ended December 31, 2005, Compared to December 31, +2004 +Revenues +Total +revenues for the year ended December 31, 2005, were $325.2 million compared +to +$264.5 million for the year ended December 31, 2004, an increase of +approximately $60.7 +million, +or 22.9% . +The +increase was a result of increased drilling revenues, gas sales from natural +gas +marketing activities, oil and gas sales, well operations and pipeline income, +and other income partially offset by increased oil and gas price risk management +losses. +Costs +and Expenses +Total +costs and expenses for the year ended December 31, 2005, were $267.4 million +compared to $211 million for the year ended December 31, 2004, an increase +of +approximately $56.4 million or 26.7%. The increase was primarily the result +of +increased cost of oil and gas well drilling operations, cost of gas marketing +activities, oil and gas production and well operations cost, exploration costs, +general and administrative expenses and depreciation, depletion and +amortization. +Drilling +Operations +Drilling +revenues for the year ended December 31, 2005, were $100 million compared to +$94.1 million for the year ended December 31, 2004, an increase of approximately +$5.9 million or 6.3%. Such increase was due to the increased drilling funds +raised and drilled during the year through the Company's drilling programs. +The +Company-sponsored drilling programs in 2005 (two public and one private) raised +$116 million compared to $100 million in 2004. The Company believes higher +oil +and natural gas prices and the resulting improved performance of prior programs +are the reasons for the increase in drilling program sales. +Oil +and +gas well drilling operations costs for the year ended December 31, 2005, were +$88.2 million compared to $77.7 million for the year ended December 31, 2004, +an +increase of approximately $10.5 million or 13.5%. The increase was due to the +higher levels of drilling activity from public drilling programs referred to +above and increased costs from higher charges for services and materials +provided to the Company. The gross margin on the drilling activities for the +year ended December 31, 2005 was 11.8% compared with 17.4% for the year ended +December 31, 2004, a decrease in gross margin of approximately 5.6%. The +decrease was due to significantly increasing well drilling and completion costs, +particularly the costs of fracturing and rising steel costs for casing and +other +well equipment and oil field services. The +private drilling partnership funded on December 30, 2005, with wells to be +drilled during the first quarter of 2006 and future partnerships will be drilled +on a "cost plus basis"; that should reduce these fluctuations in drilling gross +margins. +36 +Index +This +new +cost-plus drilling arrangement eliminates the Company's risk of loss, thus +the +drilling revenues and corresponding costs will be netted to a one-lined income +statement item representing only the gross profit portion of the drilling +arrangement. This would have a significant effect on the Company's 2006 gross +drilling revenues and corresponding drilling expenses, but would not change +the +gross profit. +Natural +Gas Marketing Activities +Natural +gas sales from the marketing activities of RNG, the Company's marketing +subsidiary for the year ended December 31, 2005, were $121.1 million compared +to +$94.6 million for the year ended December 31, 2004, an increase of approximately +$26.5 million or 28.0%. The increase was the result of significantly higher +average natural gas sales prices and higher volumes sold offset in part by +an +increase in unrealized losses on derivative transactions which amounted to +approximately $8.5 million in 2005 compared to unrealized gains of $1.2 million +in 2004. +The +costs +of gas marketing activities for the year ended December 31, 2005, were $119.6 +million compared to $92.9 million for the year ended December 31, 2004, an +increase of $26.7 million or 28.7%. The increase was due to higher average +volumes of natural gas purchased for resale and significantly higher average +purchase prices offset in part by an increase in unrealized gains on derivative +transactions which amounted to approximately $8.3 million in 2005 compared +to +unrealized losses of $0.8 million in 2004. Income before income taxes for the +Company's natural gas marketing subsidiary decreased from $1.8 million for +the +year ended December 31, 2004, to $1.7 million for the year ended December 31, +2005. Based on the nature of the Company's gas marketing activities, derivatives +did not have a significant impact on the Company's net margins from marketing +activities during either period. +Oil +and Gas Sales +Oil +and +gas sales from the Company's producing properties for the year ended December +31, 2005, were $102.6 million compared to $69.5 million for the year ended +December 31, 2004, an increase of $33.1 million or 47.6%. The increase was +due +to higher volumes sold at significantly higher average sales prices of oil +and +natural gas. The volume of natural gas sold for the year ended December 31, +2005, was 11 million Mcf at an average price of $7.29 per Mcf compared to 10.4 +million Mcf at an average sales price of $5.30 per Mcf for the year ended +December 31, 2004. Oil sales for the year ended December 31, 2005, were 439,000 +barrels at an average sales price of $50.56 per barrel compared to 381,000 +barrels at an average sales price of $38.00 per barrel for the year ended +December 31, 2004. The increase in natural gas and oil volumes was the result +of +the Company's increased investment in oil and gas properties, primarily +recompletions of existing wells, wells drilled in the NECO, Colorado area of +operation, and the investment in oil and gas properties the Company owns in +the +public drilling program partnerships. +Oil +and Gas Production +The +Company's oil and gas production by area of operations along with average sales +price (excluding derivative losses) is presented below: +Year +Ended December 31, 2005 +Year +Ended December 31, 2004 +Oil +(Bbl) +Natural +Gas +(Mcf) +Natural +Gas +Equivalents +(Mcfe) +Oil +(Bbl) +Natural +Gas +(Mcf) +Natural +Gas +Equivalents +(Mcfe) +Appalachian +Region +3,973 +1,631,552 +1,655,390 +4,893 +1,812,407 +1,841,765 +Michigan +Region +4,732 +1,555,958 +1,584,350 +5,786 +1,728,435 +1,763,151 +Rocky +Mountain Region +430,266 +7,843,250 +10,424,846 +370,482 +6,831,032 +9,053,924 +Total +438,971 +11,030,760 +13,664,586 +381,161 +10,371,874 +12,658,840 +Average +Sales Price +$ +50.56 +$ +7.29 +$ +7.51 +$ +38.00 +$ +5.30 +$ +5.49 +Financial +results depend upon many factors, particularly the price of natural gas and +the +Company’s ability to market its production effectively. In recent years, natural +gas and oil prices have been among the most volatile of all commodity prices. +These price variations can have a material impact on the Company’s financial +results. Natural gas prices in the Rocky Mountain Region continue to trail +prices which the Company receives for Appalachian and Michigan gas. The +Company’s management believes the lower prices in the Rocky Mountain Region, +including Colorado, reflect the higher costs to move gas to major market areas +compared to Michigan and the Appalachian Basin resulting in a lower price +compared to the eastern areas. In May 2003, a pipeline expansion project was +completed, leading to improved natural gas prices in the region which reduced +the local surplus. There is currently a substantial amount of drilling activity +in the Rockies, and if future additions to the pipeline system are not made +in a +timely fashion it is possible that pipeline constraints could create a local +oversupply situation in the future which could mean lower natural gas prices. +Like most other producers in the area the Company relies on major interstate +pipeline companies to construct these facilities, so their timing and +construction is not within its control. +37 +Index +Oil +and Gas Derivative Activities +Because +of uncertainty surrounding natural gas prices the Company has used various +derivative instruments to manage some of the impact of fluctuations in prices. +At April 30, 2006, the Company had in place, through October 2007, a series +of +floors and ceilings on part of natural gas production. Under the arrangements, +if the applicable index rises above the ceiling price, the Company pays the +counterparty, however if the index drops below the floor the counterparty pays +us. During the three months ended December 31, 2005, the Company averaged +natural gas volumes sold of 973,700 Mcf per month and oil sales of 36,050 +barrels per month. The positions in effect as of April 30, 2006, on the +Company's share of production (the table below does not include positions +related to Riley Marketing activities or derivative contracts entered into +by +the Company on behalf of the affiliate Partnerships as the Managing General +Partner) by area are shown in the following table. +Floors +Ceilings +Month +Set +Contract +Term +Monthly +Quantity +Gas-MMbtu +Oil-Barrels +Contract +Price +Monthly +Quantity +Gas-MMbtu +Oil-Barrels +Contract +Price +Colorado +Interstate Gas (CIG) Based Derivatives (Piceance +Basin) +Jan-05 +Jan +2006 – Mar 2006 +60,000 +$ +4.50 +30,000 +$ +7.15 +Jul-05 +Jan +2006 – Mar 2006 +27,500 +6.50 +13,750 +8.27 +Sep-05 +Jan +2006 – Mar 2006 +78,700 +9.00 +- +- +Mar-05 +Apr +2006 – Oct 2006 +42,000 +4.50 +21,000 +7.25 +Jul-05 +Apr +2006 – Oct 2006 +27,500 +5.50 +13,750 +7.63 +Jul-05 +Nov +2006 – Mar 2007 +27,500 +6.00 +13,750 +8.40 +Feb-06 +Nov +2006 – Mar 2007 +60,000 +6.50 +- +- +Feb-06 +Apr +2007 – Oct 2007 +44,000 +5.50 +- +- +NYMEX +Based Derivatives - (Appalachian and Michigan Basins) +Jan-05 +Jan +2006 – Mar 2006 +156,000 +5.00 +78,000 +8.50 +Sep-05 +Jan +2006 – Mar 2006 +156,000 +10.50 +- +- +Mar-05 +Apr +2006 – Oct 2006 +78,000 +5.50 +39,000 +7.40 +Jul-05 +Apr +2006 – Oct 2006 +61,000 +6.25 +30,000 +8.98 +Jul-05 +Nov +2006 – Mar 2007 +68,000 +7.00 +34,000 +9.27 +Feb-06 +Nov +2006 – Mar 2007 +34,000 +8.00 +- +- +Feb-06 +Nov +2006 – Mar 2007 +34,000 +8.50 +34,000 +13.73 +Feb-06 +Apr +2007 – Oct 2007 +34,000 +7.00 +- +- +Feb-06 +Apr +2007 – Oct 2007 +34,000 +7.50 +34,000 +10.83 +NYMEX +Based Derivatives (NECO) +Jan-05 +Jan +2006 – Mar 2006 +150,000 +5.00 +75,000 +8.45 +Panhandle +Based Derivatives (NECO) +Sep-05 +Jan +2006 – Mar 2006 +100,000 +10.00 +- +- +Mar-05 +Apr +2006 – Oct 2006 +150,000 +5.00 +75,000 +8.62 +Jul-05 +Nov +2006 – Mar 2007 +150,000 +6.50 +75,000 +8.56 +Feb-06 +Apr +2007 – Oct 2007 +60,000 +6.00 +- +- +Feb-06 +Apr +2007 – Oct 2007 +60,000 +6.50 +60,000 +9.80 +38 +Index +Well +Operations and Pipeline Income +Well +operations and pipeline income for the year ended December 31, 2005, were $8.8 +million compared to $7.7 million for the year ended December 31, 2004, an +increase of approximately $1.1 million or 14.3%. The increase was due to an +increase in the number of wells and pipeline systems operated by the Company +for +public drilling programs as well as for third parties. +Oil +and Gas Price Risk Management Losses, Net +Oil +and +gas price risk management loss, net for the year ended December 31, 2005, was +$9.4 million compared to approximately $3.1 million for the year ended December +31, 2004, an increase of $6.3 million. For the year ended December 31, 2005, +the +Company recorded unrealized losses of $3 million and realized losses of $6.4 +million compared to the year ended December 31, 2004, which is comprised of +unrealized losses of $1.5 million and realized losses of $1.6 million. The +Company’s strategy in its derivative policy is to provide protection on +declining oil and natural gas prices. During 2005, the Company experienced +rising oil and natural gas pricing environment, this trend caused the Company +to +record losses in its derivative transactions. In a declining oil and natural +gas +pricing environment the Company would, in theory, record gains in its derivative +transaction activities. Oil and gas price risk management losses, net is +comprised of the change in fair value of oil and natural gas derivatives related +to oil and gas production (this line item does not include commodity based +derivative transactions related to transactions from marketing +activities). +Other +Income +Other +income for the year ended December 31, 2005, was $2.2 million compared to $1.7 +million for the year ended December 31, 2004, an increase of $0.5 +million. +Oil +and Gas Production and Well Operations Costs +Oil +and +gas production and well operations costs from the Company’s producing properties +for the year ended December 31, 2005, were $20.4 million compared to $17.7 +million for the year ended December 31, 2004, an increase of approximately +$2.7 +million or 15.3%. The increase was due to the increased production costs and +severance and property taxes on the increased volumes and higher average sales +prices of natural gas and oil sold, along with the increased number of wells +and +pipelines operated by the Company. Lifting costs per Mcfe increased from a +restated $1.12 per Mcf for the year ended December 31, 2004, to $1.19 per Mcfe +for the year ended December 31, 2005, due to increased severance and property +taxes on the significantly increased oil and gas sales prices along with +additional well workovers and production enhancements work performed. +Exploration +Costs +The +Company drilled eight exploratory wells in 2005 of which five were deemed to +be +dry holes. In the fourth quarter of 2005, four Kansas wells were drilled, +plugged and abandoned for a total combined cost of $0.3 million, including +lease +acreage cost of $0.1 million, was expensed due to impairment. Also in the fourth +quarter, the Coffeepot Springs #24-34 well in Colorado was determined to be +uneconomical at a total dry hole cost of approximately $5.4 million, including +lease acreage cost of $0.1 million, and expensed due to impairment. In the +second quarter of 2005, it was determined the Fox Federal #1-13 well, which +was +drilled in 2004 in Colorado, was also an uneconomic well and total costs of +approximately $5.4 million, including lease acreage cost of $0.4 million, was +expensed due to impairment. These exploratory dry hole expenses were expensed +in +the period in which it was determined that the well was unsuccessful in +accordance with the successful efforts method of accounting. All costs were +incurred 100% by the Company because the drilling fund partnerships did not +participate in these exploratory wells. +General +and Administrative Costs +General +and administrative expenses for the year ended December 31, 2005, increased +to +$7 million compared to $4.5 million for the year ended December 31, 2004, an +increase of approximately $2.5 million or 55.6%. The increase was primarily +due +to increased costs of complying with the various provisions of Sarbanes-Oxley, +in particular Section 404 (Internal Controls), the cost of the Company's +financial statement restatements and increased personnel costs for the increased +number of employees. +Depreciation, +Depletion, and Amortization +Depreciation, +depletion, and amortization costs for the year ended December 31, 2005, +increased to $21.1 million from approximately $18.2 million for the year ended +December 31, 2004, an increase of approximately $2.9 million +or +15. 9%. +Such +increase was due to the significantly increased production and investment in +oil +and gas properties by the Company as referred to above. +39 +Index +Gain +on Sale of Leaseholds +For +the +year ended December 31, 2005, the Company recognized a gain on sale of +leaseholds totaling $7.7 million, $6.2 million for the sale to an unaffiliated +entity of undeveloped leases in Garfield County, Colorado and $1.5 million +for +the sale to an unaffiliated party of some Pennsylvania wells. The Company +recognized no gains on the sale of leaseholds in 2004. +Interest +Income +The +increase in interest income from 2004 to 2005 of approximately $0.7 was +primarily attributable to higher average cash balances and higher interest +rates. +Interest +Expense +Interest +expense was relatively unchanged for the year ended December 31, 2005, compared +the year ended December 31, 2004. The Company utilizes its daily cash balances +to reduce its line of credit to lower its cost of borrowing. The average +outstanding debt balances for the year ended December 31, 2005, was $4.1 million +compared to $11.3 million for the year ended December 31, 2004. +Provision +for Income Taxes +The +effective income tax rate for the Company's provision for income taxes decreased +from 37.9% for the year ended December 31, 2004, to 37.3% for the year ended +December 31, 2005, primarily as a result of the domestic production activities +deduction. +Liquidity +and Capital Resources +The +Company funds its operations through a combination of cash flow from operations +and use of the Company's credit facility. Operating cash flow is generated +by +sales of natural gas and oil from the Company's well interests, natural gas +marketing, profits from well drilling and operating activities from the +Company's drilling programs and others, and natural gas gathering and +transportation. Cash payments from Company-sponsored partnerships are used +to +drill and complete wells for the partnerships, with operating cash flow accruing +to the Company to the extent payments exceed drilling costs. The Company +utilizes its revolving credit arrangement to meet the cash flow requirements +of +its operating and investment activities. Management of the Company believes +that +such credit arrangements are adequate to meet its cash and liquidity +requirements. +In +July +2006, the Company sold to an unaffiliated company a portion of its undeveloped +leaseholds in Grand Valley Field, Colorado, for cash proceeds of $353.6 million. +Proceeds in the amount of $300 million were transferred to a qualified +intermediary to be held in trust pursuant to the terms of a "like-kind exchange" +agreement. In January 2007, the Company acquired, in accordance with the +"like-kind exchange" agreement, oil and gas properties totaling $191.5 million. +Following the payment of approximately $20 million in federal taxes, the Company +will have available approximately $90 million in cash to fund 2007 drilling +activities. Approximately $18.6 million, including direct costs of the +acquisition, of the non-designated proceeds was utilized in 2006 to fund the +acquisition of Unioil. The remaining unused portion of the like-kind funds +were +utilized to purchase a variety of other oil and gas properties and to pay down +the outstanding balance of the Company's credit facility. +Natural +Gas Pricing and Pipeline Capacity +The +Company sells natural gas under contracts that are priced based on spot prices +or price indexes that reflect current market prices for the commodity. As a +result, variations in the market are reflected in the revenue the Company +receives. The price of natural gas has varied substantially over short periods +of time in the past, and there is every reason to expect a continuation of +that +variability in the future. During 2006, prices for natural gas decreased from +the last part of 2005 but were still close to record levels, and future +expectations as reflected in NYMEX futures market are for continuing high price +levels for 2007 and beyond. Strong domestic and international demand for energy +and inadequate short term supplies are believed to be key causes of the strong +prices. High prices could encourage the development of new energy sources and +reduced consumption as users find more efficient ways to use energy or +substitute other energy forms. High energy prices could also slow global +economic growth, further reducing demand. As a result, the energy price outlook +could change rapidly from current expectations. Reduced natural gas prices +would +reduce the profitability and cash flow from the Company's gas production +operations. +Financial +results depend upon many factors, particularly the price of natural gas and +the +Company’s ability to market its production effectively. Natural gas and oil +prices have been among the most volatile of all commodity prices. These price +variations can have a material impact on the Company’s financial results. +Natural gas and oil prices also vary by region, and locality, depending upon +the +distance to markets, and the supply and demand relationships in that region +or +locality. This can be especially true in the Rocky Mountain region. The +combination of increased drilling activity and the lack of local markets can +entail a local oversupply situation from time to time. There are a number of +different pipelines in various stages of construction which would help to +maintain a balance between supply and demand. However, there may be times in +which oversupply situations occur for short or longer terms, which may affect +the amount of gas or oil that the Company can sell, and the price at which +it +sells gas or oil. Like most other producers in the region, the Company relies +on +major interstate pipeline companies to construct these facilities, so their +timing is not within its control. +40 +Index +Oil +Pricing +Oil +prices were near or above record levels for most of 2005 and continued through +2006. The Company's oil prices are largely determined by oil prices in the +world +market. Global supply and demand and geopolitical factors are the key +determinants of oil prices. The rapid growth of energy use in developing +countries, most notably China, is driving a rapid increase in worldwide oil +consumption. Higher prices could result in reduced consumption and/or increasing +supplies that could moderate the current high price levels. Over the past +several years, oil has been an increasing part of the Company's production +mix. +As a result, higher oil prices have contributed to the Company's increased +revenue from oil and gas sales more than in the past, and the Company would +suffer a greater impact if oil prices were to decrease. Oil sales accounted +for +33% of the Company's oil and gas sales during 2006 compared to 21.6% in +2005. +Oil +and Gas Derivative Activities +Because +of the uncertainty surrounding natural gas and oil prices, the Company has +used +various derivative instruments to manage some of the impact of fluctuations +in +prices. The Company has in place a series of floors and ceilings on part of +natural gas and oil production, which extend through October 2008. Under the +arrangements, if the applicable index rises above the ceiling price, the Company +pays the counterparty; however, if the index drops below the floor, the +counterparty pays the Company. See the section titled "Oil and Gas Derivative +Activities" as discussed in results of operations for a more detailed analysis +of the Company's current derivative positions. +The +Company uses derivative investments to protect prices for its partners' share +of +production as well as its own production. Actual wellhead prices will vary +based +on local contract conditions, gathering and other costs and factors. The Company +records the fair value of its partners' share of outstanding derivatives and +the +partners' share of the corresponding obligation or benefit in accounts +receivable or other liabilities as appropriate. +The +Company’s derivative transactions do not currently qualify for hedge accounting +under SFAS No. 133. Therefore, the Company records its derivative gains and +losses, both realized and unrealized, through oil and gas price risk management +for its share of production. The Company is required to mark-to-market its +derivative positions at the end of each period and record the adjustment to +the +consolidated statement of income under oil and gas price risk management. This +may and does cause wide variability in profits from period to period. In 2005, +the Company's recognized oil and gas price risk management losses, net of $9.4 +million compared to oil and gas price risk management gains, net of $9.1 million +in 2006. +Drilling +Programs +On +September 1, 2006, the Company funded its 2006 partnership, Rockies Region +2006 +Limited Partnership, with subscriptions of approximately $90 million. Upon +closing on September 1, 2006, the Company, as managing general partner, +contributed in cash a total of $38.9 million for its contribution to the total +capital of the partnership. After payment of sales commissions and associated +expenses, including a management fee of $1.3 million to the Company, the +partnership had a total of approximately $118 million available for future +drilling. Drilling operations commenced on September 1, 2006, and will continue +through the first quarter of 2007. All of the 2006 partnership's 97 wells have +been drilled as of March 31, 2007. +The +Company invests, as its equity contribution to each drilling partnership, a +sum +equal to approximately 43% of the aggregate subscriptions received in the +current drilling partnership being offered. As a result, the Company is subject +to substantial cash commitments at the closing of each drilling partnership. +No +assurance can be made that the Company will continue to receive this level +of +funding from these or future programs. +41 +Index +Substantially +all of the Company's drilling programs contain a provision allowing investors +to +request that the Company purchase their partnership units. This provision is +in +effect any time beginning with the third anniversary of the first cash +distribution. If investors request that the Company repurchase their units, +the +provision provides that the Company is obligated to purchase an aggregate of +10% +of the initial subscriptions per calendar year (at a minimum price of four +times +the most recent 12 months' cash distributions), subject to the Company's +financial ability to do so. The maximum annual 10% purchase obligation, if +requested by the investors, is currently approximately $12.3 million. The +Company has adequate liquidity to meet this obligation. During 2006, the Company +spent $0.8 million acquiring additional partnership interests under this +provision. As of December 31, 2006, pursuant to this provision, outstanding +purchase offers to investing partners totaled $0.2 million. In 2007, $0.1 +million of such outstanding offers were consummated prior to their expiration +on +or before February 28, 2007. +Drilling +Activity +During +2006, the Company, for its own account and on behalf of its drilling fund +partnerships, drilled a total of 118 wells with one developmental dry hole. +The +Company drilled 81 successful wells in its Wattenberg Field in the +Denver-Julesburg Basin and 30 successful wells in the Piceance Basin in western +Colorado. Also in 2006, the Company and its drilling fund partnerships drilled +four wells in North Dakota. +During +2006, the Company drilled several development wells outside of the drilling +fund +partnerships. The Company drilled 34 wells on its northeast Colorado properties +and participated in 10 additional wells which were drilled by joint venture +partners. Of these 44 wells, 41 were successful. The Company also drilled 41 +Wattenberg Field wells and 19 Piceance Basin wells for its own account, of +which +58 were successful. The Company also drilled a successful developmental gas +well +in the Michigan Basin. In North Dakota, the Company and other joint venture +partners drilled one successful development well. +In +2006, +the Company included its drilling fund partnerships in its exploratory well +drilling activities by drilling two such wells within the parameters of the +partnership. One well in Wyoming was classified as dry and expensed in +accordance with the successful efforts method of accounting while the other +well +drilled in North Dakota was successful. The Company drilled for its own benefit +one well in North Dakota, as well as participated with other joint venture +partners, outside of the partnerships, in the drilling of six exploratory wells +also in North Dakota, all of which were considered successful. +The +company incurred exploratory dry hole costs of $1.8 million for the year ended +2006, of which $1.3 million was from one well drilled in Wyoming. The remaining +$0.5 million of expenses were incurred on wells previously classified as dry +holes in 2005. +Costs +of Oil and Gas Properties +Costs +incurred by the Company in oil and gas property acquisition, exploration and +development for the year ended December 31, 2006, are presented below (in +thousands): +Acquisition +of properties: +Unproved +properties +$ +11,926 +Proved +properties +802 +Development +costs +114,487 +Exploration +costs +20,894 +Total +costs incurred +$ +148,109 +Treasury +Share Purchases +On +January 13, 2006, the Company announced that +its +Board of Directors had authorized the purchase of up to 10% (1,627,500 shares) +of the Company's common stock during 2006. Stock purchases under this program +were made in the open market or in private transactions, at times and in amounts +that management deemed appropriate. In October 2006, the Company completed +its +January 2006 program. Total shares purchased pursuant to the program were +1,627,500 common shares at a cost of $66.3 million ($40.75 average price paid +per share), including 100,000 shares from an executive officer of the Company +at +a cost of $4.1 million ($40.66 price paid per share). All shares purchased +in +accordance with the program have subsequently been retired. +On +October 16, 2006, the Board of Directors of the Company approved a second 2006 +purchase program authorizing the Company to purchase up to 10% (1,477,109 +shares) of the Company’s then outstanding common stock through April 2008. Stock +purchases under this program may be made in the open market or in private +transactions, at times and in amounts that management deems appropriate. The +Company may terminate or limit the stock purchase program at any time. +42 +Index +Working +Capital +The +Company's working capital as of December 31, 2006, is $29.2 +million. The Company manages its working capital needs by only +drawing from its credit facility of $200 million as liabilities come due and +cash is required. At December 31, 2006, the Company had an activated +line of credit with an additional borrowing capacity, in excess of amounts +outstanding, of $18 million. +As +of +December 31, 2006, the Company had $300 million of cash in a “like-kind +exchange” trust, of which $109 million is classified in the consolidated balance +sheet as cash and the remaining $191.5 million is classified as designated +cash, +a non-current asset, as it represents the amount subsequently qualifying for +"like-kind exchange" treatment and used for the acquisition of oil and gas +properties completed in January 2007. At December 31, 2006, the Company has +adequate liquidity when considering these funds along with the credit facility +to meet both its working capital requirements and plans for continued investment +in oil and gas well drilling over the next year. +Long-Term +Debt +The +Company has a credit facility with JPMorgan Chase Bank, N.A. and BNP Paribas +of +$200 million subject to and secured by required levels of oil and gas reserves. +The current borrowing base, based upon oil and gas reserves, is $135 million. +The Company is required to pay a commitment fee of 0.25 to 0.375% per annum +on +the unused portion of the activated credit facility. Interest accrues at an +Alternative Base Rate, as defined in the credit facility or adjusted LIBOR +("London Interbank Market Rate") at the Company's discretion. No principal +payments are required until the credit agreement expires on November 4, 2010. +During March 2007, due to various reporting and processing delays, the Company +requested a waiver related to the Security assignment provisions of its credit +facility. During March 2007, the waiver was granted and the corresponding +Borrowing Base was reduced to $100 million from $135 million. See Note 5 to +the +consolidated financial statements for further information. +On +December 19, 2006, the Company executed pursuant to its credit facility a +short-term, non-revolving overline note in the amount of $20 million to be +repaid on or before January 31, 2007. The note was paid in full on January +31, +2007. Interest on the overline note accrued at a per annum rate equal to the +alternate base rate plus 0.80% until December 22, 2006, at which time the rate +converted to a Eurodollar borrowing for a one month period at a per annum rate +equal to an adjusted LIBOR rate plus 2.30%. The overline note is reflected +on +the consolidated balance sheet as a current liability. +As +of +December 31, 2006 and 2005, the outstanding balances under the facility, +including the overline note, were $137 million and $24 million, respectively. +Any amounts outstanding under the credit facility are secured by substantially +all properties of the Company. The credit agreement requires, among other +things, the existence of satisfactory levels of natural gas reserves and the +maintenance of certain working capital and tangible net worth ratios. At +December 31, 2006, an outstanding balance of $67 million was subject to a prime +interest rate of 8.375%; the overline note in the amount of $20 million was +subject to an interest rate of 9.05% and the remaining outstanding balance +of +$50 million was subject to a LIBOR rate of 7.0%. As previously discussed, the +Company requested and was granted a waiver related to the Security provisions +of +its credit facility. Additionally, the Company requested and was granted a +waiver related to the delay in the delivery of its consolidated financial +statements for the year ended December 31, 2006, and three months ended March +31, 2007, until May 31, 2007, and June 30, 2007, respectively. +43 +Index +Contractual +Obligations and Contingent Commitments +Contractual +obligations and contingent commitments and due dates are as +follows: +(in +thousands) +Payments +due by period +Contractual +Obligations and Contingent Commitments +Total +Less +than +1 +year +1-3 +years +3-5 +years +More +than +5 +years +Long-Term +Debt +$ +117,000 +$ +- +$ +- +$ +117,000 +$ +- +Operating +Leases +2,049 +502 +988 +555 +4 +Drilling +Obligations (1) +28,725 +11,125 +17,600 +- +- +Asset +Retirement Obligations +11,966 +100 +200 +200 +11,466 +Drilling +Rig Commitments +36,054 +12,556 +21,635 +1,863 +- +Derivative +Agreements (2) +2,545 +2,545 +- +- +- +Other +Liabilities +10,371 +40 +702 +4,011 +5,618 +Total +$ +208,710 +$ +26,868 +$ +41,125 +$ +123,629 +$ +17,088 +(1) +Represents +the Company's obligations to drill. Failure to drill wells as specified +in +the related agreements will result in the Company having to pay liquidated +damages. A total of $25.6 million is reflected on the consolidated +balance +sheet as a deferred gain on sale of leaseholds. See Note 12 to +consolidated financial statements. +(2) +Amounts +represent gross liability related to fair value of derivatives. Includes +fair values of derivatives for RNG and PDC's share of oil and gas +production and derivative contracts entered into by the Company on +behalf +of the affiliate partnerships as the managing general partner. The +Company +has a corresponding receivable from the partnerships of $0.1 million +as of +December 31, 2006. +Long-term +debt in the above table does not include interest, as interest rates are +variable and principal balances fluctuate significantly from period to period. +The Company continues to pursue capital investment opportunities in producing +natural gas properties as well as its plan to participate in its sponsored +natural gas drilling partnerships, while pursuing opportunities for operating +improvements and cost efficiencies. Management believes that the Company has +adequate capital to meet its operating requirements. +Commitments +and Contingencies +As +managing general partner of 76 partnerships (see Item 1. Business - Drilling +and +Development), the Company has liability for any potential casualty losses in +excess of the partnership assets and insurance. In January 2007, the Company +purchased the remaining working interests in 44 of the 76 partnerships, which +were sponsored by the Company in the late 1980s and 1990s (see Note 16 to the +consolidated financial statements). The Company’s management believes its and +its subcontractors' casualty insurance coverage is adequate to meet this +potential obligation. +From +time +to time the Company is a party to various legal proceedings in the ordinary +course of business. The Company is not currently a party to any litigation +that +it believes would have a materially adverse affect on the Company's business, +financial condition, results of operations, or liquidity. +Recent +litigation has commenced against several companies in our industry regarding +royalty practices and payments in jurisdictions where the Company conducts +business. While the Company's business model differs from those of the litigants +in those cases, and the Company has not been named in any litigation, has not +had similar litigation commenced, nor has such litigation been threatened, +there +can be no assurance that the Company will not be a party to any litigation +or to +similar litigation in the future. +Sale +of Undeveloped Leaseholds +In +July +2006, the Company sold to Marathon Oil Company, an unaffiliated company, a +portion of its undeveloped leasehold located in Grand Valley Field, Garfield +County, Colorado. The sale encompassed 100% of the working interest in +approximately 8,700 acres, including approximately 6,400 acres of the Company's +Chevron leasehold and 2,300 acres of the Company's Puckett Land Company +leasehold. The Company retained approximately 475 undeveloped locations on +10 +acre spacing on the Grand Valley Field leasehold in addition to all of its +producing properties in the field. The proceeds from the sale were $353.6 +million. +44 +Index +The +Company recorded a gain on sale of leaseholds of $328 million and a deferred +gain on sale of leaseholds of $25.6 million. The Company is obligated to either +drill 16 wells on specifically identified acreage over the next three years +(five by December 31, 2007, another five by December 31, 2008, and another +six +by December 31, 2009) or pay liquidated damages of $1.6 million per un-drilled +well. The Company expects to drill the wells for its own benefit and, as such, +will record the costs of the wells drilled in accordance with its oil and gas +properties accounting policy. For each well the Company drills, the Company +will +recognize $1.6 million of the deferred gain when drilling is complete. +Alternatively, should the Company not first drill the wells, the unaffiliated +company has the option to drill the wells for its benefit and, should it decide +to exercise its option, with each well drilled, the Company would recognize +both +$1.6 million of the amount deferred and $0.4 million to be paid to the Company +by the unaffiliated company. At December 31, 2006, $8 million of the deferred +gain on sale of leaseholds is classified as short-term and included in other +current liabilities in the accompanying consolidated balance sheet. +In +conjunction with the sale, the Company entered into a “like-kind exchange” +("LKE") agreement, in accordance with Section 1031 of the Internal Revenue +Code, +with a “qualified intermediary.” Proceeds in the amount of $300 million were +transferred directly to the qualified intermediary to be held in trust pursuant +to the terms of the LKE agreement. The Company had until mid-January 2007 to +close any acquisition of suitable like-kind property, allowing the Company +to +take advantage of the income tax deferral benefits of a LKE transaction. See +below a discussion of the acquisition of suitable like-kind +properties. +Acquisition +of Oil and Gas Properties +Unioil +On +December 6, 2006, the Company completed its cash tender offer and purchased +approximately 95.5%, or 9,112,750 shares, of the outstanding common stock of +Unioil, an independent energy company with properties in northern Colorado +and +southern Wyoming. The acquisition of more than 90% of the outstanding shares +of +common stock allowed the Company to effect a short-form merger of Unioil and +a +wholly owned subsidiary of the Company, resulting in the acquisition of the +remaining 428,719 shares of Unioil. Each share of Unioil common stock not +tendered through the offer was converted into the right to receive $1.91 in +cash, the same consideration paid for shares in the tender offer. The total +price paid for 100% of Unioil’s outstanding common stock was $18.6 million, +including $0.4 million in direct costs of the acquisition. The acquisition +was +accounted for using the purchase method of accounting under SFAS No. 141, +Business +Combinations . +Acquisition +of Section 1031 - LKE Properties +In +January 2007, the Company completed its acquisitions of suitable like-kind +properties in accordance with the LKE agreement it entered into in connection +with its sale of undeveloped leaseholds located in Grand Valley Field, Garfield +Country, Colorado in July 2006. The Company paid cash consideration for the +acquired oil and gas properties totaling $191.5 million, as described below. +EXCO +Resources Inc . +On +January 5, 2007, the Company completed its purchase of EXCO Resources Inc.’s +producing properties and remaining undeveloped drilling locations and acreage +in +the Wattenberg Field area of the DJ Basin, Colorado. The cash consideration +paid +for the EXCO properties was $130.9 million. The acquisition included +substantially all of EXCO’s assets in the area and encompassed 144 oil and gas +wells (approximating 25.5 Bcfe, net of royalty interests, proved developed +reserves as of December 31, 2005) and 8,160 acres of leasehold. The wells and +leases acquired are located in Weld, Adams, Larimer, and Broomfield Counties, +Colorado. The Company will operate the assets and holds a majority working +interest in the properties. +Company-Sponsored +Partnerships . +On +January 10, 2007, the Company completed the purchase of a majority interest +in +44 Company-sponsored partnerships for $58.8 million. This transaction was not +effected pursuant to purchase requests by investor partners (see "Drilling +Programs"). The wells are located in the Appalachian Basin, Michigan, and +Colorado. The transaction resulted in an increase in the Company’s net interest +in 718 wells that are currently operated by the Company. +Other. +The +Company acquired from unaffiliated parties undeveloped leaseholds in Erath +County, Texas for $1.8 million. +Other +Acquisitions +On +February 22, 2007, the Company acquired from an unaffiliated party 28 producing +wells and associated undeveloped acreage located in Colorado (Wattenberg Field) +for a purchase price of $11.8 million. The acquisition encompasses current +daily +production of approximately 668 Mcfe (520 Mcf of gas and 25 barrels of oil +per +day), net to the interests acquired, 100 or more undeveloped drilling locations, +19.1 Bcfe of proved reserves, and an additional 7.5 Bcfe of probable +reserves. +45 +Index +Critical +Accounting Policies and Estimates +The +Company has identified the following policies as critical to business operations +and the understanding of its results of operations. This is not a comprehensive +list of all of the accounting policies. In many cases, the accounting treatment +of a particular transaction is specifically dictated by accounting principles +generally accepted in the United States, with no need for management's judgment +in their application. There are also areas in which management's judgment in +selecting any available alternative would not produce a materially different +result. However, certain of the Company’s accounting policies are particularly +important to the portrayal of its financial position and results of operations +and may require the application of significant judgment by management; as a +result, they are subject to an inherent degree of uncertainty. In applying +those +policies, management uses its judgment to determine the appropriate assumptions +to be used in the determination of certain estimates. Those estimates are based +on historical experience, observation of trends in the industry, and information +available from other outside sources, as appropriate. For a more detailed +discussion on the application of these and other accounting policies, see “Note +1 - Summary of significant accounting policies” in the financial statements and +related notes. The Company’s critical accounting policies and estimates are as +follows: +Principles +of Consolidation +The +accompanying consolidated financial statements include the accounts of Petroleum +Development Corporation and its wholly owned subsidiaries, Riley Natural Gas, +Unioil and PDC +Securities Incorporated. All material intercompany accounts and transactions +have been eliminated in consolidation. The Company accounts for its investment +in interests in oil and gas limited partnerships under the proportionate +consolidation method. Under this method, the Company’s financial statements +include its pro rata share of assets, liabilities and revenues and expenses +respectively of the Company-sponsored limited partnerships in which it +participates. The Company’s proportionate share of all significant transactions +between the Company and the Company-sponsored limited partnerships is +eliminated. +Revenue +Recognition +The +Company's drilling segment recognizes revenue from drilling contracts with +sponsored drilling programs using the percentage of completion method based +upon +the percentage of contract costs incurred to date to the estimated total +contract costs for each contract. The Company utilizes this method since +reasonably dependable estimates of the total estimated costs can be made and +recognized revenues are subject to revisions as a contract progresses, the +term +of which can range from three to twelve months. In addition, the Company offers +its drilling services under two types of contractual arrangements, cost-plus +or +footage-based service contracts, which result in differing risk and reward +relationships and consequently, different revenue reporting policies pursuant +to +Emerging Issues Task Force ("EITF") No. 99-19, Reporting +Revenue Gross as a Principal versus Net as an Agent . +The +first +cost-plus drilling service arrangement was entered into in late 2005, with +drilling activity commencing in the first quarter of 2006. Although the Company +acts overall as a principal in the transaction and takes title to products +and +services acquired necessary for drilling, the Company acts as an agent, with +little risk of loss during the performance of the drilling activities. +Consistent with the provisions of EITF 99-19, the Company’s services provided +under the cost-plus drilling agreements are reported net of recovered costs. +The +Company entered into its second cost-plus drilling arrangement in September +2006 +and commenced drilling immediately. It is the Company’s intent that all future +drilling arrangements will be on a cost-plus basis. +Footage-based +contracts provide for the drilling, completion and equipping of wells at +footage +rates and are generally completed within nine to twelve months after the +commencement of drilling. The Company provides geological, +engineering, and drilling supervision on the drilling and completion process +and +uses subcontractors to perform drilling and completion services at a fixed +footage-based rate and accordingly has risk of loss in performing services +under +these arrangements. Accordingly, the Company reports revenue under +these agreements gross of related expenses. Anticipated losses, if +any, on uncompleted contracts are recorded at the time that the estimated +total +costs exceed the estimated total contract revenue. At December 31, +2006 and 2005, the loss contract reserve was $0.3 million and $0.8 million, +respectively. +Natural +gas marketing is reported on the gross accounting method, based on the nature +of +the agreements between RNG, its suppliers and its customers. RNG, the Company’s +marketing subsidiary, purchases gas from many small producers and bundles the +gas together to sell in larger amounts to purchasers of natural gas for a price +advantage. RNG has latitude in establishing price and discretion in supplier +and +purchaser selection. Natural gas marketing revenues and expenses reflect the +full cost and revenue of those transactions because RNG takes title to the +gas +it purchases from the various producers and bears the risks and rewards of +that +ownership. Both the realized and unrealized gains or losses of the RNG commodity +based derivative transactions for natural gas marketing activities are included +in gas sales from marketing activities or cost of gas marketing activities, +as +applicable. +46 +Index +Sales +of +natural gas are recognized when natural gas has been delivered to a custody +transfer point, persuasive evidence of a sales arrangement exists, the rights +and responsibility of ownership pass to the purchaser upon delivery, collection +of revenue from the sale is reasonably assured and the sales price is fixed +or +determinable. Natural gas is sold by the Company under contracts with terms +ranging from one month to three years. Virtually all of the Company’s contract +pricing provisions are tied to a market index, with certain adjustments based +on, among other factors, whether a well delivers to a gathering or transmission +line, quality of natural gas and prevailing supply and demand conditions, so +that the price of the natural gas fluctuates to remain competitive with other +available natural gas supplies. As a result, the Company’s revenues from the +sale of natural gas will suffer if market prices decline and benefit if they +increase. The Company believes that the pricing provisions of its natural gas +contracts are customary in the industry. +The +Company currently uses the “net-back” method of accounting for transportation +arrangements of natural gas sales. The Company sells gas at the wellhead and +collects a price and recognizes revenues based on the wellhead sales price +since +transportation costs downstream of the wellhead are incurred by its customers +and reflected in the wellhead price. +Sales +of +oil are recognized when persuasive evidence of a sales arrangement exists, +the +oil is verified as produced and is delivered to a purchaser, collection of +revenue from the sale is reasonably assured and the sales price is determinable. +The Company is currently able to sell all the oil that it can produce under +existing sales contracts with petroleum refiners and marketers. The Company +does +not refine any of its oil production. The Company’s crude oil production is sold +to purchasers at or near the Company’s wells under short-term purchase contracts +at prices and in accordance with arrangements that are customary in the oil +industry. +Well +operations and pipeline income are recognized when persuasive evidence of an +arrangement exists, services have been rendered, collection of revenues is +reasonably assured and the sales price is fixed or determinable. The Company +is +paid a monthly operating fee for each well it operates for outside owners +including the limited partnerships sponsored by the Company. The fee covers +monthly operating and accounting costs, insurance and other recurring costs. +The +Company may also receive additional compensation for special non-recurring +activities, such as reworks and recompletions. +Valuation +of Accounts Receivable +Management +reviews accounts receivable to determine which are doubtful of collection. +In +making the determination of the appropriate allowance for doubtful accounts, +management considers the Company's history of write-offs, customer relationships +and the overall credit worthiness of its customers, and well production data +for +receivables related to well operations. +Accounting +for Derivatives Contracts at Fair Value +The +Company uses derivative instruments to manage its commodity and financial market +risks. Accounting requirements for derivatives and hedging activities are +complex; interpretation of these requirements by standard-setting bodies is +ongoing. The Company currently does not use hedge accounting treatment for +its +derivatives. +Derivatives +are reported on the consolidated balance sheets at fair value. Changes in fair +value of derivatives are recorded in earnings in the consolidated statements +of +income as none of the Company’s derivatives qualified for hedge accounting under +the provisions of SFAS No. 133, Accounting +for Derivative Instruments and Hedging Activities . +The +measurement of fair value is based on actively quoted market prices, if +available. Otherwise, the Company seeks indicative price information from +external sources, including broker quotes and industry publications. If pricing +information from external sources is not available, measurement involves +management's judgment and estimates. These estimates are based on valuation +methodologies considered appropriate by the Company's management. For individual +contracts, the use of different assumptions could have a material effect on +the +contract's estimated fair value. +Use +of Estimates in Long-Lived Asset Impairment Testing +Impairment +testing for long-lived assets and intangible assets with definite and indefinite +lives is required when circumstances indicate those assets may be impaired. +In +performing an impairment test, the Company estimates the future cash flows +associated with individual assets or groups of assets. Impairment is recognized +when the undiscounted estimated future cash flows are less than the related +asset's carrying amount. In those circumstances, the asset must be written +down +to its fair value, which, in the absence of market price information, may be +estimated as the present value of its expected future net cash flows, using +an +appropriate discount rate. Although cash flow estimates used by the Company +are +based on the relevant information available at the time the estimates are made, +estimates of future cash flows are, by nature, highly uncertain and may vary +significantly from actual results. +47 +Index +Oil +and Gas Properties +The +Company accounts for its oil and gas properties under the successful efforts +method of accounting. Costs of proved developed producing properties, successful +exploratory wells and development dry hole costs are depreciated or depleted +by +the unit-of-production method based on estimated proved developed producing +oil +and gas reserves. Property acquisition costs are depreciated or depleted on +the +unit-of-production method based on estimated proved oil and gas reserves. The +Company obtains new reserve reports from independent petroleum engineers +annually as of December 31st of each year. The Company adjusts oil and gas +reserves for any major acquisitions, new drilling and divestitures during the +year as needed. +Exploration +costs, including geological and geophysical expenses and delay rentals, are +charged to expense as incurred. Exploratory well drilling costs, including +the +cost of stratigraphic test wells, are initially capitalized but charged to +expense if the well is determined to be nonproductive. The status of each +in-progress well is reviewed quarterly to determine the proper accounting +treatment under the successful efforts method of accounting. Exploratory well +costs continue to be capitalized as long as the well has found a sufficient +quantity of reserves to justify its completion as a producing well, requiring +the Company to assess its reserves and the economic and operating viability +of +wells. If an in-progress exploratory well is found to be unsuccessful (referred +to as a dry hole) prior to the issuance of the financial statements, the costs +are expensed to exploration costs. If management is unable to make a final +determination about the productive status of a well prior to issuance of the +financial statements, the well is classified as “Suspended Well Costs” until +management has had sufficient time to conduct additional completion or testing +operations to evaluate the pertinent geological and engineering data obtained. +At the time when management is able to make a final determination of a well’s +productive status, the well is removed from the suspended well status and the +proper accounting treatment is recorded. The determination of an exploratory +well's ability to produce is made within one year from the completion of +drilling activities. +The +acquisition costs of unproved properties are capitalized when incurred, until +such properties are transferred to proved properties or charged to expense +when +expired, impaired or amortized. Unproved oil and gas properties with +individually significant acquisition costs are periodically assessed, and any +impairment in value is charged to expense. The amount of impairment recognized +on unproved properties which are not individually significant is determined +by +amortizing the costs of such properties within appropriate fields based on +the +Company's historical experience, acquisition dates and average lease terms. +Amortization of remaining lease costs for all other insignificant properties +is +recorded over the average remaining lives of the leases. The valuation of +unproved properties is subjective and requires management of the Company to +make +estimates and assumptions which, with the passage of time, may prove to be +materially different from actual realizable values. +Upon +sale +or retirement of significant portions of or complete fields of depreciable +or +depletable property, the book value thereof, less proceeds or salvage value, +is +credited or charged to income. Upon sale of individual wells, the proceeds +are +credited to property costs. +The +Company assesses impairment of capitalized costs of proved oil and gas +properties by comparing net capitalized costs to estimated undiscounted future +net cash flows on a field-by-field basis using estimated production based upon +prices at which management reasonably estimates such products to be sold. These +estimates of future product prices may differ from current market prices of +oil +and gas. Any downward revisions to management's estimates of future production +or product prices could result in an impairment of the Company's oil and gas +properties in subsequent periods. If net capitalized costs exceed undiscounted +future net cash flows, the measurement of impairment is based on estimated +fair +value which would consider future discounted cash flows. +Deferred +Income Tax Asset Valuation Allowance +Deferred +income tax assets are recognized for deductible temporary differences, net +operating loss carry-forwards, and credit carry-forwards if it is more likely +than not that the tax benefits will be realized. To the extent a deferred tax +asset is not expected to be realized under the preceding criteria, a valuation +allowance has been established. The factors which the Company considers in +assessing whether or not it will realize the value of deferred income tax assets +involve judgments and estimates of both amount and timing, which could differ +from actual results achieved in future periods. +The +judgments used in applying the above policies are based on management's +evaluation of the relevant facts and circumstances as of the date of the +financial statements. Actual results may differ from those estimates. +Evaluation +of Errors +The +Company has historically utilized the "roll-over" method, by which only the +current period effect is considered, of assessing the materiality of +misstatements. In 2006, the Company became subject to the provisions of SEC +Staff Accounting Bulletin (“SAB”) No. 108, and now utilizes the dual method of +assessing materiality - both "roll-over" and "iron curtain" methods, by which +the full reversing effect of cumulative errors is considered each period. +48 +Index +Recent +Accounting Standards +See +Note +1, Summary +of Significant Accounting Policies - Recent Accounting +Standards , +to the +consolidated financial statements. +ITE M +7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET +RISK. +Market-Sensitive +Instruments and Risk Management +The +Company's primary market risk exposures are interest rate risk and commodity +price risk. These exposures are discussed in detail below: +Interest +Rate Risk +The +Company's exposure to market risk for changes in interest rates relates +primarily to the Company's interest-bearing cash and cash equivalents, +designated cash and long-term debt. Interest-bearing cash and cash equivalents +includes money market funds, short-term certificates of deposit and checking +and +savings accounts with various banks. The amount of interest-bearing cash and +cash equivalents as of December 31, 2006, is $405.1 million with an average +interest rate of 4.9%. As of December 31, 2006, the Company had long-term debt +of $117 million subject to a prime interest rate of 8.375%. As of December +31, +2006, the outstanding balance under the facility, including the overline note, +was $137 million, of which the overline note in the amount of $20 million was +subject to an interest rate of 9.05%, $67 million was subject to an Alternative +Base Rate, as defined in the credit facility, of 8.375% and the remaining +outstanding balance of $50 million was subject to LIBOR of 7.0%. +Commodity +Price Risk +Natural +gas and oil prices have been among the most volatile of all commodity prices. +These price variations can have a material impact on the Company’s financial +results. Natural gas and oil prices also vary by region, and locality, depending +upon the distance to markets, and the supply and demand relationships in that +region or locality. This can be especially true in the Rocky Mountain region. +The combination of increased drilling activity and the lack of local markets +can +create a local oversupply situation from time to time. There are a number of +different pipelines in various stages of construction which will help to +maintain a balance between supply and demand. However, oversupply situations +may +occur from time to time, which may affect the quantity of and price at which +the +Company can sell its oil and gas. Like most other producers in the region, +the +Company relies on major interstate pipeline companies to construct these +facilities, so their timing is not within the Company's control. +The +Company utilizes commodity based derivative instruments to manage a portion +of +its exposure to price risk from its oil and natural gas sales and marketing +activities. These instruments consist of NYMEX-traded natural gas futures +contracts and option contracts for Appalachian and Michigan production, +PEPL-based contracts and NYMEX-traded contracts for NECO production and +CIG-based contracts for other Colorado production. These derivative instruments +have the effect of locking in for specified periods (at predetermined prices +or +ranges of prices) the prices the Company will receive for the volume to which +the derivative relates and, in the case of RNG, the cost of gas supplies +purchased for marketing activities. As a result, while these derivatives are +structured to reduce the Company's exposure to changes in price associated +with +the derivative commodity, they also limit the benefit the Company might +otherwise have received from price changes associated with the derivative +commodity. RNG also enters into fixed-price physical purchase and sale +agreements that are derivative contracts. The Company's policy prohibits the +use +of oil and natural gas future and option contracts for speculative +purposes. +49 +Index +The +following tables summarize the open derivative and fixed-price purchase and +sale +contracts for RNG and PDC as of December 31, 2006 and 2005. +Riley +Natural Gas +Open +Derivative Positions +(dollars +in thousands, except average price data) +Commodity +Type +Quantity +Gas-MMbtu +Weighted +Average +Price +Total +Contract +Amount +Fair +Value +Total +Positions as of December 31, 2006 +Natural +Gas +Cash +Settled Futures/Swaps Purchases +246,900 +$ +7.34 +$ +1,811 +$ +(304 +) +Natural +Gas +Cash +Settled Futures/Swaps Sales +1,952,150 +8.42 +16,444 +2,815 +Natural +Gas +Cash +Settled Basis Swap Purchases +90,000 +0.42 +38 +(12 +) +Natural +Gas +Cash +Settled Basis Swap Sales +20,000 +0.50 +10 +4 +Natural +Gas +Cash +Settled Option Purchases +220,000 +5.50 +1,210 +64 +Natural +Gas +Cash +Settled Option Sales +110,000 +10.10 +1,111 +(39 +) +Natural +Gas +Physical +Purchases +1,964,150 +8.27 +16,244 +(1,974 +) +Natural +Gas +Physical +Sales +114,974 +9.62 +1,106 +310 +Natural +Gas +Physical +Basis Purchases +20,000 +0.45 +9 +(3 +) +Natural +Gas +Physical +Basis Sales +90,000 +0.44 +39 +14 +Positions +maturing in 12 months following December 31, 2006 +Natural +Gas +Cash +Settled Futures/Swaps Purchases +246,900 +$ +7.34 +$ +1,811 +$ +(304 +) +Natural +Gas +Cash +Settled Futures/Swaps Sales +1,637,150 +8.37 +13,697 +2,637 +Natural +Gas +Cash +Settled Basis Swap Purchases +90,000 +0.42 +38 +(12 +) +Natural +Gas +Cash +Settled Basis Swap Sales +20,000 +0.50 +10 +4 +Natural +Gas +Cash +Settled Option Purchases +220,000 +5.50 +1,210 +64 +Natural +Gas +Cash +Settled Option Sales +110,000 +10.10 +1,111 +(39 +) +Natural +Gas +Physical +Purchases +1,649,150 +8.27 +13,641 +(2,027 +) +Natural +Gas +Physical +Sales +114,974 +9.62 +1,105 +310 +Natural +Gas +Physical +Basis Purchases +20,000 +0.45 +9 +(3 +) +Natural +Gas +Physical +Basis Sales +90,000 +0.44 +39 +14 +Prior +Year Total Positions as of December 31, 2005 +Natural +Gas +Cash +Settled Futures/Swaps Purchases +1,025,500 +$ +9.05 +$ +9,283 +$ +1,983 +Natural +Gas +Cash +Settled Futures/Swaps Sales +3,149,000 +7.95 +25,018 +(8,689 +) +Natural +Gas +Cash +Settled Basis Swap Purchases +450,000 +0.91 +409 +(158 +) +Natural +Gas +Cash +Settled Basis Swap Sales +240,000 +0.50 +120 +4 +Natural +Gas +Physical +Purchases +2,819,000 +8.32 +23,456 +7,858 +Natural +Gas +Physical +Sales +585,222 +10.72 +6,272 +(670 +) +Natural +Gas +Physical +Basis Purchases +240,000 +0.45 +108 +8 +Natural +Gas +Physical +Basis Sales +450,000 +0.94 +420 +169 +50 +Index +Petroleum +Development Corporation +Open +Derivative Positions +(dollars +in thousands, except average price data) +Commodity +Type +Quantity +Gas-MMbtu +Oil-Barrels +Weighted +Average +Price +Total +Contract +Amount +Fair +Value +Total +Positions as of December 31, 2006 +Natural +Gas +Cash +Settled Option Sales +17,390,000 +$ +5.56 +$ +96,613 +$ +12,597 +Natural +Gas +Cash +Settled Option Purchases +2,155,000 +10.34 +22,287 +(14 +) +Oil +Cash +Settled Option Purchases +300,000 +50.00 +15,000 +155 +Positions +maturing in 12 months following December 31, 2006 +Natural +Gas +Cash +Settled Option Sales +15,530,000 +$ +5.53 +$ +85,850 +$ +11,682 +Natural +Gas +Cash +Settled Option Purchases +2,155,000 +10.34 +22,287 +(14 +) +Oil +Cash +Settled Option Purchases +300,000 +50.00 +15,000 +155 +Prior +Year Total Positions as of December 31, 2005 +Natural +Gas +Cash +Settled Option Sales +5,665,000 +$ +8.17 +$ +46,273 +$ +(12,531 +) +Natural +Gas +Cash +Settled Option Purchases +14,030,000 +6.36 +89,210 +2,660 +In +addition to including the gross assets and liabilities related to the Company's +share of oil and gas production, the above tables and the accompanying +consolidated balance sheets include the gross assets and liabilities related +to +derivative contracts entered into by the Company on behalf of the affiliate +partnerships as the managing general partner. The accompanying consolidated +balance sheets include the fair value of derivatives and a corresponding net +payable to the partnerships of $7.5 million as of December 31, 2006, and a +net +receivable from the partnerships of $5.4 million as of December 31, 2005. In +addition to the short-term fair value of derivatives shown on the accompanying +consolidated balance sheets, there are long-term assets and long-term +liabilities which total to a net long-term asset of approximately $0.9 million +as of December 31, 2006, and which total a net long-term asset of approximately +$1.3 million as of December 31, 2005, respectively, related to the fair value +of +derivatives included in accompanying balance sheets. +By +using +derivative financial instruments to manage exposures to changes in interest +rates and commodity prices, the Company exposes itself to credit risk and market +risk. Credit risk is the failure of the counterparty to perform under the terms +of the derivative contract. When the fair value of a derivative contract is +positive, the counterparty owes the Company, which creates repayment risk. +The +Company minimizes the credit or repayment risk in derivative instruments by +entering into transactions with high-quality counterparties. There were no +counterparty defaults during the years ended December 31, 2006, 2005 and +2004. +The +average NYMEX closing prices for natural gas for the years 2006, 2005 and 2004, +were $7.23 Mmbtu, $8.62 Mmbtu and $6.14 Mmbtu. The average NYMEX closing prices +for oil for the years 2006, 2005 and 2004, were $64.73 bbl, $55.34 bbl and +$41.44 bbl. Future near-term gas prices will be affected by various supply +and +demand factors such as weather, government and environmental regulation and +new +drilling activities within the industry. +Disclosure +of Limitations +Because +the information above incorporates only those exposures that exist at December +31, 2006, it does not consider those exposures or positions which could arise +after that date. As a result, the Company's ultimate realized gain or loss +with +respect to interest rate and commodity price fluctuations will depend on the +exposures that arise during the period, the Company's hedging strategies at +the +time, and interest rates and commodity prices at the time. +ITE M +8. FINANCIAL STATEMENTS AND SUPPLEMENTARY +DATA +The +response to this Item is set forth herein in a separate section of this Report, +beginning on Page F-1. +Index +to financial statements. +51 +Index +ITE M +9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON +ACCOUNTING AND FINANCIAL DISCLOSURE. +None. +ITE M +9A. CONTROLS AND PROCEDURES +(1) +Evaluation +of Disclosure Controls and Procedures +As +of the +end of the period covered by this report, the management of the Company, under +the supervision and with the participation of the Company's Chief Executive +Officer and Chief Financial Officer, carried out an evaluation of the Company's +disclosure controls and procedures as defined in Rule 13a-15(e) of the Exchange +Act. Based on that evaluation, the Chief Executive Officer and Chief Financial +Officer concluded that, as of December 31, 2006, the Company's disclosure +controls and procedures were not effective in enabling the Company to record, +process, summarize and report, in a timely manner, the information that the +Company is required to disclose in its Exchange Act reports due to the +existence, at December 31, 2006, of three material weaknesses described below +in +section (2), "Management’s Report on Internal Control over Financial Reporting +." +(2) +Management’s +Report on Internal Control over Financial +Reporting +Management +is responsible for establishing and maintaining adequate internal control +over +financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) +of the Exchange Act. 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. 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 policies or procedures may +deteriorate. +Management +has assessed the effectiveness of the Company’s internal control over financial +reporting as of December 31, 2006, based upon the criteria established in +“Internal Control - Integrated Framework” issued by the Committee of Sponsoring +Organizations of the Treadway Commission (“COSO”). Based on this evaluation, +management concluded that three material weaknesses, which are control +deficiencies, or combinations of control deficiencies, that result in more +than +a remote likelihood that a material misstatement of the annual or interim +financial statements will not be prevented or detected, existed at December +31, +2006. The Company’s assessment, as of December 31, 2006, identified the +following material weaknesses: +· +The +Company did not have effective policies and procedures to ensure +the +timely reconciliation, review and adjustment of significant balance +sheet +and income statement accounts. As a result, material misstatements +were +identified during the Company's closing process in certain significant +balance sheet and income statement accounts and corrected prior to +the +issuance of the Company’s 2006 consolidated financial statements. This +deficiency resulted in a more than remote likelihood that a material +misstatement of the Company’s annual or interim financial statements would +not be prevented or detected. +· +The +Company did not have effective policies and procedures, or personnel +with +sufficient technical expertise to ensure proper accounting for derivative +instruments. Specifically, the Company’s internal control processes did +not ensure the completeness of all derivative contracts related to +oil and +gas sales, and also did not ensure the determination of the fair +value of +certain derivatives. As a result, misstatements were identified in +the +fair value of derivatives and related income statement accounts and +corrected prior to the issuance of the Company’s 2006 consolidated +financial statements. This deficiency resulted in a more than remote +likelihood that a material misstatement of the Company’s annual or interim +financial statements would not be prevented or +detected. +· +The +Company did not have effective policies and procedures to ensure +proper +accounting for oil and gas properties. Specifically, the +Company’s review procedures were not sufficient to ensure that the +calculations of depreciation and depletion were performed accurately +and +that the capitalization of costs was performed in accordance with +the +applicable authoritative accounting guidance. As a result, +misstatements were identified in 2006 in depreciation, depletion +and +amortization expense, and corrected prior to the issuance of the +Company’s +consolidated financial statements. This deficiency resulted in +a more than remote likelihood that a material misstatement of the +Company’s annual or interim financial statements would not be prevented +or +detected. +52 +Index +Management +has concluded that, as a result of the material weaknesses noted above, the +Company did not maintain effective internal control over financial reporting +as +of December 31, 2006, based on criteria set forth in the COSO +Framework. +The +Company acquired Unioil on December 6, 2006, and management excluded from its +assessment of the effectiveness of the Company's internal control over financial +reporting as of December 31, 2006, Unioil's internal control over financial +reporting associated with total assets of $26.1 million and total revenues +of +$0.3 million included in the consolidated financial statements of the Company +as +of and for the year ended December 31, 2006. +The +Company’s independent registered public accounting firm, KPMG LLP, has issued an +audit report on Management’s assessment of the Company’s internal control over +financial reporting as of December 31, 2006, which is included in this annual +report on Form 10-K +(3) Changes +in Internal Control over Financial Reporting +Changes +in Internal Control over Financial Reporting During the Quarter Ended December +31, 2006 +There +have been changes in the Company's internal control over financial reporting +(as +such term is defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange +Act of 1934) during the most recent fiscal quarter that have materially affected +or are reasonably likely to materially affect the Company's internal control +over financial reporting. +During +the fourth quarter of 2006, management completed implementing, documented and +tested internal control over financial reporting which, as noted below, have +allowed management to conclude that there are no longer material weaknesses +in +its accounting for asset retirement obligations, proportionate consolidation +and +income taxes. +Status +of December 31, 2005, Evaluation and Related Material Weaknesses in Internal +Control Over Financial Reporting +In +connection with the preparation of the Company's Annual Report on Form 10-K +for +the year ended December 31, 2005 ("2005 10-K"), an evaluation was completed +under the supervision and with the participation of the Company's management, +including the Chief Executive Officer and the Chief Financial Officer, of +the +effectiveness of the design and operation of the Company's disclosure controls +and procedures (as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange +Act). The Company concluded that, as of December 31, 2005, certain +control deficiencies in its internal control over financial reporting +constituted material weaknesses within the meaning of the Public Company +Accounting Oversight Board's Auditing Standard No. 2. Specifically, +deficiencies related to the Company’s accounting for derivatives, oil and gas +properties, asset retirement obligations, proportionate consolidation and +income +taxes were determined to be material weaknesses. Beginning in 2005 +and throughout all four fiscal quarters of 2006, management undertook +remediation efforts, described in further detail below, to address and remediate +these material weaknesses, and ultimately remediated three of these material +weaknesses. +The +Company has evaluated remediation efforts initiated to address material +weaknesses identified by the Company - and disclosed in its December 31, 2005, +annual report on Form 10-K as part of management’s evaluation of internal +control over financial reporting, and in its March 31, June 30, and September +30, 2006, quarterly reports on Forms 10-Q, as part of its evaluation of +disclosure controls and procedures in those periods. Based upon that evaluation, +the Company’s Chief Executive Officer and Chief Financial Officer have concluded +that, as of December 31, 2006, the Company no longer has deficiencies in its +internal control over financial reporting which represent material weaknesses +in +its accounting related to asset retirement obligations, proportionate +consolidation and income taxes. +Remediation +Efforts Undertaken to Address and Correct 2005 Material Weaknesses in Internal +Control Over Financial Reporting +In +order +to address and remediate the above-mentioned December 31, 2005 material +weaknesses, the following changes in the Company’s internal control over +financial reporting that have materially affected, or are reasonably likely +to +materially affect, the Company’s internal control over financial reporting were +made during the year ended December 31, 2006, ultimately resulting in management +concluding that three of those material weaknesses have been +corrected: +• +In +November 2006, the accounting and finance group was reorganized to +include +a new position of Chief Accounting Officer ("CAO"), which reports +directly +to the Chief Financial Officer. The CAO's responsibilities include +the +proper application of generally accepted accounting principles, and +the +supervision of the Company’s Sarbanes-Oxley compliance program. Mr. Darwin +Stump, CPA, formerly the Chief Financial Officer assumed the new +position +of CAO in November 2006. +53 +Index +· +Concurrently, +in November 2006, the Company appointed a new Chief Financial Officer +and +Treasurer, who has significant oil and gas industry and accounting +experience. In addition to his finance responsibilities, the new +Chief +Financial Officer has assumed a leadership role in guiding the Company’s +Sarbanes-Oxley compliance program. +· +Additional +controls and procedures were designed by the Company during 2006 +over the +creation and reporting of the Company’s income tax provision and +accounting for other miscellaneous taxes. In addition, in December +2006, +the Company hired a Director of Taxation with significant and relevant +experience with another publicly held company, including the preparation +and review of tax provisions, tax-related disclosures and footnotes +for +financial statement reports and SEC filings. These additional controls +were tested as part of the Company’s year end Sarbanes-Oxley compliance +effort and were determined to be operating effectively by management. +· +During +2006, the Company expanded the size of its financial accounting and +reporting team by hiring professionals with significant and relevant +experience. Specifically, an additional certified public accountant +was +hired in the first quarter of 2006 and two additional certified public +accountants were hired during the second quarter of 2006, including +a +corporate financial reporting director, a partnership financial reporting +director, and an exploration and production (“E&P”) accountant. +· +Continuing +the process begun and reported during 2005, the Company enhanced +its +training program for its financial accounting and reporting team; +formal +training has been conducted during 2005 and 2006, including oil and +gas +accounting and other topics specific to the areas of the Company’s +internal control over financial reporting for which material weaknesses +were reported as of December 31, 2005, and through all four quarters +of +2006. +· +Starting +during the fourth quarter 2005 and continuing through 2006, the Company +subscribed to online accounting research and other accounting technical +resources including GAAP and SEC reporting checklists and has utilized +these resources to assist in the preparation of its financial statements +and SEC filings. Additionally, the online research tool has been +used as a +source of periodic informal training and education in supporting +and +enhancing the technical expertise of the financial accounting and +reporting team. Company finance, accounting and financial reporting +personnel have utilized these resources throughout 2006. +· +The +Company engaged a team of independent, highly experienced advisors +and +consultants, through all fiscal quarters in 2006, to assist with +various +accounting research, projects and monitoring activities. The advisors +and +consultants assist the Company with addressing accounting and reporting +issues including, but not limited to, derivatives, oil and gas activities, +new accounting standards and rules, transaction-specific accounting +issues, SEC reporting and on-going monitoring of changes that may +impact +the Company's application of accounting principles. +· +During +2005 and continuing in 2006, the Company re-evaluated and improved +its +documentation, policies and procedures, and templates with respect +to its +accounting for derivatives, oil and gas property depreciation, depletion +and amortization, proportionate consolidation, asset retirement +obligations and income taxes, and the related disclosures in its +financial +statements. The corrected policies and procedures were employed by +the +Company in the preparation of each of its 2006 periodic financial +statements on Form 10-Q, and in this annual report on Form 10-K. +Senior +management - both operating and financial reporting management - +has +played a significant role in performing appropriate and sufficient +monitoring and review control activities focusing on the appropriate +application of the correct policies and procedures in the Company’s +periodic financial reporting. +54 +Index +Report +of Independent Registered Public Accounting Firm +The +Board +of Directors and Shareholders +Petroleum +Development Corporation: +We +have +audited management’s assessment, included in the accompanying Management’s +Report on Internal Control Over Financial Reporting (Item 9A(2)), that Petroleum +Development Corporation and subsidiaries (the Company) did not maintain +effective internal control over financial reporting as of December 31, 2006 +because of the effect of the material weaknesses identified in management's +assessment based on criteria established in Internal +Control-Integrated Framework issued +by +the Committee of Sponsoring Organizations of the Treadway Commission (COSO). +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 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. +A +material weakness is a control deficiency, or combination of control +deficiencies, that results in more than a remote likelihood that a material +misstatement of the annual or interim financial statements will not be prevented +or detected. Management has identified and included in its assessment the +following material weaknesses as of December 31, 2006: +· +The +Company did not have effective policies and procedures to ensure +the +timely reconciliation, review and adjustment of significant balance +sheet +and income statement accounts. As a result, material misstatements +were +identified during the Company's closing process in certain significant +balance sheet and income statement accounts of the Company’s 2006 +consolidated financial statements. This deficiency resulted in a +more than +remote likelihood that a material misstatement of the Company’s annual or +interim financial statements would not be prevented or +detected. +· +The +Company did not have effective policies and procedures, or personnel +with +sufficient technical expertise to ensure proper accounting for derivative +instruments. Specifically, the Company’s internal control processes did +not ensure the completeness of all derivative contracts related to +oil and +gas sales, and also did not ensure the determination of the fair +value of +certain derivatives. As a result, misstatements were identified in +the +fair value of derivatives and related income statement accounts of +the +Company’s 2006 consolidated financial statements. This deficiency resulted +in a more than remote likelihood that a material misstatement of +the +Company’s annual or interim financial statements would not be prevented or +detected. +· +The +Company did not have effective policies and procedures to ensure +proper +accounting for oil and gas properties. Specifically, the +Company’s review procedures were not sufficient to ensure that the +calculations of depreciation and depletion were performed accurately +and +that the capitalization of costs was performed in accordance with +the +applicable authoritative accounting guidance. As a result, +misstatements were identified in 2006 in depreciation, depletion +and +amortization expense of the Company’s consolidated financial +statements. This deficiency resulted in a more than remote +likelihood that a material misstatement of the Company’s annual or interim +financial statements would not be prevented or +detected. +55 +Index +In +our +opinion, management’s assessment that Petroleum Development Corporation did not +maintain effective internal control over financial reporting as of December +31, +2006, 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 +(COSO). Also, in our opinion, because of the effect of the material +weaknesses described above on the achievement of the objectives of the control +criteria, Petroleum Development Corporation did not maintain effective internal +control over financial reporting as of December 31, 2006, based on the criteria +established in Internal Control - Integrated Framework issued by the +Committee of Sponsoring Organizations of the Treadway Commission +(COSO). +The +Company acquired Unioil on December 6, 2006, and management excluded from its +assessment of the effectiveness of the Company's internal control over financial +reporting as of December 31, 2006, Unioil’s internal control over financial +reporting associated with total assets of $26.1 million and total revenues +of +$0.3 million included in the consolidated financial statements of the Company +as +of and for the year ended December 31, 2006. Our audit of internal control +over +financial reporting of the Company also excluded an evaluation of the internal +control over financial reporting of Unioil. +We +also +have audited, in accordance with the standards of the Public Company Accounting +Oversight Board (United States), the consolidated balance sheets of Petroleum +Development Corporation and subsidiaries as of December 31, 2006 and 2005, +and +the related consolidated statements of income, shareholders’ equity and cash +flows for each of the years in the three-year period ended December 31, 2006. +The aforementioned material weaknesses were considered in determining the +nature, timing and extent of audit tests applied in our audit of the 2006 +consolidated financial statements, and this report does not affect our report +dated May 22, 2007, which expressed an unqualified opinion on those consolidated +financial statements. +KPMG +LLP +Pittsburgh, +Pennsylvania +May +22, +2007 +56 +Index +ITE M +9B. OTHER INFORMATION +None. +PART +III +ITE M +10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE +GOVERNANCE +The +executive officers and directors of the Company, their principal occupations +for +the past five years and additional information is set forth below. +Name +Age +Position(s) +Director +Since +Directorship +Term +Expires +Steven +R. Williams +56 +Chairman, +Chief Executive Officer and Director +1983 +2009 +Thomas +E. Riley +54 +President +and Director +2004 +2007 +Richard +W. McCullough +55 +Chief +Financial Officer and Treasurer +- +- +Darwin +L. Stump +52 +Chief +Accounting Officer +- +- +Eric +R. Stearns +49 +Executive +Vice President, Exploration and Production +- +- +Vincent +F. D'Annunzio +54 +Director +1989 +2007 +Jeffrey +C. Swoveland +52 +Director +1991 +2008 +Kimberly +Luff Wakim +49 +Director +2003 +2009 +David +C. Parke +40 +Director +2003 +2008 +Anthony +J. Crisafio +54 +Director +2006 +2009 +Steven +R. Williams +was +elected Chairman and Chief Executive Officer in January 2004. Mr. Williams +served as President from March 1983 until December 2004 and has been a Director +of the Company since 1983. +Thomas +E. Riley +was +elected Director in January 2004 by the Board of Directors and assumed the +position of President in December 2004. Previously Mr. Riley was appointed +Executive Vice President of Production, Natural Gas Marketing and Business +Development in November 2003. Prior thereto, Mr. Riley served as Vice President +Gas Marketing and Acquisitions of the Company since April 1996. Prior to joining +the Company, Mr. Riley was president of Riley Natural Gas Company, a natural +gas +marketing company which the Company acquired in April 1996. +Richard +W. McCullough +was +appointed Chief Financial Officer and Treasurer in November 2006. Prior to +joining the Company, Mr. McCullough served as president and chief executive +officer of Gasource, LLC, Dallas, Texas, a marketer of long-term, natural gas +supplies. From 2001 to 2003, Mr. McCullough served as an investment banker +with +J.P. Morgan Securities, Atlanta, Georgia, and served in the public finance +utility group supporting bankers nationally in all natural gas matters. +Additionally, Mr. McCullough has held senior positions with Progress Energy, +Deloitte and Touche, and the Municipal Gas Authority of Georgia. Mr. McCullough, +a CPA, was a practicing certified public accountant for eight +years. +Darwin +L. Stump +was +appointed Chief Accounting Officer in November 2006. Mr. Stump has been an +officer of the Company since April 1995 and held the position of Chief Financial +Officer and Treasurer from 2003 until November 2006. Previously, Mr. Stump +served as Corporate Controller from 1980 until November 2003. Mr. Stump, a +CPA, +was a senior accountant with Main Hurdman, Certified Public Accountants prior +to +joining the Company. +Eric +R. Stearns +was +appointed Executive Vice President of Exploration and Production in December +2004. Prior to his current position, Mr. Stearns was Executive Vice President +of +Exploration and Development since November 2003, having previously served as +Vice President of Exploration and Development since April 1995. Mr. Stearns +joined the Company as a geologist in 1985 after working for Hywell, Incorporated +and for Petroleum Consultants. +Vincent +F. D'Annunzio +has +served as president of Beverage Distributors, Inc. located in Clarksburg, West +Virginia since 1985. +57 +Index +Jeffrey +C. Swoveland +has +served as chief financial officer of Body Media, a life-science company +specializing in the design and development of wearable body monitoring products +and services, since September, 2000. Prior thereto, Mr. Swoveland held various +positions, including vice president of finance, treasurer and interim chief +financial officer, with Equitable Resources, Inc., a diversified natural gas +company, from 1997 to September 2000. Mr. Swoveland serves as a member of the +board of directors of Linn Energy, LLC, a public, independent natural gas and +oil company. +Kimberly +Luff Wakim , +an +Attorney and Certified Public Accountant, is a partner with the law firm Thorp, +Reed & Armstrong LLP. Ms. Wakim joined Thorp Reed & Armstrong LLP in +1990. +David +C. Parke +is a +managing director in the investment banking group of Boenning & Scattergood, +Inc., West Conshohocken, Pennsylvania, a full-service investment banking firm. +Prior to joining Boenning & Scattergood in November 2006, he was a director +with Mufson Howe Hunter & Company LLC, Philadelphia, Pennsylvania, an +investment banking firm, from October 2003 to November 2006. From 1992 through +2003, Mr. Parke was director of corporate finance of Investec, Inc., and its +predecessor Pennsylvania Merchant Group Ltd., investment banking companies. +Prior to joining Pennsylvania Merchant Group, Mr. Parke served in the corporate +finance departments of Wheat First Butcher & Singer, now part of Wachovia +Securities, and Legg Mason, Inc., now part of Stifel Nicolaus. Mr. Parke serves +as a member of the board of directors of Zunicom, Inc., a public company +providing business communication services to the hospitality +industry. +Anthony +J. Crisafio +was +elected to the Board in October 2006. Mr. Crisafio, a certified public +accountant, serves as an independent business consultant, providing financial +and operational advice to businesses and has done so since 1995. He owned two +small businesses during the period of 1991 to 2002. Additionally, Mr. Crisafio +has served as the chief operating officer of Cinema World, Inc. from 1989 until +1993 and was a partner with Ernst & Young from 1986 until 1989. +Corporate +Governance +In +January 2005, the Company adopted Corporate Governance Guidelines to promote +the +effective functioning of its Board of Directors and related +committees. +Board +of Directors +The +Company's By-Laws provide that the number of members of the Board of Directors +("Board") shall be designated from time to time by a resolution of the Board +and, in absence of such designation, the number of directors shall be seven. +The +Board shall be divided into three separate classes of directors which are +required to be as nearly equal in number as practicable. At each annual meeting +of stockholders one class of directors, whose term expires, will be elected +to a +term of three years. The classes are staggered so that the term of one class +expires each year. There is no family relationship between any director or +executive officer and any other director or executive officer of the Company. +There are no arrangements or understandings between any director or officer +and +any other person pursuant to which the person was selected as an +officer. +Director +Independence +The +Company has determined that all of its directors, other than Messrs. Williams +and Riley, are independent under NASDAQ Marketplace Rule 4200 and the Exchange +Act. +58 +Index +Committees +of the Board +The +following table identifies the current membership and chair of the five standing +committees of the Board:. +Name +Audit +Compensation +Executive +Nominating/ +Corporate +Governance +Planning/ +Finance +Jeffrey +C. Swoveland +Chair +- +Member +- +Member +Kimberly +Luff Wakim +Member +- +- +Member +- +Vincent +F. D'Annunzio +- +Member +Member +Chair +- +David +C. Parke +Member +Chair +- +Member +Chair +Anthony +J. Crisafio +Member +Member +- +- +- +Steven +R. Williams +- +- +Chair +- +- +Thomas +E. Riley +- +- +Member +- +Member +The +Audit +Committee of the Board is comprised entirely of persons whom the Board has +determined to be independent under NASDAQ Rule 4200(a)(15). Mr. Swoveland chairs +the committee; other audit committee members are Ms. Wakim, Mr. Parke and Mr. +Crisafio. The Board has determined that Mr. Swoveland and the other Audit +Committee members, with the exception of Mr. Parke, qualify as audit committee +financial experts as defined by SEC regulations and are all, without exception, +independent of management. The audit committee’s purpose is to assist the Board +in monitoring the integrity of the financial reporting process, systems of +internal controls and financial statements of the Company, and compliance by +the +Company with legal and regulatory requirements. Additionally, the committee +is +directly responsible for the appointment, compensation and oversight of the +independent auditors employed by the Company for the purpose of preparing or +issuing an audit report or related work and to assess the need for an internal +audit function and recommend its establishment when deemed appropriate. +The +independent directors conduct meetings ("executive sessions") without the +presence of management at each scheduled Board meeting. Mr. Swoveland serves +as +Presiding Independent Director of the Board. +Communications +with Directors +Shareholders +wishing to communicate with the Board or a committee may do so by writing to +the +attention of the Board or Committee at the corporate headquarters or by emailing +the Board at board@petd.com, with "Board" or appropriate committee in the +subject line. +Code +of Ethics +In +January 2003, the Company adopted its Code of Business Conduct and Ethics, +as +amended (the “Code of Conduct”) applicable to all directors, officers, +employees, agents and representatives of the Company and consultants. The +Company's principal executive officer, principal financial officer and principal +accounting officer are subject to additional specific provisions under the +Code +of Conduct. The Company's Code of Conduct is posted on its website at +www.petd.com. In the event of an amendment to, or a waiver of, including an +implicit waiver, the Code of Conduct, the Company will disclose the information +on its internet website. +Section +16(a) Beneficial Ownership Reporting Compliance +Section +16(a) of the Exchange Act requires the Company's officers and directors, and +persons who own more than 10% of a Company's equity securities, to file reports +of ownership and changes in ownership with the Securities and Exchange +Commission. Officers, directors and holders of more than 10% of the Common +Stock +are required by regulations promulgated by the Commission pursuant to the +Exchange Act to furnish the Company with copies of all Section 16(a) forms +they +file. The Company assists officers and directors, and will assist beneficial +owners, if any, of more than 10% of the Common Stock, in complying with the +reporting requirements of Section 16(a) of the Exchange Act. +Based +solely on its review of the copies of such forms received by it, the Company +believes that since January 1, 2006, all Section 16(a) filing requirements +applicable to its directors, officers and greater than 10% beneficial owners +were met. +59 +Index +ITE M +11. EXECUTIVE COMPENSATION +EXECUTIVE +COMPENSATION +Compensation +Discussion and Analysis +The +Compensation Committee of the Board of Directors ("Board") of Petroleum +Development Corporation (the “Committee”), which consists of three independent +Board members, developed and recommended for Board approval the compensation +program for 2006 for the Chief Executive Officer ("CEO") and the other executive +officers listed in the “2006 Summary Compensation Table” (collectively, the +"named executive officers" or "executive officers") appearing below. The +Committee’s recommendations of compensation for the executive officers were +approved by the Board. For 2007 executive compensation, the Board authorized +the +Committee to make final determinations for all elements of compensation for +the +executive officers, which the Committee did after reviewing its proposals with +all other independent board members who are not part of the Committee. The +Committee also negotiates terms of employment agreements with the executive +officers. Prior to determining executive compensation, the Compensation +Committee consults with the CEO for his evaluation of performance and +recommendation for compensation of the other executive officers. +The +Compensation Committee utilized the compensation consulting service of Towers +Perrin ("Consultant") in recent years. Over the past 18 months, the Consultant: +conducted a competitive benchmarking of the Company's executive and non-employee +director compensation programs, helped the Committee in its redesign of the +Long-Term Incentive ("LTI") program in 2007 as described below, and led an +educational session focused on new SEC pay disclosure rules. The Consultant +also +assisted the Company with the design of a retention-based stock plan for +non-officers. The Committee periodically assesses the effectiveness and +competitiveness of the Company’s executive compensation structure with the +assistance of the Consultant, and utilizes the assistance of the Consultant +in +assessing the value and cost of various proposed compensation arrangements. +The +Consultant is engaged by, and reports directly to, the Committee. +Compensation +Philosophy +The +Committee considers many factors in establishing the compensation packages +for +the executive officers of the Company. The ultimate goal is to provide +compensation that is fair to both the Company and the executive officers, that +motivates behavior that will enhance the value of the Company, that avoids +encouraging behavior that does not serve the best interests of the Company +and +that will allow the Company to attract and retain executive +officers. +Objectives +of Compensation Program +The +Committee’s philosophy is to provide compensation packages that will attract, +motivate and retain executive talent and deliver rewards for superior +performance and consequences for underperformance. Specifically, the objectives +of the Committee’s executive compensation practices are to: +· +Offer +a total compensation program that is competitive with the compensation +practices of those peer companies with which the Company competes +for +talent; +· +Tie +a significant portion of executive compensation to the Company’s +achievement of pre-established financial and operating objectives +and to +personal objectives established for each executive +individually; +· +Provide +a significant portion of overall compensation in the form of equity-based +compensation in order to align the interests of the Company’s executives +with those of the Company’s shareholders; +and +· +Structure +a significant proportion of total compensation in a fashion that +promotes +executive retention. +The +Committee seeks to attract executive talent by offering competitive base +salaries, annual performance incentive opportunities under the Company’s +Short-Term Incentive (“STI”) program and the potential for long-term rewards +under the Company’s equity-based LTI program. The Committee believes that to +attract and retain a highly-skilled executive team, the Company’s compensation +practices must be competitive with those of other employers with which the +Company competes for talent. +60 +Index +Pay-for-Performance +The +Committee believes that significant portions of executive compensation should +be +closely linked to both the Company’s and the individual’s performance. The +Committee’s pay-for-performance philosophy is reflected in the Company’s +compensation practices, which tie a significant portion of executive +compensation to the achievement of financial and operating objectives of the +Company and also to take into account personal objectives and performance. +The +Committee believes that using solely financial objectives could unduly reward +or +punish executives for financial performance resulting from issues beyond the +executive’s control, such as changes in energy prices. On the other hand using +solely operating measures could result in compensation practices that did not +align the executive’s interests with those of the shareholders. As a result, the +Committee has chosen to use a combination of financial and operating measures +as +determinants for STI compensation. This philosophy is reflected in annual +incentive awards, which are directly linked to the achievement of short-term +financial and operating objectives, set by the Committee and have potential +payouts ranging from zero to 200% of target for each of the three components. +During 2006, the targets were increases in diluted earnings per share, increases +in production, and the Committee’s assessment of other factors related to the +individual’s performance and development. The following table summarized the +criteria used in determining the bonus amount. +Criteria +Lower +Threshold +Amount +Target +Bonus +Maximum +Bonus +Percent +of +Total +Maximum +Bonus +Production +increase based on Mcfe +6 +% +10 +% +14 +% +40 +% +Diluted +earnings per share +$ +2.42 +$ +2.66 +$ +3.03 +30 +% +Discretionary +evaluation +Compensation +Committee Determination +30 +% +The +Committee also ties compensation to performance through equity-based LTI awards +that are designed to motivate executives to meet the Company’s long-term +performance goals and to tie their interests to those of the shareholders. +In +2006, the LTI awards consisted of restricted stock and stock options that vest +25% per year over a period of four years. For 2007, all of the LTI awards are +restricted stock, a portion of which vest over time. The balance of the +restricted stock awards will be long-term incentive performance shares (“LTIP +shares”). The LTIP shares will vest only if certain minimum thresholds of stock +price appreciation are met. One-half of the LTIP shares will vest and be issued +based upon an annual stock price increase of approximately 12%. An additional +25% of the awarded LTIP shares will vest and be issued at annualized increased +hurdles of 16% and an additional 25% at 20%. The stock price will be measured +based on the average daily closing price for each of the three monthly periods: +December 2009, 2010 and 2011. Any shares not vested in 2009 or 2010 will remain +eligible to be vested in future years; however, any unvested shares at December +31, 2011 will be forfeited. The Committee decided to use three measurement +dates +to take into account the volatility of energy prices and their impact on the +stock price of the Company. +As +a +result of the structure of the STI and LTI compensation, a significant amount +of +variable compensation under the Company’s compensation program is contingent on +the achievement of key financial and operating objectives of the Company and +on +increasing the value of the shares of the Company’s stock. +For +2006, +30% of the Company’s STI compensation program also accounts for individual +performance through individual objectives and evaluation of individual executive +performance by the Committee, which enables the Committee to differentiate +among +executives and emphasize the link between personal performance and compensation. +For 2007, 100% of Mr. Stump's STI is discretionary and for the other executive +officers, their STI performance based award percentages remain unchanged from +2006. +The +Role of Equity-Based Compensation +The +Company’s LTI program is an integral part of the Company’s overall executive +compensation program. The LTI program is intended to serve a number of +objectives. These include aligning the interests of executives with those of +the +Company’s shareholders, and focusing senior executives on the achievement of +well-defined, long-term performance objectives that are aligned with the +Company’s corporate strategy, thereby establishing a direct relationship between +compensation and shareholder value. The program also furthers the goal of +executive retention, since the executive officer will forfeit any unvested +awards in the event the officer voluntarily terminates employment with the +Company without "good reason." +In +making +long-term incentive awards, the Committee uses a pre-determined market-based +value approach. The Committee determines the dollar value of awards in the +marketplace using a valuation methodology. The Committee establishes the desired +dollar value for each executive officer relative to the market. The +corresponding number of equity instruments to be awarded is then determined +using the same valuation methodology, based on prevailing factors in advance +of +the award date. The valuation for financial statement purposes is subsequently +re-calculated based on the prevailing factors at the time of the +award. +The +value-based approach can cause the number of equity instruments needed to be +granted from year to year to vary, even though the awards may have the same +dollar value. This can be caused by, among other things, fluctuations in the +Company’s common stock price at the time of grant. This issue is further +addressed in the Long-Term Incentives section. +61 +Index +Use +of Benchmarking to Establish Target Compensation Levels +In +furtherance of its compensation objectives, the Committee compared the Company’s +compensation levels with those of a group of 14 companies in 2006, and 15 +companies in 2007, in setting compensation targets. These groups, collectively, +are referred to as the “Peer Group.” This benchmarking is done with respect to +each of the key elements of the Company’s executive compensation programs +discussed above (salary, STI and LTI compensation), as well as the compensation +of individual executives based on their position in the overall compensation +hierarchy. The Committee uses data from the Peer Group to establish a dollar +target level for each key element to deliver compensation to each executive +at +approximately the 50th percentile of the Peer Group, with adjustments made +based +on the executive’s individual performance. Targeting the 50th percentile helps +ensure that the Company’s compensation practices will be competitive in terms of +attracting and retaining executive talent, while performance based compensation +provides for variations due to superior or sub-par performance. Because +compensation for the Peer Group is for prior periods, the Committee attempts +to +anticipate future movements in compensation levels when it sets compensation +targets. For example, when setting compensation for 2006, the most recent +compensation information available was from the 2005 proxy statements for +compensation paid in 2004. As more up to date information becomes available, +it +is reviewed by the Committee to evaluate whether future compensation plans +should be adjusted to take unanticipated changes in actual compensation of +the +Peer Group into account. +The +2006 +Peer Group was comprised of the following companies: +• +Unit Corporation +• +St. Mary Land & Exploration Company +• +Cabot Oil & Gas Corporation +• +Penn Virginia Corporation +• +Whiting Petroleum Corporation +• +Range Resources Corporation +• +Encore Acquisition Company +• +Berry Petroleum Company +• +KCS Energy Incorporated +• +Quicksilver Resources Inc +• +Clayton Williams Energy Incorporated +• +Brigham Exploration Company +• +Magnum Hunter Resources Incorporated +• +Cimarex Energy Company +For +2007, +Forest Oil Corporation, Comstock Resources Incorporated and Bill Barrett +Corporation were added to the Peer Group. Cimarex acquired Magnum Hunter in +2005 +and these companies were removed from the Peer Group as they were no longer +comparable due to size. The Committee believes that the Peer Group represents +companies with similar operations, of similar complexity, and with which the +Company believes it competes for executive talent. +Review +of Overall Compensation +The +Committee reviews for each of the executive officers the total dollar value +of +the officer’s annual compensation, including salary, STI, LTI compensation, +perquisites, deferred compensation accruals and other compensation. The +Committee also reviews shareholdings and accumulated unrealized gains under +prior equity-based compensation awards, and amounts payable to the executive +officer upon termination of the executive’s employment under various different +circumstances, including retirement and termination in connection with a change +in control. See 2006 Summary Compensation Table below. +Consideration +of Prior Compensation +While +the +Committee considers all compensation previously paid to the executive officers, +including amounts realized or realizable under prior equity-based compensation +awards, the Committee believes that current compensation practices must be +competitive to retain the executives in light of prevailing market practices +and +to motivate the future performance of the executive officers. Accordingly, +wealth accumulation through superior past performance of the Company should +not +be punished through reductions in current compensation levels. +Elements +of Executive Compensation +To +accomplish the objectives of the executive compensation program, the Committee +uses four elements of compensation in varying proportions for the different +executive officers. These elements are base salary, STI, LTI, and other +benefits. The Committee uses cash payments (base salary and STI), awards tied +to +the Company's stock (LTI, which we also refer to as “equity-based compensation”) +and non-cash benefits in its overall compensation packages. The Committee +balances salary and performance-based compensation, and cash and non-cash +compensation, in a manner it believes best serves the objectives of the +Company’s compensation program. The Committee allocates among the different +elements of compensation in a manner similar to the median allocation of the +Peer Group, based on the level of the executive's position. Generally, it is +the +policy of the Committee that, as income levels increase, a greater proportion +of +the executive’s income should be in the form of STI and LTI compensation. For +example the CEO of the Company receives a higher percentage of his compensation +in the form of short and long term incentives compared to other executives, +as +is the case of CEOs in the Peer Group. The following table shows the breakdown +of target compensation among the three elements for 2006 and 2007 for each +executive officer. +62 +Index +Target +Compensation for Elements +as +a +Percentage of Total Target Compensation +2006 +2007 +Name +Base +Salary +Bonus +Target +Equity +Target +Base +Salary +Bonus +Target +Equity +Target +Steven +R. Williams +31 +% +23 +% +46 +% +33 +% +24 +% +43 +% +Thomas +E. Riley +36 +% +18 +% +46 +% +36 +% +22 +% +42 +% +Eric +R. Stearns +37 +% +19 +% +44 +% +36 +% +23 +% +41 +% +Richard +W. McCullough (1) +- +- +- +40 +% +20 +% +40 +% +Darwin +L. Stump +39 +% +19 +% +42 +% +44 +% +22 +% +34 +% +_______________ +(1) +Mr. +McCullough was appointed as CFO in November 2006. The initial contract +period runs through 2008. +Base +Salary +The +Committee annually reviews the base salaries of the Chief Executive Officer +(“CEO”) and other executive officers. Salaries are also reviewed in the case of +promotions or other significant changes in responsibilities. In each case, +the +Committee takes into account the results achieved by the executive, his or +her +future potential, scope of responsibilities and experience, and competitive +salary practices of the Peer Group. Base salary is intended to provide a +baseline of compensation that is not contingent upon the Company’s performance. +After +reviewing the Peer Group salary levels and considering individual performance, +the Committee established Base Salary increases for 2006 of 8.5% for the CEO, +and between 5% and 8.7% for the other executive officers. The total compensation +of the executive officers approximated the mean of the Peer Group, although +the +spread between the highest and lowest is less than the Peer Group. This is +consistent throughout the elements of compensation, and reflects the goal of +the +Committee to encourage a strong team among the executive officers. For 2007, +the +Committee established Base Salary increases of 7.2% for the CEO, and between +0% +and 8.2% for the other executive officers. Mr. McCullough, the Company’s CFO, +will receive the compensation established in his employment contract, executed +in November 2006. Annual base salaries for the executive officers for 2006 +and +2007 are shown in the following table: +Annual +Base Salaries +Name +2006 +2007 +Steven +R. Williams +$ +345,000 +$ +370,000 +Thomas +E. Riley +272,000 +292,500 +Eric +R. Stearns +251,000 +271,500 +Richard +W. McCullough +- +235,000 +Darwin +L. Stump +220,500 +220,500 +Short-Term +Incentives +Annual +STI are tied to the Company’s overall performance for the fiscal year, as +measured against objective criteria set by the Committee, as well as the +Committee’s assessment of individual performance of each executive. For 2006, at +least 70% of the target STI payments are performance based awards measured +against objective criteria established early in the fiscal year. The remainder +may include additional awards based on performance goals, or may be awarded +at +the discretion of the Committee based on its assessment of the executive’s +performance. For 2007, 100% of Mr. Stump's STI is discretionary and for the +other executive officers, their STI performance based award percentages remain +unchanged from 2006. The Compensation Committee has decided to maintain +discretion over STI bonus amounts for Mr. Stump to emphasize the focus of his +role in 2007 on the continued development of the accounting functions of the +Company rather than on production targets and overall financial performance. +The +Committee, comprised entirely of independent directors, believes that some +discretion with respect to individual awards is desirable to compensate for +unusual and unexpected events. +Target +STI payments, expressed as a percentage of base salary, are set for each +executive officer prior to the beginning of the fiscal year based on job +responsibilities. STI payments for the year may range from zero up to 150% +of +the executive officer’s base salary, based on the achievement of the objective +criteria for performance based payments and the assessment by the Committee +for +individual goals. For fiscal year 2006 and again in 2007, target STI awards +for +the executive officers ranged from 50% to 75% of salary. +With +respect to the executive officers, the Committee establishes formulae to +determine the percentage of the target annual incentive payment that may be +payable for the fiscal year. The Committee does not have the discretion to +change any objective criteria once they have been established. However, the +Committee does retain discretion over 30% (in 2007, 100% for Mr. Stump) of +the +total target STI to allow some flexibility to award superior, or reflect the +effect of sub-par, personal performance that may not be captured by the +financial and operating criteria. In addition, the Committee has the authority +to recommend to the Board compensation for unusual events. In 2006, Eric +Stearns, the Executive Vice President of Exploration and Production, received +a +special bonus for his key role in the $354 million acreage sale to Marathon. +The +following table sets forth the STI threshold, target and maximum levels for +2006 +and 2007 for the executives expressed as a percentage of base +salary. +63 +Index +Short-Term +Incentive Compensation +2006 +2007 (1) +% +of Base Salary +% +of Base Salary +Name +Threshold +Target +Stretch +Threshold +Target +Stretch +Steven +R. Williams +0 +% +75 +% +150 +% +0 +% +75 +% +150 +% +Thomas +E. Riley +0 +% +50 +% +100 +% +0 +% +62.5 +% +125 +% +Eric +R. Stearns +0 +% +50 +% +100 +% +0 +% +62.5 +% +125 +% +Richard +W. McCullough (2) +- +- +- +0 +% +50 +% +100 +% +Darwin +L. Stump +0 +% +50 +% +100 +% +- +- +- +_______________ +(1) +In +2007, the target percentages apply to Messrs. Williams, Riley, Stearns +and +McCullough. For Mr. Stump, 100% of his STI is +discretionary. +(2) +Mr. +McCullough was appointed as CFO in November 2006. The initial contract +period runs through 2008. +Long-Term +Incentives +Historically, +the primary form of equity compensation awarded by the Company was qualified +and +non-qualified stock options. This form was selected because of the favorable +individual and corporate accounting and tax treatments provided by the +accounting and tax rules prevalent at the time, and the widespread use of stock +options in executive compensation. In 2004, the Committee began utilizing a +combination of restricted stock and options for executive compensation, +believing that the restricted stock was better appreciated by employees and +resulted in less dilution for the Shareholders. Beginning in 2006, the +accounting treatment for stock options changed as a result of the applicability +of Statement of Financial Accounting Standards No. 123(R), making the use of +stock options less attractive. As a result, the Committee assessed the +desirability of granting only shares of restricted stock to executives, and +concluded that shifting entirely to restricted stock would provide an equally +motivating form of incentive compensation, while permitting the issuance of +fewer shares, thereby reducing potential dilution to other shareholders. The +Committee did want to tie the value received by executives to performance for +a +portion of the equity compensation, thereby providing executives with a greater +incentive to focus on the long-term appreciation of the stock. To accomplish +this, a portion of the LTI for each executive consists of LTI performance shares +(“LTIP shares”), which require both the passage of time and specified increases +in the stock price to become vested. +The +Committee’s practice has been to determine the dollar amount of equity +compensation and to then grant a number of shares of restricted stock and +options that have a fair value equal to that amount on the date of grant. The +2007 awards were determined using the fair value of the awards based on the +average daily closing price of the Company's stock in December 2006. The +Consultant calculated the fair value utilizing methods they have developed +for +use with these types of equity valuations, including taking into account the +probability and/or timing of vesting under the performance criteria for the +LTIP +shares and the other restricted stock. For the purpose of recording an expense +for financial reporting purposes, the awards will be revalued based on the +prevailing capital markets factors at the time of the award. +In +April +2007, the Company corrected an administrative error in the stock option exercise +price of shares awarded the executive officers in March 2006, none of which +were +exercised. The administrative error related to the use of the closing price +of +the Company's common stock on the day prior to the award, rather than the +closing price on the day of the award in accordance with the Company's 2004 +Long-Term Equity Compensation Plan. The need for the correction was identified +by the Company and the effect of the correction was not material to the fair +value of the awards, either at the time of the award or the time of the +correction. +For +2006, +the fair value of all Long-Term Incentive (“LTI”) awards was divided as follows: +70% for time vesting restricted stock and 30% for stock options (with both +types +of awards vesting 25% per year over a four year period). In 2007, a percentage +of the equity-based compensation awards are LTIP shares with the percentage +increasing for more highly compensated executives, and the balance of the awards +are time vesting restricted stock. For example, 50% of the CEO’s equity-based +compensation in 2007 will be LTIP shares, in contrast to 40% for the President +and 30% for the CAO. The following table summarizes LTI awards for 2006 and +2007, and the second table summarizes the target prices for the performance +vesting of the LTIP awards. +64 +Index +Long-Term +Incentive Compensation +2006 +2007 +Name +Percent +Of +Salary +Percent of Value +From +Time +Vesting +Restricted Stock +Percent +of Value +From +Stock +Options +Percent +Of +Salary +Percent of Value +From +Time +Vesting +Restricted Stock +Percent +of Value +From +LTIP +Stock +Steven +R. Williams +150 +% +70 +% +30 +% +175 +% +50 +% +50 +% +Thomas +E. Riley +125 +% +70 +% +30 +% +145 +% +60 +% +40 +% +Eric +R. Stearns +120 +% +70 +% +30 +% +140 +% +60 +% +40 +% +Richard +W. McCullough (1) +100 +% +70 +% +30 +% +- +- +- +Darwin +L. Stump +110 +% +70 +% +30 +% +90 +% +70 +% +30 +% +_______________ +(1) +LTI +awarded in 2006 pursuant to initial employment agreement. Mr. McCullough +will be eligible for annual award consideration beginning in +2008. +LTIP +Target Prices (1) +Approximate +Target +Price +Percent +Vested if +Growth +Target +Year +3 +Year +4 +Year +5 +Target +Attained (2) +12 +% +$ +60.00 +$ +67.50 +$ +75.00 +50 +% +16 +% +67.50 +77.50 +90.00 +75 +% +20 +% +75.00 +90.00 +107.50 +100 +% +_______________ +(1) +Growth +target percentages and target prices are based on the average closing price +of +the Company's common stock during the preceding December for each of the years +ended December 31, 2009, 2010 and 2011. +(2) +Performance +shares will vest for a performance period only if the target price is met or +exceeded for such period. Performance shares vested for a performance period +shall not be subject to divestment in the event the share price subsequently +decreases below the threshold in a subsequent performance +period. +Retirement +Plans +As +of +January 1, 2006, the Company maintained a 401(k) plan and a qualified profit +sharing plan for all of the Company’s employees including the executive +officers. On July 1, 2006, the two plans were combined into a single plan. +The +plan provides for discretionary matching contributions. Generally, the Company +matches employee 401(k) contributions dollar for dollar up to 10% of the +employee’s compensation and then matches 20% for contributions above 10% of the +employees' compensation up to the maximum allowable limits under the Internal +Revenue Code ("IRC"). The Company's profit sharing contribution is discretionary +and for 2006 was equal to 1% of the Company's consolidated net income. Total +Company contributions, to both 401(k) and profit sharing, to the plan in 2006 +were $3.1 million. +Under +their current employment agreements, each of the executive officers also earns +the right to future payments following their retirement or other departure +from +the Company. For each year worked under his current agreement, the CEO earns +an +annual retirement benefit equal to $500 times the number of his full years +of +service times 10 ($500 per year of service for 10 years). Following the +termination of his service with the Company, the cumulative total of the +calculated annual retirement benefits is disbursed in ten equal annual +installments. For 2006, the retirement benefit was $115,000 ($11,500 per year +for 10 years) and for 2007, the retirement benefit will be $120,000 ($12,000 +per +year for 10 years). The CEO's total cumulative retirement benefit, under this +plan, at December 31, 2006, was $330,000 ($33,000 per year for 10 years). Each +of the other executive officers, under their respective employment agreements, +annually earns a retirement benefit equal to $75,000 ($7,500 per year for 10 +years). Following their termination of service with the Company, their +cumulative total annual retirement benefit will be disbursed in ten equal annual +installments. As of December 31, 2006, for each of the other executive officers, +excluding Mr. McCullough, the total cumulative benefit, including the 2006 +increment, was $225,000 ($22,500 per year for 10 years). As of December 31, +2006, Mr. McCullough had not yet completed sufficient service to qualify for +the +benefit, but will, like the others, be eligible in 2007. +Additionally, +under his previous employment agreement, Mr. Williams earned supplemental +retirement benefits. The prior agreement requires the Company to pay Mr. +Williams an annual sum of $40,000 per year for the ten year period following +his +retirement from the Company (an aggregate of $400,000). This benefit was fully +vested on December 31, 2003. Under provisions of his previous employment +agreement, Mr. Williams may elect to defer payment up to five years following +his retirement. In the event of employment beyond the five year vesting period +or the deferral of payment following retirement the amount of the annual benefit +will be increased by 10.75% compounded annually. As of December 31, 2006, the +amount of this benefit is $543,470 (or $54,347 per year for 10 years). In the +event of change in control the benefits due under this agreement will be +accelerated and due immediately. +65 +Index +Other +Compensation and Benefits +The +Company also provides certain other benefits to its executive officers that +are +not tied to any formal individual or Company performance criteria and are +intended to be part of a competitive overall compensation program. Each of +the +executive officers has 1) a Company vehicle (or vehicle allowance) that they +use +for Company business, and are allowed to use for personal uses as well, 2) +coverage under the Company’s medical plan and reimbursement of medical expenses +not covered by the plan, 3) the right to be reimbursed for one Board-approved +club membership, 4) reimbursement of the cost of a $1 million life insurance +policy, and 5) reimbursement of the cost of disability insurance. Given the +importance of the executives and their good health to the success of the Company +and the achievement of its business goals, the Committee believes that the +medical insurance and reimbursement encourage the executives to seek appropriate +medical assistance. The other benefits are commonly provided to executives +and +are necessary to create a competitive compensation package. +Termination +Benefits including Change in Control Payments +The +Committee believes that severance benefits for senior management should reflect +the fact that it may be difficult for employees to find comparable employment +within a short period of time. They also should disentangle the Company from +the +former employee as soon as practicable. For instance, while it is possible +to +provide salary continuation to an employee during the job search process, which +in some cases may be less expensive than a lump-sum severance payment, a +lump-sum severance payment is preferable in order to most cleanly sever the +relationship as soon as practicable. The Company has entered into employment +agreements with each of the executive officers that include change in control +provisions. These agreements provide for the continued employment of the +executives for a period of two years following a change in control of the +Company. These agreements are intended to retain the executives and provide +continuity of management in the event of an actual or threatened change in +the +control of the Company and ensure that the executive’s compensation and benefits +expectations would be satisfied in such event. +The +compensation provisions in the event of a change in control also serve to lessen +the potential negative impact of a change in control on the executive officers. +The Committee believes this is desirable to encourage the executives to consider +possible change in control situations that might benefit the Company’s +shareholders. +Where +the +termination is without “cause” or the executive officer terminates employment +for “good reason,” the severance plan provides for benefits equal to three times +the sum of: a) the executive officer’s highest base salary during the previous +two years of employment immediately preceding the termination date, plus b) +the +highest bonus paid to the executive officer during the same two year period. +The +executive officer is also entitled to 1) vesting of any unvested equity +compensation, 2) reimbursement for any unpaid expenses, 3) retirement benefits +earned under the current or previous agreements, 4) continued coverage under +the +Company’s medical plan for up to 18 months, and 5) payment of any earned, unpaid +bonus amounts. In addition, a terminated executive officer is entitled to +receive any benefits that he otherwise would have been entitled to receive +under +our 401(k) and profit sharing plan, although those benefits are not increased +or +accelerated. The Committee believes that these termination benefits are +comparable to the general practice among similar companies, although it has +not +conducted a study to confirm this. +Good +reason includes 1) assignment to the executive of duties materially and +adversely inconsistent with his position, duties, responsibilities and status +with the Company, 2) an adverse change in the executive’s position with the +Company, 3) a change in control of the Company, 4) a decrease of the executive +officer’s base salary, 5) a material reduction in the benefits provided by the +Company, 6) the requirement by the Company for the executive officer to be +based +anywhere outside of Bridgeport, West Virginia, 7) the failure by the Company +to +obtain a satisfactory agreement from any successor or assignee of the Company +to +assume and agree to the Company’s obligations under the employment agreement, or +8) any other material breach of the employment agreement by the +Company. +The +Company may terminate any of the executive officers for just cause, which is +defined in the employment agreements to include 1) a failure by the executive +to +perform his duties, 2) conduct by the executive that results in consequences +which are materially adverse to the Company, monetarily or otherwise, 3) a +guilty plea or conviction of a felony, or 4) a material breach of the terms +of +the employment agreement by the executive officer. If an executive officer +is +terminated for just cause, the Company is required to pay the executive officer +his base salary through the termination date plus any bonus (only for periods +completed and accrued, but not paid), incentive, deferred, retirement or other +compensation, and provide any other benefits, which have been earned or become +payable as of the termination date but which have not yet been paid or +provided. +66 +Index +If +an +executive officer voluntarily terminates his employment with the Company for +other than good reason, he is entitled to receive 1) the base salary, bonus +and +incremental retirement payment prorated for the portion of the year that the +executive officer is employed by the Company, 2) any incentive, deferred or +other compensation which has been earned or has become payable, but which has +not yet been paid under the schedule originally contemplated in the agreement +under which they were granted or in full without discount within 60 days of +the +termination date at the discretion of the Company, 3) any unpaid expense +reimbursement upon presentation by the executive officer of an accounting of +such expenses in accordance with normal Company practices, and 4) any other +payments for benefits earned under the employment agreement or Company +plans. +The +table +below provides information regarding the amounts each of the executive officers +would be eligible to receive if a termination event had occurred as of December +31, 2006: +Termination +Benefits +Name +Retirement +or +Voluntary +Termination +by +Executive +Termination +For +Cause +by +Company +Change +in Control or +Termination +Without +Cause or +Good +Reason +by +Executive +Death/ +Disability (1) +Steven +R. Williams (2) +$ +1,669,067 +$ +1,513,817 +$ +4,198,813 +$ +2,286,078 +Thomas +E. Riley +541,252 +459,652 +2,172,522 +1,069,117 +Eric +R. Stearns +520,252 +444,952 +2,315,782 +1,000,160 +Richard +W. McCullough (3) +- +- +1,153,767 +317,267 +Darwin +L. Stump +456,677 +423,602 +1,839,846 +681,171 +_______________ +(1) +In +the event of death or disability, the termination benefits would +consist +of (i) the base salary and bonus for the portion of the year the +executive +officer is employed by the Company; (ii) the base salary that would +have +been earned for six months after termination; (iii) immediate vesting +of +all equity and option awards; (iv) the payment of deferred retirement +compensation based upon the schedule originally contemplated in the +deferred retirement compensation agreement or in a lump-sum no later +than +two and one-half months following the close of the calendar year +in which +the death or disability occurred; (v) reimbursement for any unpaid +expenses; (vi) any benefits earned under the 401(k) and profit sharing +plan; and (vii) continued coverage under the Company's medical plan, +life +time coverage for Mr. Williams and for up to 18 months for all other +named +executive officers. +(2) +Includes +(i) the estimated lifetime value of medical benefits for Mr. Williams +and/or his spouse; and (ii) the sum of deferred retirement compensation +benefits related to prior employment agreement and current employment +agreement. +(3) +Includes +a signing bonus of $83,000 (employment effective November 15, 2006). +If +employment terminates within one year after commencement of employment, +Mr. McCullough must refund to the Company a pro-rata portion of the +signing bonus. +Executive +and Director Share Retention and Ownership Guidelines +In +order +to promote equity ownership and further align the interests of management with +the Company’s shareholders, the Committee has adopted share retention and +ownership guidelines for senior management and non-employee directors. Under +these guidelines, executive officers and non-employee directors are required +to +achieve and continue to maintain a significant ownership position, expressed +as +a multiple of salary as follows: +Chief +Executive Officer +3 +times salary +Other +Executive Officers (4 persons) +2 +times salary +Non-Employee +Directors +1 +times retainer +The +Committee periodically reviews share ownership levels of the persons subject +to +these guidelines. Shares held by the executive officers and shares held +indirectly through the Company 401(k) plan are included in determining an +executive officer’s share ownership. Shares underlying stock options, including +vested options, as well as unvested restricted stock, are not included. Each +of +the executive officers, excluding Mr. McCullough who was hired in November +2006, +and the non-employee directors have achieved shareholdings in excess of the +applicable multiple set forth above. +The +Company’s insider trading policy expressly prohibits Company officers, +directors, employees and associates from engaging in options, puts, calls or +other transactions that are intended to hedge against the economic risk of +owning the Company shares. +67 +Index +Employment +Agreements +The +Company entered into employment agreements with Messrs. Williams, Riley, Stearns +and Stump effective January 1, 2004, and Mr. McCullough effective November +13, +2006. The initial term of the agreements is for two years and they are +automatically extended for an additional 12 months beginning on the first +anniversary of the effective date and on each successive anniversary unless +either party cancels. The employment agreements provide for the base annual +salary to be reviewed annually (see "Base Salary" discussion above ). +Each +employment agreement provides for an annual performance bonus as determined +by +the Compensation Committee and is based in part upon written objective criteria +and in part upon the discretion of the Compensation Committee. The annual +performance bonus earned is calculated as a percentage, as determined by the +Compensation Committee, of the executive officers' base salary. +Each +employment agreement contains a standard non-disclosure covenant and, also, +provides that the executive officer is prohibited during the term of his +employment and for a period of one year following his termination from engaging +in any business that is competitive with the Company's oil and gas drilling +business. Additionally, the employment agreements state that the executive +officer must devote substantially all of his business time, best efforts and +attention to promote and advance the business of the Company. The executive +officer may not be employed in any other business activity, other than with +the +Company, during the term of the employment agreement, whether or not such +activity is pursued for gain, profit or other pecuniary advantage without +approval by the Compensation Committee of the Board. This restriction will +not +prevent the executive officer from investing his personal assets in a business +which does not compete with the Company or its affiliates, and where such +investment will not require services of any significance on the part of the +executive officer in the operation of the affairs of the business. +Other +Agreements and Arrangements +Executive +officers may invest in a Board-approved executive drilling program at the +Company's cost. During 2006, Messrs. Williams, Riley and Stump invested +approximately $40,000, $20,000 and $17,000, respectively. Other investors +participating in drilling with the Company are generally charged a profit or +markup above the cost of the wells; for example, the markup on Company-sponsored +partnerships is approximately 15% of the cost of the wells. As a result, the +executive officers realize a benefit not generally available to other investors. +The Board believes that having the executive officers invest in wells with +the +Company and other investors helps to create a commonality of interests much +like +share ownership creates a commonality of interests between the shareholders +and +executive officers. +Internal +Revenue Code Section 162(m) +The +Committee is aware of IRC Section 162(m) of the tax code, which generally limits +the deductibility of executive pay in excess of one million dollars, and which +specifies the requirements for the “performance-based” exemption from this +limit. Elements of the executive compensation program are indeed +performance-based, and vehicles such as stock options are believed to qualify +as +performance-based under Section 162(m). Other aspects of the executive +compensation program may not qualify as performance-based, such as time-based +restricted stock and our annual incentive plan because the Committee prefers +the +ability to exercise discretion in evaluating a portion of participants' +performance. The financial implications of a potential lost deduction are not +expected to be material. The Committee will continue to monitor its position +on +the impact of Section 162(m) for the Company's executive compensation programs. +Compensation +Committee Report +The +Compensation Committee has met to review and discuss with the Company’s +management the specific disclosure contained under the heading “Compensation +Discussion and Analysis”. Based on its review and discussions with management +the Compensation Committee has recommended to the Board of Directors that the +Compensation Discussion and Analysis be included in this Annual Report on Form +10-K. +This +report has been provided by the Compensation Committee of the Board of Directors +of the Company. +David +C. +Parke, Chairman +Vincent +F. D'Annunzio +Anthony +J. Crisafio +*** +68 +Index +2006 +SUMMARY COMPENSATION TABLE +The +following table provides summary compensation information for the Company's +Chief Executive Officer, the Chief Financial Officer, and the three most highly +compensated executive officers, other than the Chief Executive Officer and +Chief +Financial Officer, whose total compensation exceeded $100,000 in 2006 (the +"named executive officers"). +Name +and Principal Position +Salary +Bonus (1) +Stock +Awards +(2) +Option +Awards +(3) +Non-Equity +Incentive +Plan +Compensation (4) +Nonqualified +Deferred +Compensation +(5) +All +Other +Compensation +(6) +Total +Compensation +Steven +R. Williams +$ +345,000 +$ +155,250 +$ +163,023 +$ +54,546 +$ +362,250 +$ +88,438 +$ +37,778 +(7) +$ +1,206,285 +Chairman, +Chief Executive Officer and Director +Thomas +E. Riley +272,000 +81,600 +107,580 +35,977 +190,400 +30,824 +9,357 +(8) +727,738 +President +and Director +Eric +R. Stearns +251,000 +175,300 +(9) +98,318 +32,806 +175,700 +21,730 +17,773 +772,627 +Executive +Vice President, Exploration and Development +Richard +W. McCullough +32,237 +83,000 +(10) +5,928 +2,289 +- +3,848 +- +127,302 +Chief +Financial Officer and Treasurer +Darwin +L. Stump +220,500 +33,075 +85,963 +28,484 +154,350 +25,880 +17,610 +(11) +565,862 +Chief +Accounting Officer +_______________ +(1) +The +annual STI bonus plan provides for a discretionary component equal +to 30% +of the total STI award. The amounts for Messrs. Williams, Riley, +and Stump +represent only the discretionary amounts earned pursuant to the STI +plan. +The annual STI bonus plan has established performance criteria that +must +be met before 70% of the annual cash bonus may be paid. See discussion +of +the STI bonus plan above. +(2) +Represents +compensation expense recorded by the Company pursuant to FAS 123(R) +related to outstanding restricted stock awards. See Note 8, Common +Stock, +to the Consolidated Financial +Statements. +(3) +Represents +compensation expense recorded by the Company pursuant to FAS 123(R) +related to outstanding stock options. See Note 8, Common Stock, to +the +Consolidated Financial Statements. +(4) +Represents +performance based cash bonuses earned during the year and paid shortly +after year-end. As noted above in the discussion and analysis, the +STI +bonus plan has established performance criteria that must be met +for the +executive to earn 70% of the targeted annual cash bonus amount. +(5) +Represents +the present value of the current year benefit earned related to the +deferred compensation retirement plan. The amount for Mr. McCullough +was +based upon a prorated annual amount since 2006 was the initial year +of +employment. +(6) +All +Other Compensation includes insurance and medical reimbursements, +social +fringe benefits such as club dues and athletic event tickets, the +value +for the personal use of Company automobiles and discounts related +to +Company-sponsored drilling +programs. +(7) +Includes, +in addition to other compensation items discussed in (6) above, $20,170 +for post retirement medical and a discount received of $5,216 related +to +investments in Company-sponsored drilling programs, see discussion +above +in Other Agreements and +Arrangements. +(8) +Includes, +in addition to other compensation items discussed in (6) above, a +discount +received of $2,649 related to investments in Company-sponsored drilling +programs. +(9) +Includes +$75,300 pursuant to discretionary component of the STI plan and an +additional $100,000 bonus for his role in the sale of an undeveloped +leasehold in Grand Valley Field in September. +(10) +Represents +a signing bonus paid at the start of employment with the Company +in +November 2006. +(11) +Includes, +in addition to other compensation items discussed in (6) above, a +discount +received of $2,437 related to an investment in a Company-sponsored +drilling program. +69 +Index +2006 +GRANTS OF PLAN-BASED AWARDS TABLE +Estimated +Future Payouts +Number +of +Grant +Date +Under +Non-Equity +Securities +Exercise +Price +Fair +Value of +Incentive +Plan Awards +Number +of +Underlying +Per +Share +Stock +and +Shares +Option +of +Option +Option +Name +Grant +Date +Threshold +Target +Maximum +Awarded +Awards (1) +Awards (1) +Awards +(2) +Steven +R. Williams +3/16/2006 +$ +- +$ +- +$ +- +9,348 +7,517 +$ +44.95 +(3) +$ +571,886 +6/23/2006 +- +258,750 +517,500 +- +- +- +- +Thomas +E. Riley +3/16/2006 +- +- +- +6,141 +4,939 +44.95 +(3) +375,707 +6/23/2006 +- +136,000 +272,000 +- +- +- +- +Eric +R. Stearns +3/16/2006 +- +- +- +5,441 +4,375 +44.95 +(3) +332,860 +6/23/2006 +- +125,500 +251,000 +- +- +- +- +Richard +W. McCullough +11/14/2006 +- +- +- +4,256 +3,333 +43.60 +255,688 +Darwin +L. Stump +3/16/2006 +- +- +- +4,381 +3,523 +44.95 +(3) +268,020 +6/23/2006 +- +110,250 +220,500 +- +- +- +- +_______________ +(1) +Represents +awards under the Company's long-term equity compensation plan (see +Note 8, +"Common Stock," to the consolidated financial statements and "Long-Term +Incentives" above in the Compensation Discussion and Analysis for +additional discussion). +(2) +The +Grant Date Fair Value of stock and option awards is computed by +multiplying the restricted stock number of shares awarded by the +closing +price of the Company's stock on the date of the grant, plus the Black +Scholes value per share times the number of securities underlying +the +option shares. The closing price per share of awards on March 16, +2006, +and November 14, 2006, was $44.95 and $43.60, respectively. The Black +Scholes estimated fair value per share of the options awarded on +March 16, +2006, and November 14, 2006, was $20.18 and $21.04, +respectively. +(3) +In +April 2007, the Company corrected an administrative error related +to the +use of the closing price of the Company's common stock on the day +prior to +the award, rather than the closing price on the day of the award +in +accordance to the plan, see Long-Term Incentives discussion above. +The +Exercise Price Per Share correctly reflects the closing price per +share on +the day of the award. +70 +Index +Outstanding +Equity Awards at 2006 Fiscal Year-End Table +Option +Awards +Restricted +Stock Awards +Number +of Securities +Number +Market +Value +Underlying +Unexercised +of +Shares +of +Shares +Options +Held at +That +Have +That +Have +December +31, 2006 +Exercise +Expiration +Not +Not +Name +Exercisable +Unexercisable +Price +Date +Vested +Vested +(1) +Steven +R. Williams +2,935 +2,935 (2 +) +$ +37.15 +12/13/2014 +13,413 (3 +) +$ +577,430 +- +7,517 (4 +) +44.95 +3/16/2016 +- +- +Thomas +E. Riley +1,945 +1,945 (5 +) +37.15 +12/13/2014 +8,836 (6 +) +380,390 +- +4,939 (7 +) +44.95 +3/16/2016 +- +- +Eric +R. Stearns +1,835 +1,835 (8 +) +37.15 +12/13/2014 +7,981 (9 +) +343,582 +- +4,375 (10 +) +44.95 +3/16/2016 +- +- +Richard +W. McCullough +- +3,333 (11 +) +43.60 +11/14/2016 +4,256 (12 +) +183,221 +Darwin +L. Stump +1,725 +1,725 (13 +) +37.15 +12/13/2014 +6,771 (14 +) +291,492 +- +3,523 (15 +) +44.95 +3/16/2016 +- +- +_______________ +(1) +Market +value of shares is based on the closing price of the Company's common +stock on December 29, 2006, $43.05 per +share. +(2) +Vesting: +1,467 shares in 2007 and 1,468 shares in +2008. +(3) +Vesting: +4,369 shares in 2007, 4,370 shares in 2008, 2,337 shares in 2009 +and 2,337 +shares in 2010. +(4) +Vesting: +25% in each of the years 2007 through +2010. +(5) +Vesting: +972 shares in 2007 and 973 shares in +2008. +(6) +Vesting: +2,882 shares in 2007, 2,883 shares in 2008, 1,535 shares in 2009 +and 1,536 +shares in 2010. +(7) +Vesting: +25% in each of the years 2007 through +2010. +(8) +Vesting: +917 shares in 2007 and 918 shares in +2008. +(9) +Vesting: +2,630 shares in 2007, 2,630 shares in 2008, 1,360 shares in 2009 +and 1,361 +shares in 2010. +(10) +Vesting: +25% in each of the years 2007 through +2010. +(11) +Vesting: +25% in each of the years 2007 through +2010. +(12) +Vesting: +25% in each of the years 2007 through +2010. +(13) +Vesting: +862 shares in 2007 and 863 shares in +2008. +(14) +Vesting: +2,290 shares in 2007, 2,290 shares in 2008, 1,095 shares in 2009 +and 1,096 +shares in 2010. +(15) +Vesting: +25% in each of the years 2007 through +2010. +71 +Index +2006 +Options Exercises and Stock Vested Table +Option +Awards +Stock +Awards +Name +Number +of +Shares +Acquired +on +Exercise +Value +Realized +on +Exercise +Number +of +Shares +Acquired +on +Vesting +Value +Realized +on +Vesting (1) +Steven +R. Williams +- +$ +- +2,032 +$ +90,932 +Thomas +E. Riley +- +- +1,347 +60,278 +Eric +R. Stearns +- +- +1,270 +56,833 +Richard +W. McCullough +- +- +- +- +Darwin +L. Stump +- +- +1,195 +53,476 +_______________ +(1) +Based +on the closing price of the Company's common stock on the date of +vesting, +December 13, 2006, $44.75 per +share. +2006 +Nonqualified Deferred Compensation Table +Name +Executive +Contributions +in +2006 +Company +Contributions +in +2006 (1) +Aggregate +Earnings +in +2006 (2) +Aggregate +Withdrawals/ +Distributions +Aggregate +Balance +at +December +31, 2006 +Steven +R. Williams +$ +- +$ +88,438 +(3) +$ +35,699 +(4) +$ +- +$ +754,821 +Thomas +E. Riley +- +30,824 +3,489 +- +92,471 +Eric +R. Stearns +- +21,730 +2,460 +- +65,189 +Richard +W. McCullough +- +3,848 +- +- +3,848 +Darwin +L. Stump +- +25,880 +2,930 +- +77,641 +_______________ +(1) +Company +contributions include the present value cost of providing the defined +compensation payout over a ten year period. Since this is a self +funded +deferred compensation plan, the Company’s additional annual deferred +compensation expense, less the interest component noted as aggregate +earnings above, equals the increase in the accrued Company contributions +that are required to fund the plan. These annual amounts are a component +of the executive officers' 2006 compensation and are included in +the 2006 +Summary Compensation Table. +(2) +Aggregate +earnings consist of interest income earned on the beginning of the +year +compensation balance at a 6% interest rate. These earnings are not +included in the 2006 Summary Compensation Table as they are not above +market rate. +(3) +Mr. +Williams received deferred compensation benefits from both the current +deferred compensation plan for all named executive officers, as well +as a +prior retirement plan. The amount for Mr. Williams includes a reduction +of +$8,990 in the current funding amount due to the fact that the deferral +option has been elected by Mr. Williams for the start of benefits +under +the prior retirement plan. The deferred payment start date has been +deferred for five years after retirement. In addition, current year +required Company contributions were also reduced by $35,699 due to +a +change in Mr. Williams’ projected retirement date. +(4) +Aggregate +earnings for Mr. Williams include additional earnings of $4,590 on +the +Company’s previous retirement plan due to that plan’s “five year deferral +option”. +72 +Index +DIRECTOR +COMPENSATION +Each +non-employee director received an annual retainer of $40,000 during 2006. +Additionally, non-employee directors receive a fee for being a member of certain +committees. During the third quarter of 2006, the audit committee chairperson +began receiving an annual fee of $13,000, payable quarterly, and the other +audit +committee members began receiving an annual fee of $8,000, each, also payable +quarterly. The compensation committee chairperson received an annual fee of +$2,500 and the nominating committee chairperson received an annual fee of +$2,500. Non-employee directors also receive restricted stock compensation. +Pursuant to the shareholder approved, Non-Employee Director Restricted Stock +Plan (the “Restricted Stock Plan”), as of the date of each annual stockholders +meeting of the Company each non-employee director will be awarded a specified +number of shares of Restricted Stock as determined by the Board. The amount +of +the award for the upcoming plan year will be disclosed in the Company’s proxy +statement. Directors receiving Restricted Stock under the Restricted Stock +Plan +will have all of the rights of a stockholder including the right to vote the +shares and receive cash dividends and other cash distributions. Restricted +Stock +will be subject to the restrictions of the Restricted Period commencing on +the +date the stock is awarded. Each non-employee director can choose to defer a +portion or all of their annual cash compensation by participating in the +Non-Employee Director Deferred Compensation Plan. The plan's trustee will invest +all cash deposits received exclusively in the common stock of the Company. +2006 +Director Compensation Table +Name +Fees +Earned/ +Paid +in Cash +Stock +Awards +(1) +Option +Awards +All +Other +Compensation +Total +Kimberly +Luff Wakim +$ +46,500 (2) +$ +26,310 +$ +- +$ +- +$ +72,810 +Vincent +F. D'Annunzio +42,500 (3) +41,464 +- +- +83,964 +David +C. Parke +44,500 +23,088 +- +- +67,588 +Jeffrey +C. Swoveland +45,250 +23,088 +- +- +68,338 +Donald +B. Nestor +35,750 (4) +19,996 +- +- +55,746 +Anthony +J. Crisafio +12,000 +2,882 +- +- +14,882 +_______________ +(1) +Represents +compensation expense recorded by the Company pursuant to FAS 123(R). +See +Note 8, Common Stock, to the Consolidated Financial +Statements. +(2) +Includes +amounts deferred (20%) pursuant to stock purchase +election. +(3) +Includes +amounts deferred (100%) pursuant to stock purchase +election. +(4) +Retired +from directorship on September 1, 2006. He received a prorated annual +retainer and fees for three quarters of the year based on his time +of +service. +Compensation +Committee Interlocks and Insider Participation +There +are +no Compensation Committee interlocks. +73 +Index +ITE M +12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND +MANAGEMENT AND RELATED STOCKHOLDER MATTERS +The +following table sets forth certain information regarding ownership of the +Company's common stock as of April 30, 2007, by (a) each person known by the +Company to own beneficially more than 5% of the outstanding shares of common +stock; (b) each director of the Company; (c) each executive officer; and (d) +all +directors and executive officers as a group. As of April 30, 2007, 14,887,530 +common shares of the Company were issued and outstanding. +Name +and Address of Beneficial Owner +Number +Of +Shares +Beneficially +Owned +Percent +Of +Shares +Beneficially +Owned +FMR +Corporation +82 +Devonshire Street +Boston, +MA 02109 +2,420,360 +(1) +16.3 +% +Steinberg +Asset Management, LLC +12 +East 49th Street +New +York, NY 10017 +2,085,868 +(2) +14.0 +% +Kayne +Anderson Rudnick +Investment +Management, LLC +1800 +Avenue of the Stars, 2nd Floor +Los +Angeles, CA 90067 +1,078,093 +(3) +7.2 +% +Barclays +Global Investors, NA +45 +Fremont Street +San +Francisco, CA 94105 +1,029,403 +(4) +6.9 +% +Steven +R. Williams +310,931 +(5) +2.1 +% +Thomas +E. Riley +104,605 +(6) +* +Eric +R. Stearns +56,828 +(7) +* +Richard +W. McCullough +- +(8) +* +Darwin +L. Stump +26,540 +(9) +* +Vincent +F. D'Annunzio +21,042 +* +Jeffrey +C. Swoveland +12,916 +Kimberly +Luff Wakim +4,479 +* +David +C. Parke +4,129 +* +Anthony +J. Crisafio +1,035 +* +All +directors and executive officers as a group (10 persons) (10) +542,505 +(11) +3.6 +% +_______________ +* +Less +than 1% +74 +Index +(1) +According +to the Schedule 13G filed by FMR Management with the SEC on February +14, +2007. +(2) +According +to the Schedule 13G filed by Steinberg Asset Management with the +SEC on +February 9, 2007. +(3) +According +to the Schedule 13G filed by Anderson Rudnick Investment Management +with +the SEC on February 5, 2007. +(4) +According +to the Schedule 13G filed by Barclays Global Investors, NA Management +with +the SEC on January 23, 2007. +(5) +Includes +4,814 shares subject to options exercisable within 60 days of April +30, +2007; excludes 19,561 restricted shares subject to +vesting. +(6) +Includes +3,179 shares subject to options exercisable within 60 days of April +30, +2007; excludes 13,971 restricted shares subject to +vesting. +(7) +Includes +2,928 shares subject to options exercisable within 60 days of April +30, +2007; excludes 12,597 restricted shares subject to +vesting. +(8) +Excludes +4,256 restricted shares subject to +vesting. +(9) +Includes +2,605 shares subject to options exercisable within 60 days of April +30, +2007; excludes 9,316 restricted shares subject to +vesting. +(10) +Address: +120 Genesis Boulevard, Bridgeport, WV +26330. +(11) +Includes +13,526 shares subject to options exercisable within 60 days of April +30, +2007; excludes 59,701 restricted shares subject to +vesting. +Equity +Compensation Plan Information +The +following table summarizes information related to the Company's equity +compensation plans under which its equity securities are authorized for issuance +as of April 30, 2007. +Plan +category +Number +of securities to be +issued +upon exercise of +outstanding +options +Weighted-average +exercise +price +of outstanding options +Number +of securities +remaining +available for +future +issuance under equity +compensation +plans (1) +Equity +compensation plans approved by security holders (2) +59,567 +(3) +$ +29.56 +530,267 +Equity +compensation plans not approved by security holders +- +- +- +Total +59,567 +$ +29.56 +530,267 +_______________ +(1) +Excludes +the number of securities to be issued upon exercise of outstanding +options +and performance shares subject to certain performance goals over +a +specified period of time. +(2) +These +plans consist of the 1999 Incentive Stock Option and Non-Qualified +Stock +Option Plan, the 2004 Long-Term Equity Compensation Plan and the +2005 +Non-Employee Director Restricted Stock +Plan. +(3) +Excludes +31,972 shares of common stock issuable upon the obtainment of specified +performance goals over a specified period of +time. +ITE M +13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND +DIRECTOR INDEPENDENCE +Policies +and Procedures with Respect to Transactions with Related +Persons +The +Board +has adopted a policy for the review, approval and ratification of transactions +that involve related parties and potential conflicts of interest. +The +related party transaction policy applies to each director and executive officer +of the Company, any nominee for election as a director, any security holder +who +is known to own more than five percent of the Company's voting securities, +any +immediate family member of any of the foregoing persons and any corporation, +firm or association in which one or more of the Company's directors are +directors or officers, or have a substantial financial interest. +Under +the +related party transaction policy a related person transaction is a transaction +or arrangement involving a related person in which the Company is a participant +or that would require disclosure in the Company's filings with the SEC as a +transaction with a related person. +The +related persons must disclose to the Audit Committee any potential related +person transactions and must disclose all material facts with respect to such +interest. All related person transactions will be reviewed by the Audit +Committee. In determining whether to approve or ratify a transaction, the Audit +Committee will consider the relevant facts and circumstances of the transaction +which may include factors such as the relationship of the related person with +the Company, the materiality or significance of the transaction to the Company +and the business purpose and reasonableness of the transaction, whether the +transaction is comparable to a transaction that could be available to the +Company on an arms-length basis, and the impact of the transaction on the +Company's business and operations. +75 +Index +During +the year ended December 31, 2006, there was no transaction or series of +transactions, or any currently proposed transaction, in which the amount +involved exceeds $120,000 and in which any director, executive officer, holder +of more than 5% of our common stock or any member of the immediate family of +any +of the foregoing persons had or will have a direct or indirect material +interest. +ITE M +14. PRINCIPAL ACCOUNTANT FEES AND +SERVICES +KPMG +Fees +The +following table presents the aggregate fees billed to the Company by KPMG LLP +("KPMG") for services in 2006 and 2005 as of March 31, 2007. +2006 +2005 +Audit +fees +$ +2,038,701 +$ +2,457,423 +Audit +related fees +983,701 +394,543 +Total +audit and audit related fees (1) +$ +3,022,402 +$ +2,851,966 +_______________ +(1) There +were no tax or other fees for services rendered to us during either +of the +years. +Audit +Fees +Audit +fees include amounts billed for professional services rendered by KPMG for +the +audit of the Company's annual consolidated financial statements and the report +on management's assessment of internal control over financial reporting and +the +effectiveness of the Company's internal control over financial reporting for +the +years ended December 31, 2006 and 2005, including reviews of the condensed +consolidated financial statements included in the Company's quarterly reports +on +Form 10-Q for the years ended December 31, 2006 and 2005. The 2005 audit fees +also include fees billed for professional services rendered by KPMG for the +audit of the consolidated financial statements included in the Company's Form +10-K/A for the year ended December 31, 2004. +Audit +Related Fees +Audit +related fees include amounts billed for professional services rendered by KPMG +for the audits of the annual financial statements of the Company-sponsored +drilling partnerships for which the Company acts as managing general partner. +The aggregate billings for those professional services rendered during 2006 +primarily represent audits for years ended December 31, 2005 and prior. Total +audit related fees for the year ended December 31, 2005, includes $140,977 +related to due diligence services provided for a contemplated +transaction. +Audit +Committee Pre-Approval Policies and Procedures +The +Sarbanes-Oxley Act of 2002 requires that all services provided to the Company +by +its Independent Registered Public Accounting Firm be subject to pre-approval +by +the Audit Committee or authorized members of the Committee. The Audit Committee +has adopted policies and procedures for pre-approval of all audit services +and +non-audit services to be provided by the Company's Independent Registered Public +Accounting Firm. Services necessary to conduct the annual audit must be +pre-approved by the Audit Committee annually at a meeting. Permissible non-audit +services to be performed by the independent accountant may also be approved +on +an annual basis by the Audit Committee if they are of a recurring nature. +Permissible non-audit services to be conducted by the independent accountant, +which are not eligible for annual pre-approval, must be pre-approved +individually by the full Audit Committee or by an authorized Audit Committee +member. Actual fees incurred for all services performed by the independent +accountant will be reported to the Audit Committee after the services are fully +performed. The duties of the Committee are described in the Audit Committee +Charter, which is available at the Company's website under Corporate +Governance. +76 +Index +PART +IV +ITE M +15. EXHIBITS , +FINANCIAL STATEMENT SCHEDULES +(a) +(1) +Financial +Statements: +See +Index +to Financial Statements and Schedules on page F-1. +(2) +Financial +Statement Schedules: +See +Index +to Financial Statements and Schedules on page F-1. +Schedules +and Financial Statements Omitted +All +other +financial statement schedules are omitted because they are not required, +inapplicable, or the information is included in the Financial Statements or +Notes thereto. +(3) +Exhibits: +See +Exhibits Index on page E-1. +77 +Index +SIG NATURES +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. +PETROLEUM +DEVELOPMENT CORPORATION +By +/s/ +Steven R. Williams +Steven +R. Williams, Chairman +May +22, 2007 +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/ +Steven R. Williams +Steven +R. Williams +Chairman, +Chief Executive Officer and Director +(principal +executive officer) +May +22, 2007 +/s/ +Richard W. McCullough +Richard +W. McCullough +Chief +Financial Officer and Treasurer +(principal +financial officer) +May +22, 2007 +/s/ +Darwin L. Stump +Darwin +L. Stump +Chief +Accounting Officer +(principal +accounting officer) +May +22, 2007 +/s/ +Thomas E. Riley +Thomas +E. Riley +President +and Director +May +22, 2007 +/s/ +Jeffrey C. Swoveland +Jeffrey +C. Swoveland +Director +May +22, 2007 +/s/ +Vincent F. D'Annunzio +Vincent +F. D'Annunzio +Director +May +22, 2007 +/s/ +Kimberly Luff Wakim +Kimberly +Luff Wakim +Director +May +22, 2007 +/s/ +David C. Parke +David +C. Parke +Director +May +22, 2007 +/s/ +Anthony J. Crisafio +Anthony +J. Crisafio +Director +May +22, 2007 +78 +Index +Exhibits +Index +Exhibit +Number +Exhibit +Name +Location +3.1 +Amended +and Restated Certificate of Incorporation of the Company +Incorporated +by reference to Exhibit 3.1 to Form S-2, SEC File No. 333-36369, +filed on +September 25, 1997. +3.2 +Amended +and Restated By Laws of the Company +Incorporated +by reference to Exhibit 3.1 to Form 8-K filed on April 2, +2007. +10.1 +Amended +and restated Credit Agreement, dated as of November 4, 2005, Petroleum +Development Corporation, as borrower, and JPMorgan Chase Bank, N.A. +and +BNP Paribas, as lenders. +Incorporated +by reference to Exhibit 10.2 to Form 8-K dated November 4, +2005. +10.2 +Employment +Agreement with Steven R. Williams, Chief Executive Officer and Chairman, +dated as of March 7, 2003, and amended December 29, 2005 +Incorporated +by reference in Exhibit 10.2 to Form 10-K filed on March 7, 2003, +and +Exhibit 99.1 to Form 8-K filed January 4, 2006. +10.3 +Employment +Agreement with Darwin L. Stump, Chief Accounting Officer, dated as +of +January 5, 2004, and amended December 29, 2005 +Incorporated +by reference to Exhibit 99.4 Form 8-K dated January 5, 2004 and Exhibit +99.4 to Form 8-K dated January 4, 2006. +10.4 +Employment +Agreement with Thomas E. Riley, President, dated as of January 5, +2004, +and amended December 29, 2005 +Incorporated +by reference to Exhibit 99.6 Form 8-K dated January 5, 2004, and +Exhibit +99.2 to Form 8-K dated January 4, 2006. +10.5 +Employment +Agreement with Eric R. Stearns, Executive Vice President, dated as +of +January 5, 2004, and amended December 29, 2005 +Incorporated +by reference to Exhibit 99.5 Form 8-K dated January 5, 2004, and +Exhibit +99.3 to Form 8-K dated January 4, 2006. +10.6 +Employment +Agreement with Richard W. McCullough, Chief Financial Officer, dated +as of +November 13, 2006. +Filed +herewith. +10.7 +2007 +Compensation Arrangements with Executive Officers +Incorporated +by reference to Exhibit 99.1 to Form 8-K dated February 20, +2007. +10.8 +2007 +Long-Term Incentive Program +Incorporated +by reference to Exhibit 99.1 to Form 8-K dated February 20, +2007. +10.9 +2007 +Short-Term Incentive Program +Incorporated +by reference to Form 8-K dated April 2, 2007. +10.10 +2005 +Non-Employee Director Restricted Stock Plan +Incorporated +by reference to Exhibit 99.1 to Form S-8, SEC file No. 333-126444 +filed on +July 7, 2005. +10.11 +2004 +Long-Term Equity Compensation Plan +Incorporated +by reference to Exhibit 99.1 to Form S-8, SEC File No. 333-118215, +filed +on August 13, 2004. +79 +Index +Exhibit +Number +Exhibit +Name +Location +10.12 +Non-Employee +Director Deferred Compensation Plan +Incorporated +by reference Exhibit 99.1 to Form S-8, SEC File No. 333-118222, filed +on +August 13, 2004. +10.13 +1999 +Incentive Stock Option and Non-Qualified Stock +Incorporated +by reference to Exhibit 99.1 to form S-8, SEC File No. 333-111825, +filed +on January 9, 2004. +10.14 +1997 +Employee Incentive Stock Option Plan +Incorporated +by reference to Exhibit 99.1 to Form S-8, SEC File No. 333-111824, +filed +on January 9, 2004. +10.15 +Tom +Carpenter Employment Agreement Stock Option Plan +Incorporated +by reference to Exhibit 99.1 to Form S-8, SEC File No. 333-111823, +filed +on January 9, 2004. +14 +Code +of Business Conduct and Ethics +Incorporated +by reference to Exhibit 3.1 to Form 10-K for the year ended December +31, +2002, SEC File No. 0-07246 +filed on March 7, 2003. +21.1 +Subsidiaries +Filed +herewith. +23.1 +Consent +of Independent Registered Public Accounting Firm +Filed +herewith. +23.2 +Consent +of Independent Petroleum Engineers +Filed +herewith. +23.3 +Consent +of Independent Petroleum Engineers +Filed +herewith +31.1 +Rule +13a-14(a)/15d-14(a) Certification by Chief Executive +Officer +Filed +herewith. +31.2 +Rule +13a-14(a)/15d-14(a) Certification by Chief Financial +Officer +Filed +herewith. +32.1 +Title +18 U.S.C. Section 1350 (Section 906 of Sarbanes-Oxley Act of 2002) +Certifications by Chief Executive Officer and Chief Financial +Officer +Filed +herewith. +80 +Index +PETROLEUM +DEVELOPMENT CORPORATION +Index +to Consolidated Financial Statements and Financial Statement +Schedule +1. +Financial +Statements: +Report +of Independent Registered Public Accounting Firm +F-2 +Balance +Sheets - December 31, 2006 and 2005 +F-3 +Statements +of Income - Years Ended December 31, 2006, 2005 and 2004 +F-4 +Statements +of Shareholders' Equity - Years Ended December 31, 2006, 2005 and +2004 +F-5 +Statements +of Cash Flows - Years Ended December 31, 2006, 2005 and +2004 +F-6 +Notes +to Consolidated Financial Statements +F-7 +2. +Financial +Statement Schedule: +Valuation +and Qualifying Accounts and Reserves +F-38 +F-1 +Index +PETROLEUM +DEVELOPMENT CORPORATION +Report +of Independent Registered Public Accounting Firm +The +Board +of Directors and Shareholders +Petroleum +Development Corporation: +We +have +audited the accompanying consolidated balance sheets of Petroleum Development +Corporation and subsidiaries as of December 31, 2006 and 2005, and the related +consolidated statements of income, shareholders' equity, and cash flows for +each +of the years in the three-year period ended December 31, 2006. In connection +with our audits of the consolidated financial statements, we also have audited +the related financial statement schedule. These consolidated financial +statements and financial statement schedule are the responsibility of the +Company's management. Our responsibility is to express an opinion on these +consolidated financial statements and financial statement schedule 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, the consolidated financial statements referred to above present fairly, +in all material respects, the financial position of Petroleum Development +Corporation and subsidiaries as of December 31, 2006 and 2005, and the results +of their operations and their cash flows for each of the years in the three-year +period ended December 31, 2006, in conformity with U. S. generally accepted +accounting principles. Also in our opinion, the related financial statement +schedule, when considered in relation to the basic consolidated financial +statements taken as a whole, presents fairly, in all material respects, the +information set forth therein. +As +discussed in Note 1 to the consolidated financial statements, the Company +adopted the provisions of Statement of Financial Accounting Standards No. +123(R), (“Share-Based Payment”), in 2006. +As +discussed in Note 1 to the consolidated financial statements, the Company +changed its method of quantifying errors based on SEC Staff Accounting Bulletin +No. 108 (“Considering the Effects of Prior Year Misstatements when Quantifying +Misstatements in Current Year Financial Statements”) in 2006. +We +also +have audited, in accordance with the standards of Public Company Accounting +Oversight Board (United States), the effectiveness of Petroleum Development +Corporation's internal control over financial reporting as of December 31, +2006, +based on criteria established in Internal Control - Integrated Framework issued +by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) +and our report dated May 22, 2007, expressed an unqualified opinion on +management’s assessment of, and an adverse opinion on the effective operation +of, internal control over financial reporting as of December 31, +2006. +KPMG +LLP +Pittsburgh, +Pennsylvania +May +22, +2007 +F-2 +Index +PETROLEUM +DEVELOPMENT CORPORATION +Consolidated +Balance Sheets +(in +thousands, except share and per share data) +December +31, +2006 +2005 +Assets +Current +assets: +Cash +and cash equivalents +$ +194,326 +$ +90,110 +Restricted +cash +519 +1,501 +Accounts +receivable, net +42,600 +43,248 +Accounts +receivable - affiliates +9,235 +9,041 +Inventories +3,345 +5,055 +Fair +value of derivatives +15,012 +10,382 +Other +current assets +5,977 +4,640 +Total +current assets +271,014 +163,977 +Properties +and equipment, net +394,217 +265,926 +Restricted/designated +cash +192,451 +- +Goodwill +6,783 +- +Other +assets +19,822 +14,458 +Total +Assets +$ +884,287 +$ +444,361 +Liabilities +and Shareholders' Equity +Current +liabilities: +Accounts +payable +$ +67,675 +$ +55,049 +Short +term debt +20,000 +- +Production +tax liability +11,497 +11,758 +Other +accrued expenses +9,685 +4,141 +Accounts +payable - affiliates +7,595 +1,479 +Deferred +gain on sale of leaseholds +8,000 +- +Federal +and state income taxes payable +28,698 +8,473 +Fair +value of derivatives +2,545 +18,424 +Advances +for future drilling contracts +54,772 +49,999 +Funds +held for distribution +31,367 +31,417 +Total +current liabilities +241,834 +180,740 +Long-term +debt +117,000 +24,000 +Deferred +gain on sale of leaseholds +17,600 +- +Other +liabilities +19,400 +16,184 +Deferred +income taxes +116,393 +26,889 +Asset +retirement obligation +11,916 +8,283 +Total +liabilities +524,143 +256,096 +Commitments +and contingent liabilities +Shareholders' +equity: +Common +stock, par value $.01 per share;authorized 50,000,000 shares;issued +14,834,871 shares and issued and outstanding 16,281,923 +shares +148 +163 +Additional +paid-in capital +64 +30,423 +Retained +earnings +360,102 +158,504 +Unamortized +stock award +- +(825 +) +Treasury +shares at cost, 4,706 shares +(170 +) +- +Total +shareholders' equity +360,144 +188,265 +Total +Liabilities and Shareholders' Equity +$ +884,287 +$ +444,361 +See +accompanying Notes to Consolidated Financial Statements. +F-3 +Index +PETROLEUM +DEVELOPMENT CORPORATION +Consolidated +Statements of Income +(in +thousands, except per share data) +Year +Ended December 31, +2006 +2005 +2004 +Revenues: +Oil +and gas well drilling operations +$ +17,917 +$ +99,963 +$ +94,076 +Gas +sales from marketing activities +131,325 +121,104 +94,627 +Oil +and gas sales +115,189 +102,559 +69,492 +Well +operations and pipeline income +10,704 +8,760 +7,677 +Oil +and gas price risk management gains (losses), net +9,147 +(9,368 +) +(3,085 +) +Other +2,221 +2,180 +1,696 +Total +revenues +286,503 +325,198 +264,483 +Costs +and expenses: +Cost +of oil and gas well drilling operations +12,617 +88,185 +77,696 +Cost +of gas marketing activities +130,150 +119,644 +92,881 +Oil +and gas production and well operations cost +29,021 +20,400 +17,713 +Exploration +cost +8,131 +11,115 +- +General +and administrative expense +19,047 +6,960 +4,506 +Depreciation, +depletion, and amortization +33,735 +21,116 +18,156 +Total +costs and expenses +232,701 +267,420 +210,952 +Gain +on sale of leaseholds +328,000 +7,669 +- +Income +from operations +381,802 +65,447 +53,531 +Interest +income +8,050 +898 +185 +Interest +expense +(2,443 +) +(217 +) +(238 +) +Income +before income taxes +387,409 +66,128 +53,478 +Income +taxes +149,637 +24,676 +20,250 +Net +income +$ +237,772 +$ +41,452 +$ +33,228 +Basic +earnings per common share +$ +15.18 +$ +2.53 +$ +2.05 +Diluted +earnings per common share +$ +15.11 +$ +2.52 +$ +2.00 +See +accompanying Notes to Consolidated Financial Statements. +F-4 +Index +PETROLEUM +DEVELOPMENT CORPORATION +Consolidated +Statements of Shareholders' Equity +(in +thousands, except share and per share data) +Year +Ended December 31, +2006 +2005 +2004 +Common +stock - shares issued: +Shares +at beginning of year +16,281,923 +16,589,824 +15,628,433 +Adjust +prior conversion of predecessor shares +59,546 +- +- +Exercise +of stock options +8,000 +3,000 +1,100,000 +Issuance +of stock awards, net of forfeitures +112,902 +20,895 +23,380 +Retirement +of treasury shares +(1,627,500 +) +(331,796 +) +(161,989 +) +Shares +at end of year +14,834,871 +16,281,923 +16,589,824 +Treasury +stock: +Shares +at beginning of year +- +- +- +Purchase +of treasury shares +(1,627,500 +) +(331,796 +) +(161,989 +) +Retirement +of treasury shares +1,627,500 +331,796 +161,989 +Non-employee +directors' deferred compensation plan +(4,706 +) +- +- +Shares +at end of year +(4,706 +) +- +- +Common +shares outstanding +14,830,165 +16,281,923 +16,589,824 +Common +stock, $.01 par: +Balance +at beginning of year +$ +163 +$ +166 +$ +156 +Exercise +of stock options +- +- +11 +Issuance +of stock awards, net of forfeitures +1 +- +- +Retirement +of treasury shares +(16 +) +(3 +) +(1 +) +Balance +at end of year +148 +163 +166 +Additional +paid-in capital: +Balance +at beginning of year +30,423 +37,684 +28,593 +Reclassification +of unearned compensation pursuant to the adoption of SFAS No. 123(R) +(825 +) +- +- +Exercise +of stock options +31 +12 +4,981 +Issuance +of stock awards, net of forfeitures +(1 +) +- +- +Stock +based compensation expense +1,516 +603 +871 +Retirement +of treasury shares +(31,150 +) +(7,876 +) +(4,156 +) +Excess +tax benefit of stock based compensation +70 +- +7,395 +Balance +at end of year +64 +30,423 +37,684 +Retained +earnings: +Balance +at beginning of year +158,504 +117,052 +83,824 +Cumulative +effect adjustment for the adoption of SAB 108, net of tax +(1,021 +) +- +- +Retirement +of treasury shares +(35,153 +) +- +- +Net +income +237,772 +41,452 +33,228 +Balance +at end of year +360,102 +158,504 +117,052 +Unamortized +stock award +Balance +at beginning of year +(825 +) +(882 +) +(15 +) +Issuance +of stock awards +- +(603 +) +(871 +) +Amortization +of stock awards +- +660 +4 +Reclassification +of unearned compensation pursuant to the adoption of SFAS No. 123(R) +825 +- +- +Balance +at end of year +- +(825 +) +(882 +) +Treasury +stock, at cost: +Balance +at beginning of year +- +- +- +Purchase +of treasury shares +(66,319 +) +(7,879 +) +(4,157 +) +Retirement +of treasury shares +66,319 +7,879 +4,157 +Non-employee +directors' deferred compensation plan +(170 +) +- +- +Balance +at end of year +(170 +) +- +- +Total +shareholders' equity +$ +360,144 +$ +188,265 +$ +154,020 +See +accompanying Notes to Consolidated Financial Statements. +F-5 +Index +PETROLEUM +DEVELOPMENT CORPORATION +Consolidated +Statements of Cash Flows +(in +thousands) +Year +Ended December 31, +2006 +2005 +2004 +Cash +flows from operating activities: +Net +income +$ +237,772 +$ +41,452 +$ +33,228 +Adjustments +to net income to reconcile to net cash provided by (used in) operating +activities: +Deferred +income taxes +86,431 +3,351 +9,887 +Depreciation, +depletion and amortization +33,735 +21,116 +18,156 +Impairment +of oil and gas properties +1,519 +- +- +Accretion +of asset retirement obligation +515 +465 +436 +Dry +hole costs +1,790 +11,115 +- +Gain +from sale of leaseholds +(328,000 +) +(7,669 +) +- +Loss +(gain) from sale of assets +9 +(207 +) +(32 +) +Expired +and abandoned leases +2,169 +48 +301 +Amortization +of stock award +1,516 +660 +4 +Unrealized +(gains) losses on derivative transactions +(7,620 +) +3,226 +535 +Changes +in current assets and liabilities: +Decrease +(increase) in restricted cash +982 +(836 +) +1,201 +Increase +in accounts receivable +(9,935 +) +(11,811 +) +(11,391 +) +Increase +in accounts receivable - affiliates +(194 +) +(5,319 +) +(1,482 +) +Decrease +(increase) in inventories +1,987 +(3,398 +) +357 +(Increase) +decrease in other current assets +(2,106 +) +3,482 +4,776 +(Decrease) +increase in production tax liability +(261 +) +3,317 +8,441 +Increase +in accounts payable and accrued expenses +13,010 +19,440 +11,648 +Increase +in accounts payable - affiliates +6,116 +112 +745 +Increase +(decrease) in advances for future drilling contracts +4,773 +7,502 +(7,961 +) +Increase +in federal and state income taxes payable +19,880 +8,473 +- +(Decrease) +increase in funds held for future distribution +(575 +) +18,505 +4,501 +Other +3,877 +(652 +) +(49 +) +Net +cash provided by operating activities +67,390 +112,372 +73,301 +Cash +flows from investing activities: +Capital +expenditures +(146,180 +) +(97,390 +) +(44,762 +) +Acquisition +of Unioil, net of cash acquired +(18,512 +) +- +- +Investment +in drilling partnerships +(7,151 +) +(7,160 +) +3,540 +Exploration +costs +(765 +) +(1,918 +) +(4,170 +) +(Increase) +decrease in restricted/designated cash +(192,416 +) +- +- +Proceeds +from sale of leases to partnerships +1,798 +2,829 +1,951 +Proceeds +from sale of leaseholds/assets +353,600 +9,597 +95 +Net +cash provided by (used in) investing activities +(9,626 +) +(94,042 +) +(43,346 +) +Cash +flows from financing activities: +Proceeds +from debt +302,000 +91,000 +84,000 +Proceeds +from short-term debt +20,000 +- +- +Retirement +of debt +(209,000 +) +(88,000 +) +(116,000 +) +Payment +of debt issuance costs +(160 +) +(423 +) +(233 +) +Proceeds +from issuance of stock +31 +12 +3,584 +Excess +tax benefits from stock-based compensation +70 +- +- +Purchase +of treasury stock +(66,489 +) +(7,879 +) +(2,749 +) +Net +cash provided by (used in) financing activities +46,452 +(5,290 +) +(31,398 +) +Net +increase (decrease) in cash and cash equivalents +104,216 +13,040 +(1,443 +) +Cash +and cash equivalents, beginning of period +90,110 +77,070 +78,513 +Cash +and cash equivalents, end of period +$ +194,326 +$ +90,110 +$ +77,070 +Supplemental +disclosures of cash flow information: +Cash +paid during the period for: +Income +taxes +$ +46,735 +$ +10,675 +$ +5,028 +Interest +$ +3,011 +$ +101 +$ +1,049 +See +accompanying Notes to Consolidated Financial Statements. +F-6 +Index +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS +NOTE +1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +General +Petroleum +Development Corporation (“PDC” or “the Company”) is an independent energy +company engaged primarily in the drilling and development, production and +marketing of natural gas and oil. Since it began oil and gas operations in +1969, +the Company has grown primarily through drilling and development activities, +the +acquisition of producing natural gas and oil wells and the expansion of its +natural gas marketing activities. As of December 31, 2006, the Company operates +approximately 3,100 wells located in the Appalachian Basin, Michigan, and the +Rocky Mountain Region. All of the Company's oil and gas wells are located in +West Virginia, Tennessee, Pennsylvania, Michigan, North Dakota, Colorado, Kansas +and Wyoming. The Company's operations are divided into four business segments: +drilling and development, natural gas marketing, oil and gas sales and well +operations and pipeline income. See Note 17. +Principles +of Consolidation +The +accompanying consolidated financial statements include the accounts of +PDC +and its +wholly owned subsidiaries, Riley Natural Gas (“RNG”), Unioil and PDC +Securities Incorporated. All material intercompany accounts and transactions +have been eliminated in consolidation. The Company accounts for its investment +in interests in oil and gas limited partnerships under the proportionate +consolidation method. Under this method, the Company’s consolidated financial +statements include its pro rata share of assets, liabilities and revenues and +expenses respectively of the limited partnerships in which it participates. +The +Company’s proportionate share of all significant transactions between the +Company and the limited partnerships is eliminated. +Cash +Equivalents +For +purposes of the statement of cash flows, the Company considers all highly liquid +debt instruments with original maturities of three months or less to be cash +equivalents. +Restricted +and Designated Cash +In +July +2006, the Company established a trust in the amount of $300 million with a +qualified intermediary in conjunction with its sale of undeveloped leaseholds +and corresponding “like-kind exchange” agreement. As of December 31, 2006, $300 +million remains in the trust, with $109 million reflected in cash and cash +equivalents as a current asset in the consolidated balance sheet and the +remaining $191.5 million reflected as designated cash - property acquisitions, +a +non-current asset. The $191.5 million represents the amounts paid in January +2007 for the acquisition of oil and gas properties qualifying for "like-kind +exchange" treatment. Interest earned on the trust account of $5.5 million is +reflected in cash and cash equivalents as a current asset, along with the $109 +million not utilized for "like-kind exchange" (“LKE”) purchases, will be +available to the Company for operating purposes in January 2007 and is no longer +subject to a LKE. See Note 15 and Note 16. +In +December 2006, the Company had paid a deposit of $0.5 million, reflected in +the +consolidated balance sheet as designated cash, a non-current asset, for the +acquisition of oil and gas properties subsequently closed in January +2007. +The +Company is required to maintain margin deposits with brokers for outstanding +derivative contracts. As of December 31, 2006 and 2005, cash in the amount +of +$0.5 million and $1.5 million, respectively, was on deposit and reflected in +the +consolidated balance sheets as restricted cash, a current asset. +The +Company is required by various government agencies or joint venture agreements +to maintain a bond or cash account for the plugging and abandonment of wells. +As +of December 31, 2006, the Company had bonds and cash accounts restricted for +plugging and abandonment of wells totaling $1.0 million, which are reflected +in +restricted/designated cash, a non-current asset. +Inventories +Materials, +supplies and commodity inventories are stated at the lower of average cost +or +market and removed at carrying value. +Oil +and Gas Properties +The +Company accounts for its oil and gas properties under the successful efforts +method of accounting. Costs of proved developed producing properties, successful +exploratory wells and development dry hole costs are depreciated or depleted +by +the unit-of-production method based on estimated proved developed producing +oil +and gas reserves. Property acquisition costs are depreciated or depleted on +the +unit-of-production method based on estimated proved oil and gas reserves. The +Company obtains new reserve reports from independent petroleum engineers +annually as of December 31 of each year. The Company adjusts oil and gas +reserves for any major acquisitions, new drilling and divestitures during the +year as needed. +F-7 +Index +PETROLEUM +DEVELOPMENT CORPORATION +Exploration +costs, including geological and geophysical expenses and delay rentals, are +charged to expense as incurred. Exploratory well drilling costs, including +the +cost of stratigraphic test wells, are initially capitalized but charged to +expense if the well is determined to be nonproductive. The status of each +in-progress well is reviewed quarterly to determine the proper accounting +treatment under the successful efforts method of accounting. Exploratory well +costs continue to be capitalized as long as the well has found a sufficient +quantity of reserves to justify its completion as a producing well and the +Company is making sufficient progress assessing its reserves and economic and +operating viability. If an in-progress exploratory well is found to be +unsuccessful (referred to as a dry hole) prior to the issuance of the Company’s +financial statements, the costs are expensed to exploration costs. If management +is unable to make a final determination about the productive status of a well +prior to issuance of the Company’s financial statements, the cost of the well is +classified as part of “Suspended Well Costs” until management has had sufficient +time to conduct additional completion or testing operations to evaluate the +pertinent geological and engineering data obtained. At the time when management +is able to make a final determination of a well’s productive status, the well is +removed from the suspended well status and the proper accounting treatment +is +recorded based on that determination. The determination of an exploratory well's +ability to produce is generally made within one year from the completion of +drilling activities. See Note 18. +The +acquisition costs of unproved properties are capitalized when incurred, until +such properties are transferred to proved properties or charged to expense +when +expired, impaired or amortized. Unproved oil and gas properties with +individually significant acquisition costs are periodically assessed, and any +impairment in value is charged to expense. The amount of impairment recognized +on unproved properties which are not individually significant is determined +by +amortizing the costs of such properties within appropriate fields based on +the +Company's historical experience, acquisition dates and average lease terms. +Amortization of remaining lease costs for all other insignificant properties +is +recorded over the average remaining lives of the leases. The valuation of +unproved properties is subjective and requires management of the Company to +make +estimates and assumptions which, with the passage of time, may prove to be +materially different from actual realizable values. +Upon +sale +or retirement of significant portions of or complete fields of depreciable +or +depletable property, the net book value thereof, less proceeds or salvage value, +is credited or charged to income. Upon sale of individual wells, the proceeds +are credited to property costs. +The +Company assesses impairment of capitalized costs of proved oil and gas +properties by comparing net capitalized costs to estimated undiscounted future +net cash flows on a field-by-field basis using estimated production based upon +prices at which management reasonably estimates such production to be sold. +These estimates of future production prices may differ from current market +prices of oil and gas. Any downward revisions to management's estimates of +future production or prices could result in an impairment of the Company's +oil +and gas properties in subsequent periods. If net capitalized costs exceed +undiscounted future net cash flows, the measurement of impairment is based +on +estimated fair value which would consider future discounted cash flows. In +2006, +the Company recognized an impairment loss on oil and gas properties of $1.5 +million, which is included in the statement of income as a component of +exploration cost. +Transportation +Equipment, Pipelines and Other Equipment +Transportation +equipment, pipelines and other equipment are carried at cost. Depreciation +is +provided principally on the straight-line method over useful lives of 3 to +17 +years. In accordance with Statement of Financial Accounting Standards (“SFAS”) +No. 144 , +Accounting for the Impairment or Disposal of Long-Lived Assets , +long-lived assets, such as property, plant and equipment, are reviewed for +impairment whenever events or changes in circumstances indicate that the +carrying amount of an asset may not be recoverable. Recoverability of assets +to +be held and used is measured by a comparison of the carrying amount of an asset +to estimated undiscounted future cash flows expected to be generated by the +asset. If the carrying amount of an asset exceeds its estimated future cash +flows, an impairment charge is recognized in the amount by which the carrying +amount of the asset exceeds the fair value of the asset. +Maintenance +and repairs are charged to expense as incurred. Major renewals and improvements +are capitalized. Upon the sale or other disposition of assets, the cost and +related accumulated depreciation, depletion and amortization are removed from +the accounts, the proceeds are applied thereto and any resulting gain or loss +is +reflected in income. +Capitalized +Interest +Interest +costs are capitalized as part of the historical cost of acquiring assets. Oil +and gas investments in unproved properties and major development projects, +on +which depreciation, depletion and amortization expense is not currently recorded +and on which exploration or development activities are in progress, qualify +for +capitalization of interest. Major construction projects also qualify for +interest capitalization until the asset is ready for service. Capitalized +interest is calculated by multiplying the Company's weighted-average interest +rate on its debt by the qualifying costs. Interest capitalized may not exceed +gross interest expense for the period. As the qualifying asset is moved to +the +depreciation, depletion and amortization pool, the related capitalized interest +is also transferred and is amortized over the useful life of the asset. Interest +costs of $1.6 million were capitalized during 2006. No interest costs were +capitalized during 2005 or 2004. +F-8 +Index +PETROLEUM +DEVELOPMENT CORPORATION +Goodwill +Goodwill +represents the excess of the aggregate purchase price over the fair value of +the +net assets acquired in a purchase business combination. The acquisition of +Unioil in December 2006 resulted in the recognition of goodwill in the amount +of +$6.8 million. The goodwill has been allocated to the oil and gas sales segment. +In accordance with SFAS No. 142, Goodwill +and Other Intangible Assets , +goodwill will be tested at least annually for impairment. See Note +2. +Buildings +Buildings +are carried at cost and depreciated on the straight-line method over estimated +useful lives of 30 years. +Asset +Retirement Obligations +The +Company accounts for asset retirement obligations by recording the fair value +of +its plugging and abandonment obligations when incurred, which is at the time +the +well is completely drilled. Upon initial recognition of an asset retirement +obligation, the Company increases the carrying amount of the long-lived asset +by +the same amount as the liability. Over time, the liabilities are accreted for +the change in their present value, through charges to oil and gas production +and +well operations costs. The initial capitalized costs are depleted over the +useful lives of the related assets, through charges to depreciation, depletion +and amortization. If the fair value of the estimated asset retirement obligation +changes, an adjustment is recorded to both the asset retirement obligation +and +the asset retirement cost. Revisions in estimated liabilities can result from +revisions of estimated inflation rates, escalating retirement costs and changes +in the estimated timing of settling asset retirement obligations. See Note +7 for +a reconciliation of asset retirement obligation activity. +Production +Tax Liability +Production +tax liability represents estimated taxes, primarily severance and property, +to +be paid to the states and counties in which the Company produces oil and gas. +The Company's share of these taxes is expensed to oil and gas production and +well operations cost. +Advances +for Future Drilling Contracts +Advances +for future drilling contracts represent deferred revenues arising from funds +being received from partnerships and other joint ventures for drilling +activities which have not been completed and accordingly have not yet been +recognized as revenue in accordance with the Company's revenue recognition +policies. +Retirement +of Treasury Shares +The +Company has historically retired all treasury share purchases, with the +exception of shares purchased in accordance with its non-employee deferred +compensation plan for non-employee directors, see Note 9. As treasury shares +are +retired, the Company charges any excess of cost over the par value entirely +to +additional paid-in-capital, to the extent the Company has amounts in +paid-in-capital, with any remaining excess cost being charged to retained +earnings. +Revenue +Recognition +The +Company's drilling segment recognizes revenue from drilling contracts with +sponsored drilling programs using the percentage of completion method based +upon +the percentage of contract costs incurred to date to the estimated total +contract costs for each contract. The Company utilizes this method since +reasonably dependable estimates of the total estimated costs can be made and +recognized revenues are subject to revisions as a contract progresses, the +term +of which can range from three to twelve months. In addition, the Company offers +its drilling services under two types of contractual arrangements, cost-plus +or +footage-based service contracts, which result in differing risk and reward +relationships, and hence, different revenue reporting policies pursuant to +Emerging Issues Task Force (“EITF”) No. 99-19, Reporting +Revenue Gross as a Principal versus Net as an Agent . +F-9 +Index +PETROLEUM +DEVELOPMENT CORPORATION +The +first +cost-plus drilling service arrangement was initially entered into in late 2005 +with drilling activity commencing in the first quarter of 2006. Although the +Company acts as a principal in the transaction and takes title to products +and +services acquired necessary for drilling, the Company acts as an agent, with +little risk of loss during the performance of the drilling activities. +Consistent with the provisions of EITF 99-19, the Company’s services provided +under the cost-plus drilling agreements are reported net of recovered costs. +The +Company entered into its second cost-plus drilling arrangement in September +2006 +and commenced drilling immediately. It is the Company’s intent that all future +drilling arrangements will be on a cost-plus basis. +Footage-based +contracts provide for the drilling, completion and equipping of wells at footage +rates and are generally completed within nine to twelve months after the +commencement of drilling. The Company provides geological, engineering, and +drilling supervision on the drilling and completion process and uses +subcontractors to perform drilling and completion services and accordingly +has +risk of loss in performing services under these arrangements. Accordingly, +the +Company reports revenue under these agreements gross of related expenses. +Anticipated losses, if any, on uncompleted contracts are recorded at the time +that the estimated total costs exceed the estimated total contract revenue. +At +December 31, 2006 and 2005, the loss contract reserve was $0.3 million and +$0.8 +million, respectively. +Natural +gas marketing is reported on the gross accounting method, based on the nature +of +the agreements between RNG, its suppliers and its customers. RNG, the Company’s +marketing subsidiary, purchases gas from many small producers and bundles the +gas together to sell in larger amounts to purchasers of natural gas for a price +advantage. RNG has latitude in establishing price and discretion in supplier +and +purchaser selection. Natural gas marketing revenues and expenses reflect the +full cost and revenue of those transactions because RNG takes title to the +gas +it purchases from the various producers and bears the risks and rewards of +that +ownership. Both the realized and unrealized gains or losses of the RNG commodity +based derivative transactions for natural gas marketing activities are included +in gas sales from marketing activities or cost of gas marketing activities, +as +applicable. +Sales +of +natural gas are recognized when natural gas has been delivered to a custody +transfer point, persuasive evidence of a sales arrangement exists, the rights +and responsibility of ownership pass to the purchaser upon delivery, collection +of revenue from the sale is reasonably assured and the sales price is fixed +or +determinable. Natural gas is sold by the Company under contracts with terms +ranging from one month to three years. Virtually all of the Company’s contract +pricing provisions are tied to a market index, with certain adjustments based +on, among other factors, whether a well delivers to a gathering or transmission +line, quality of natural gas and prevailing supply and demand conditions, so +that the price of the natural gas fluctuates to remain competitive with other +available natural gas supplies. As a result, the Company’s revenues from the +sale of natural gas will suffer if market prices decline and benefit if they +increase. The Company believes that the pricing provisions of its natural gas +contracts are customary in the industry. +The +Company currently uses the “net-back” method of accounting for transportation +arrangements of its natural gas sales. The Company sells gas at the wellhead +and +collects a price and recognizes revenues based on the wellhead sales price +since +transportation costs downstream of the wellhead are incurred by the customers +and reflected in the wellhead price. +Sales +of +oil are recognized when persuasive evidence of a sales arrangement exists, +the +oil is verified as produced and is delivered to a purchaser, collection of +revenue from the sale is reasonably assured and the sales price is determinable. +The Company is currently able to sell all the oil that it can produce under +existing sales contracts with petroleum refiners and marketers. The Company +does +not refine any of its oil production. The Company’s crude oil production is sold +to purchasers at or near the Company’s wells under short-term purchase contracts +at prices and in accordance with arrangements that are customary in the oil +industry. +Well +operations and pipeline income are recognized when persuasive evidence of an +arrangement exists, services have been rendered, collection of revenues is +reasonably assured and the sales price is fixed or determinable. The Company +is +paid a monthly operating fee for each well it operates for outside owners +including the limited partnerships sponsored by the Company. The fee covers +monthly operating and accounting costs, insurance and other recurring costs. +The +Company may also receive additional compensation for special non-recurring +activities, such as reworks and recompletions. +Income +Taxes +Income +taxes are accounted for under the asset and liability method. +Deferred +tax assets and liabilities are recognized for the future tax consequences +attributable to differences between the financial statement carrying amounts +of +existing assets and liabilities and their respective tax bases. Deferred tax +assets and liabilities are measured using enacted tax rates expected to apply +to +taxable income in the years in which those temporary differences are expected +to +be recovered or settled. The effect on deferred tax assets and liabilities +of a +change in tax rates is recognized in income in the period that includes the +enactment date. +F-10 +Index +PETROLEUM +DEVELOPMENT CORPORATION +Derivative +Financial Instruments +The +Company accounts for derivative financial instruments in accordance with SFAS +No. 133, Accounting +for Derivative Instruments and Certain Hedging Activities , +as +amended. +During +2006, 2005 and 2004, none of the Company's derivative instruments qualified +for +use of hedge accounting under the terms of SFAS No. 133. Accordingly, the +Company recognizes all derivative instruments as either assets or liabilities +on +the consolidated balance sheets at fair value and changes in the derivatives' +fair values are recorded in the consolidated statements of income in oil and +gas +price risk management, net for the Company’s oil and gas commodities +(derivatives related to the Company's production only), in gas sales from +marketing activities for RNG’s gas sales, in cost of gas marketing activities +for RNG’s gas purchases and in interest expense for the Company’s interest rate +swap (2004 only), as applicable. See Note 14. +In +the +accompanying consolidated balance sheets, the Company records the fair value +of +derivatives entered into on behalf of the affiliated partnerships and records +an +offsetting receivable from or payable to the partnerships. See Note +11. +Stock-Based +Compensation +Effective +January 1, 2006, the Company adopted Statement SFAS No. 123(R), Share-Based +Payment (revised 2004) . +The +Company elected the modified prospective method of adoption, and accordingly, +prior period financial statements have not been restated. Pursuant to SFAS +No. +123(R) the Company is required to recognize in its financial statements, based +on fair value, compensation expense for all unvested stock options and other +equity-based awards as of January 1, 2006. For all unvested options outstanding +as of January 1, 2006 the previously measured but unrecognized compensation +expense, based on the fair value at the original grant date, will be recognized +in the financial statements over the remaining requisite service period for +each +separately vesting portion. For equity-based compensation awards granted or +modified subsequent to January 1, 2006, compensation expense, based on the +fair +value on the date of grant or modification, will be recognized in the financial +statements on a straight-line basis over the vesting period for the entire +award. To the extent compensation cost relates to employees directly involved +in +oil and natural gas acquisition, exploration and development activities, such +amounts are capitalized to properties and equipment. Amounts not capitalized +to +properties and equipment are recognized in the appropriate cost and expense +line +item in the statement of income. For the year ended December 31, 2006, the +Company recognized stock-based compensation expense of $0.1 million and $1.4 +million related to stock option and restricted stock awards, respectively. +Compensation capitalized as part of properties and equipment was immaterial +in +2006. +For +periods prior to the adoption of SFAS No. 123(R), the Company accounted for +its +share-based compensation awards using the intrinsic value based method as +prescribed by Accounting Principles Board Opinion ("APB") No. 25, Accounting +for Stock Issued to Employees , +and +related interpretations. Under the intrinsic value based method, compensation +expense for option awards was recorded on the date of grant only if the +then-current market price of the underlying stock exceeded the exercise price. +The following table illustrates the effect on net income and earnings per share +had the Company applied the fair value recognition provisions of SFAS No. +123(R), as amended, to stock-based employee compensation during 2005 and 2004 +(in thousands, except per share data): +Year +ended +December +31, +2005 +2004 +Net +income, as reported: +$ +41,452 +$ +33,228 +Stock-based +compensation expense included in reported net income, net of +tax +414 +2 +Total +stock-based compensation expense determined under fair value +method +(509 +) +(21 +) +Pro +forma net income +$ +41,357 +$ +33,209 +Earnings +per share: +Basic +earnings per share, as reported and pro forma +$ +2.53 +$ +2.05 +Diluted +earnings per share, as reported and pro forma +$ +2.52 +$ +2.00 +Earnings +Per Share +The +Company's basic earnings per share ("EPS") amounts have been computed based +on +the average number of shares of common stock outstanding for the period. Diluted +EPS amounts include the effect of the Company's outstanding stock options, +unamortized portion of restricted stock and shares held pursuant to the +Company's non-employee director deferred compensation plan using the treasury +stock method if including such potential shares of common stock is dilutive. +See +Note 10. +F-11 +Index +PETROLEUM +DEVELOPMENT CORPORATION +Use +of Estimates +The +preparation of the consolidated financial statements in accordance with +generally accepted accounting principles in the United States of America +requires management of the Company to make estimates and assumptions that affect +the amounts reported in the consolidated financial statements and accompanying +notes. Actual results could differ from those estimates. Estimates which are +particularly significant to the consolidated financial statements include +estimates of oil and gas reserves, future cash flows from oil and gas properties +valuation of derivative instruments and valuation of deferred income tax +assets. +Fair +Value of Financial Instruments +The +carrying values of the Company's receivables, payables and debt obligations +approximate fair value as of December 31, 2006 and 2005, due to the short-term +maturity of these instruments. +Reclassifications +Reclassifications +to conform to current year presentation +Certain +prior year amounts were reclassified to conform to the current year +presentation. The reclassifications had no impact on reported net earnings, +earnings per share, shareholders’ equity or cash flows from operating +activities. +· +Oil +and gas price risk management losses of $9.4 million and $3.1 million +for +2005 and 2004, respectively, have been reclassified from non-operating +losses to a component of (and an offset to) +revenues. +· +As +of December 31, 2005, investment in drilling partnerships, a long-term +asset, in the amount of $11.2 million has been reclassified from +properties and equipment, net, also a long-term asset, to other long-term +assets. +Reclassifications +to correct prior year amounts +Certain +prior year amounts were reclassified to correct prior year amounts. These +correcting reclassifications were immaterial and had no impact on reported +net +earnings, earnings per share, shareholders' equity or cash flows from operating +activities. +· +Accretion +expense related to the Company’s asset retirement obligation in the amount +of $0.5 million and $0.4 million, respectively for the years 2005 +and +2004, has been reclassified from interest expense, a non-operating +expense, to oil and gas production and well operations cost, a component +of income from operations. +· +Interest +income in the amount of $0.9 million, and $0.2 million, respectively +for +the years 2005 and 2004, has been reclassified from other income, +a +component of revenues, to interest income, a non-operating income +item. +· +Gain +on sale of leaseholds in the amount of $7.7 million for the year +2005 has +been reclassified from other income to gain on sale of leaseholds, +with no +impact on income from operations. +· +As +of December 31, 2005, production taxes relating to accrued oil and +gas +revenues in the amount of $3.8 million previously reported as a reduction +of accounts receivable have been reclassified to production tax liability. +· +As +of December 31, 2005, production receivables in the amount of $1.8 +million +were reclassified from accounts receivable to accounts receivable +- +affiliates. +· +As +of December 31, 2005, the Company did not appropriately eliminate +a +portion of its intercompany accounts receivable and accounts payable; +accordingly, the Company reduced it accounts receivable and accounts +payable balances by $8.5 million, resulting in the elimination of +all +material intercompany transactions. +· +In +connection with the production tax withheld adjustment discussed +below +under the caption Recently Adopted Accounting Standards, $22.1 million +has +been reclassified from production tax liability to other liability +line +items as of December 31, 2005. Of this amount, $9.1 million has been +reclassified to other long-term liability to reflect production tax +obligations as of December 31, 2005, that are not payable until 2007 +and +$13 million, representing amounts due to drilling partnership limited +partners as a result of over withholding of estimated production +taxes by +the Company, has been reclassified to funds held for +distribution. +Recent +Accounting Standards +Recently +Adopted Accounting Standards +In +December 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS No. +123(R), Share-Based +Payment . +In +March 2005, the Securities and Exchange Commission (“SEC”) issued Staff +Accounting Bulletin (“SAB”) No. 107, Share-Based +Payment , +regarding the interaction between SFAS No. 123(R) and certain SEC rules and +regulations. Effective January 1, 2006, the Company adopted SFAS No. 123(R). +The +Company elected to use the modified prospective method for adoption, which +requires compensation expense to be recognized in the statement of income for +all unvested stock options and other equity-based compensation beginning in +the +first quarter of adoption. Prior to the adoption of SFAS No. 123(R), the Company +followed the intrinsic value method in accordance with APB No. 25 (as amended) +to account for employee stock-based compensation. The adoption of SFAS No. +123(R) required the unamortized stock award recorded under APB No. 25 related +to +stock-based compensation awards as of January 1, 2006, in the amount of $0.8 +million to be eliminated against additional paid-in-capital. See Stock-Based +Compensation +policy +above and Note 8 for further discussion of the Company's accounting for +share-based compensation awards. +F-12 +Index +PETROLEUM +DEVELOPMENT CORPORATION +In +June +2005, the FASB issued SFAS No. 154, Accounting +Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB +Statement No. 3 , +which +replaces APB No. 20, Accounting +Changes , +and +SFAS No. 3, Reporting +Accounting Changes in Interim Financial Statements , +and +changes the requirements for the accounting for and reporting of a change in +accounting principle. SFAS No. 154 requires retrospective application for +voluntary changes in accounting principle unless it is impracticable to do +so, +and it applies to all voluntary changes in accounting principle in addition +to +changes required by an accounting pronouncement in the unusual instance that +the +pronouncement does not include specific transition provisions. SFAS No. 154 +became effective for accounting changes and corrections of errors made in fiscal +years beginning after December 15, 2005. The January 1, 2006, adoption of SFAS +No. 154 did not have a material impact on the Company's consolidated financial +statements. +In +September 2006, the SEC issued SAB No. 108, Considering +the Effects of Prior Year Misstatements when Quantifying Misstatements in +Current Year Financial Statements . +SAB No. +108 provides guidance on how the effects of prior year misstatements should +be +considered in quantifying misstatements in the current year financial +statements. SAB No. 108 requires registrants to quantify misstatements using +both the income statement (“rollover”) and balance sheet (“iron curtain”) +approach and evaluate whether either approach results in a misstatement that, +when all relevant quantitative and qualitative factors are considered, is +material. Historically, the Company evaluated uncorrected misstatements using +the “rollover” method which resulted in an accumulation of quantitatively and +qualitatively immaterial misstatements to the Company’s consolidated financial +statements. SAB No. 108 provides for a one time transitional adjustment to +retained earnings for errors which were not deemed material to prior year +financial statements, but which are material under guidance of SAB No. 108. +The +Company adopted SAB No. 108 during the fourth quarter of 2006 and recorded +the +effect of the following identified items as a cumulative effect adjustment +to +retained earnings effective January 1, 2006 for periods through December 31, +2005 (in thousands): +Increase/ +(Decrease) +Pre-tax +adjustments: +Employee +benefits payable (1) +$ +(470 +) +Accrued +performance supplement (2) +(464 +) +Deferred +compensation retirement liability (3) +(961 +) +Accounting +for oil inventory (4) +(1,172 +) +Fair +value of derivatives (5) +(487 +) +Oil +and gas properties, net (6) +(1,402 +) +Funds +held for distribution (7) +(778 +) +Funds +held pending a division order (8) +377 +Interest +income recognition (9) +136 +Accrued +gas marketing (10) +(15 +) +Accrued +oil and gas production costs (11) +878 +Unclaimed +property liabilities (12) +(124 +) +Production +taxes withheld (13) +5,003 +Accrued +franchise tax (14) +(52 +) +Prepaid +well costs (15) +(274 +) +Accrued +production taxes (16) +(1,445 +) +(1,250 +) +Tax +effect (17) +229 +Decrease +to shareholders' equity as of January 1, 2006 +$ +(1,021 +) +____________________ +(1) +Employee +benefits payable - The Company understated employee benefits payable +as a +result of errors in its calculation of certain 401k plan provisions. +These +errors originated in 1997 and continued through December 31, 2005. +(2) +Oil +and gas partnership performance liability - The Company understated +oil +and gas partnership performance liability as a result of recognizing +its +cost on a cash basis instead of accruing the cost in the period in +which +the cost was incurred. This misstatement originated in 1996 and continued +through June 30, 2006. +F-13 +Index +PETROLEUM +DEVELOPMENT CORPORATION +(3) +Deferred +compensation retirement liabilities - The Company understated its +deferred +compensation and medical benefits liability as a result of errors +in the +calculation of the escalation provision in the deferred compensation +plan +and understated its post retirement medical benefits liability as +a result +of recognizing its cost on a cash basis for certain employment contracts. +This misstatement originated in 2000 and continued through September +30, +2006. +(4) +Accounting +for oil inventory - The Company overstated accounts receivable and +understated its inventory as a result of recognizing oil revenues +when +production was delivered to Company owned storage tanks. This misstatement +originated in 1999 and continued through September 30, +2006. +(5) +Fair +value of derivatives - The Company overstated the fair value of its +purchase of certain put option contracts as a result of errors in +its +premium amortization calculation. This misstatement originated in +2005 and +continued through September 30, +2006. +(6) +Oil +and gas properties, net – The Company capitalized certain overhead cost +which, under the successful efforts method of accounting for oil +and gas +properties, should have been expensed in the period +incurred. This misstatement originated in 2001 and continued +through September 30, +2006. +(7) +Funds +held for distribution liability - The Company understated its funds +held +for distribution liability as a result of errors in the processing +of +certain transactions and un-reconciled differences between certain +control +and subsidiary accounts. This misstatement originated in years prior +to +2002 and continued through September 30, +2006. +(8) +Funds +held pending a division order - The Company overstated its funds +held for +distribution liability and understated its portion of oil and gas +revenue +and corresponding production taxes as a result of not accruing oil +and gas +production proceeds that had been received but held for distribution +due +to a lack of a division order. This misstatement originated in years +prior +to 2002 and continued through September 30, +2006. +(9) +Accrued +interest income - The Company understated accounts receivable affiliates +as a result of recognizing the Company’s portion of affiliate interest +income on a cash basis. This misstatement originated in 2005 and +continued +through September 30, 2006. +(10) +Gas +marketing liabilities - The Company understated gas marketing liabilities +as a result of errors in its calculation of the timing of services +provided. This misstatement originated in 2004 and continued through +September 30, 2006. +(11) +Accrued +oil and gas production costs - The Company overstated production +tax +liability, a current liability, by over accruing fuel usage costs. +This +misstatement originated in 2003 and continued through September 30, +2006. +(12) +Unclaimed +property liability - The Company understated accrued expenses as +a result +of errors in its calculation of unclaimed property liability. This +misstatement originated in 1995 and continued through September 30, +2006. +(13) +Production +taxes withheld - The Company over-withheld production tax obligations +related to oil and gas production proceeds distributed by the Company +in +years prior to 2002 to September 30, 2006. As a result, the Company +overstated its oil and gas production and well operations cost and, +in its +capacity as well operator, the Company over-withheld from the revenue +distributions made to drilling partnership limited partners (see +reclassification above). The Company has accrued and will distribute +foregone interest to the limited partners and has also accrued estimated +penalties and interest that are likely to result from this item. +This +misstatement originated in 2001 and continued through September 30, +2006. +(14) +Franchise +tax liabilities - The Company understated franchise tax liabilities +as a +result of recognizing certain of its liabilities on a cash basis. +This +misstatement originated in 2005 and continued through September 30, +2006. +(15) +Prepaid +well costs - The Company overstated prepaid well costs as a result +of +errors in accounting for the expiration and abandonment of well drill +sites. This misstatement originated in 2004 and continued through +September 30, 2006. +(16) +Accrued +production taxes - The Company understated production tax liabilities +as a +result of not accruing penalty and interest associated with the untimely +payment of production taxes in certain jurisdictions and not correcting +other unreconciled amounts included in production tax liabilities. +This +misstatement originated in 2001 and continued through September 30, +2006. +(17) +Tax +effect - As a result of the errors discussed in items 13 and 16 above, +and +the fact that certain property and severance taxes were remitted +late, the +Company expects that it will incur non-deductible +penalties. These penalties are not deductible for tax purposes +and consist of $0.3 million for the late payment and/or late filing +of +severance taxes, as well as, income tax penalties of $0.4 for the +late +payment of the limited partners’ income taxes that resulted from the +overstatement of production costs. After adjusting for the +impact of these non-deductible items, the Company recorded a tax +provision +for the net effect of items 1 through 16 at the rate of +38.8%. +See +Note +19, where the effect of the above entries on 2006 quarterly financial +statements, which was not material, is reflected in revised financial data +for +those periods. +F-14 +Index +PETROLEUM +DEVELOPMENT CORPORATION +Recently +Issued Accounting Standards +In +June +2006, the FASB issued EITF No. 06-3, How +Taxes Collected from Customers and Remitted to Governmental Authorities Should +be Presented in the Income Statement (That Is, Gross versus Net +Presentation) . +EITF +06-3 addresses the income statement presentation of any tax collected from +customers and remitted to a government authority and concludes that the +presentation of taxes on either a gross basis or a net basis is an accounting +policy decision that should be disclosed pursuant to APB No. 22, Disclosures +of Accounting Policies . +For +taxes that are reported on a gross basis (included in revenues and costs), +EITF +06-3 requires disclosure of the amounts of those taxes in interim and annual +financial statements, if those amounts are significant. EITF 06-3 is effective +for interim and annual reporting periods beginning after December 15, 2006. +The +adoption of the standard, effective January 1, 2007, is not expected to have +a +significant impact on the consolidated financial statements. +In +July +2006, the FASB issued FASB Interpretation (“FIN”) No. 48, Accounting +for Uncertainty in Income Taxes - an Interpretation of FASB Statement +109 , +which +prescribes a comprehensive model for accounting for uncertainty in tax +positions. FIN No. 48 provides that the tax effects from an uncertain tax +position can be recognized in the financial statements, only if the position +is +more likely than not of being sustained on audit by the Internal Revenue +Service, based on the technical merits of the position. The provisions of FIN +48 +will become effective for the Company as of January 1, 2007. The cumulative +effect, if any, of applying the provisions of FIN 48 will be accounted for +as an +adjustment to retained earnings in the first quarter of 2007. The Company is +currently evaluating the impact of adopting FIN 48 on its consolidated financial +statements. +In +September 2006, the FASB issued SFAS No. 157, Accounting +for Fair Value Measurements . +SFAS +No. 157 defines fair value, establishes a framework for measuring fair value +within generally accepted accounting principles and expands required disclosure +about fair value measurements. SFAS No. 157 does not expand the use of fair +value in any new circumstances. The provisions of SFAS No. 157 are effective +for +financial statements issued for fiscal years beginning after November 15, 2007, +and interim periods within those fiscal years. The Company does not expect +the +new standard to have any material impact on its consolidated financial +statements. +In +February 2007, the FASB issued SFAS No. 159, The +Fair Value Option for Financial Assets and Financial +Liabilities . +SFAS +No. 159 permits entities to choose to measure many financial instruments and +certain other items at fair value that are not currently required to be measured +at fair value. The objective is to improve financial reporting by providing +entities with the opportunity to mitigate volatility in reported earnings caused +by measuring related assets and liabilities differently without having to apply +complex hedge accounting provisions. SFAS No. 159 establishes presentation +and +disclosure requirements designed to facilitate comparisons between entities +that +choose different measurement attributes for similar types of assets and +liabilities. The statement will be effective as of the beginning of an entity's +first fiscal year beginning after November 15, 2007. The Company is evaluating +the impact of the adoption of SFAS No. 159 on the financial +statements. +NOTE +2 - ACQUISITION OF UNIOIL +On +December 6, 2006, the Company completed its cash tender offer and purchased +approximately 95.5% or 9,112,750 shares of the outstanding common stock of +Unioil, an independent energy company with properties in northern Colorado +and +southern Wyoming. The acquisition of more than 90% of the outstanding shares +of +common stock allowed the Company to effect a short-form merger of Unioil and +a +wholly owned subsidiary of the Company, resulting in the acquisition of the +remaining 428,719 shares of Unioil. Each share of Unioil common stock not +tendered through the offer was converted into the right to receive $1.91 in +cash, the same consideration paid for shares in the tender offer. The total +price paid for 100% of Unioil’s outstanding common stock was $18.6 million, +including $0.4 million in direct costs of the acquisition. The acquisition +was +accounted for in accordance with SFAS No. 141, Business +Combinations . +F-15 +Index +PETROLEUM +DEVELOPMENT CORPORATION +The +total +acquisition cost has been initially allocated to the assets purchased and the +liabilities assumed based upon the fair values on the date of acquisition as +follows (in thousands): +Cash +consideration paid +$ +18,224 +Plus: +Direct costs of acquisition +382 +Total +acquisition cost +$ +18,606 +Current +assets acquired +$ +660 +Properties +and equipment acquired +19,056 +Goodwill +6,783 +Deferred +tax liability +(6,783 +) +Other +liabilities assumed +(1,110 +) +Total +acquisition cost +$ +18,606 +The +assessment of the fair values of oil and gas properties acquired was based +primarily on projections of expected future net cash flows, discounted to +present value. The preliminary acquisition cost allocation includes $6.8 million +in goodwill. The goodwill is neither deductible for tax purposes, nor +amortizable for book purposes pursuant to SFAS No. 141. Goodwill will be tested +for impairment at least annually. The purchase price allocation is preliminary +subject to finalizing fair value appraisals and completing evaluations of proved +and unproved oil and gas properties. These amounts are subject to change as +additional information becomes available and is assessed by the Company. +The +results of Unioil's operations have been included in the consolidated financial +statements from the date of acquisition, December 6, 2006. The pro forma effect +of the inclusion of the results of Unioil's operations in the Company's +consolidated statements of income was not material. +NOTE +3 - ACCOUNTS RECEIVABLE +Accounts +receivable are reviewed to determine which are doubtful of collection. In making +the determination of the appropriated allowance for doubtful accounts, +management considers the Company's historical write-offs, relationships and +overall credit worthiness of its customers, additional consideration is given +to +well production data for receivables related to well operations. The allowance +as reflected in the accompanying balance sheets is the Company's best estimate +of the amount of probable credit losses in the Company's existing accounts +receivable. +The +allowance for doubtful accounts receivable, net as of December 31, 2006 and +2005, was $0.2 million and $0.2 million, respectively. In addition, included +in +other assets, a non-current asset, based on their terms, are accounts receivable +as of December 31, 2006 and 2005, in the amounts of $0.2 million and $0.4 +million, net of an allowance for doubtful accounts of $0.2 million and $0.2 +million, respectively. +The +nature of the independent oil and gas industry involves a dependence on outside +investor drilling capital and involves a concentration of oil and gas sales +to a +few customers. The Company sells oil and natural gas to various public +utilities, gas marketers and industrial customers. The following table +identifies significant customers as a percent of total oil and gas sales and +total revenues for each of the years presented. +Oil +and Gas Sales +Total +Revenue +Year +Ended December 31, +Year +Ended December 31, +2006 +2005 +2004 +2006 +2005 +2004 +Customer +A +14.9 +% +10.5 +% +7.6 +% +12.9 +% +6.9 +% +4.3 +% +B +10.6 +% +10.6 +% +9.6 +% +9.1 +% +6.9 +% +5.4 +% +C +10.3 +% +15.2 +% +11.1 +% +8.9 +% +9.9 +% +6.3 +% +D +9.4 +% +12.9 +% +13.8 +% +8.1 +% +8.4 +% +7.8 +% +F-16 +Index +PETROLEUM +DEVELOPMENT CORPORATION +NOTE +4 - PROPERTIES AND EQUIPMENT (in thousands) +December +31, +2006 +2005 +Properties +and Equipment: +Oil +and gas properties (successful efforts method of +accounting) +$ +500,506 +$ +354,147 +Pipelines +12,673 +11,512 +Transportation +and other equipment +7,870 +6,383 +Land +and buildings +11,620 +3,981 +Construction +in progress +4,801 +1,509 +537,470 +377,532 +Less +accumulated depreciation, depletion and amortization +143,253 +111,606 +Properties +and equipment, net of accumulated depreciation,depletion and +amortization +$ +394,217 +$ +265,926 +NOTE +5 - LONG-TERM DEBT +The +Company has a credit facility with JPMorgan Chase Bank, N.A. ("JPMorgan") and +BNP Paribas of $200 million subject to and secured by required levels of oil +and +gas reserves. The current borrowing base, based upon current oil and gas +reserves, is $135 million. Effective September 18, 2006, the Company elected +to +increase the amount it had activated by $55 million, from $80 million to $135 +million. The Company is required to pay a commitment fee of 0.25% to 0.375% +per +annum on the unused portion of the activated credit facility. Interest accrues +at an Alternative Base Rate ("ABR") or adjusted LIBOR at the discretion of +the +Company. The ABR is the greater of JPMorgan's prime rate, an adjusted secondary +market rate for a three-month certificate of deposit plus 1% or the federal +funds effective rate plus 0.5%. ABR borrowings are assessed an additional margin +spread of 0% to 0.375% and adjusted LIBOR borrowings are assessed an additional +margin spread of 1.125% to 1.875%. The margin spread charges are based upon +the +outstanding balance under the facility. No principal payments are required +until +the credit agreement expires on November 4, 2010. +On +December 19, 2006, the Company executed pursuant to its credit facility an +overline note in the amount of $20 million to be repaid on January 31, 2007. +Interest on the overline note accrued at a per annum rate equal to the alternate +base rate plus 0.80% until December 22, 2006, at which time the rate converted +to a Eurodollar borrowing for a one month period and at a per annum rate equal +to an adjusted LIBOR rate plus 2.30%. The overline note was paid in full in +accordance with its terms in January, 2007. +As +of +December 31, 2006 and 2005, the outstanding balance under the facility, +including the overline note, was $137 million and $24 million, respectively. +Any +amounts outstanding under the credit facility are secured by substantially +all +properties of the Company. At December 31, 2006, an outstanding balance of +$67 +million was subject to a prime interest rate of 8.375%; the overline note in +the +amount of $20 million was subject to an interest rate of 9.05% and the remaining +outstanding balance of $50 million was subject to a LIBOR rate of 7.0%. The +credit agreement requires, among other things, the existence of satisfactory +levels of natural gas reserves and the maintenance of certain working capital +and tangible net worth ratios. As of the filing of this annual report on Form +10-K, the Company was in compliance with all covenants in the credit agreement +except for timely filing of this December 31, 2006, Form 10-K. During March +2007, due to various reporting and processing delays, the Company requested +a +waiver related to the Security assignment provisions of its credit facility. +During March 2007, a waiver was granted and the corresponding Borrowing Base +was +reduced to $100 million from $135 million. Along with the previously discussed +waiver, the Company requested and was granted a waiver related to the delay +in +the delivery of its consolidated financial statement for the year ended December +31, 2006, and three months ended March 31, 2007, until May 31, 2007, and June +30, 2007, respectively. +NOTE +6 - INCOME TAXES +The +Company had a substantial taxable gain from the sale of undeveloped oil and +gas +properties (see Note 15). The Company has chosen to use the favorable deferral +aspects of the Internal Revenue Code ("IRC") Section 1031, LKE to defer the +tax +liability on a portion of the gain utilized by purchasing replacement properties +(see Note 16). Accordingly, the Company’s current and deferred provision for +income taxes increased substantially in 2006 and consisted of the following +(in +thousands): +F-17 +Index +PETROLEUM +DEVELOPMENT CORPORATION +2006 +2005 +2004 +Current: +Federal +$ +54,467 +$ +17,894 +$ +8,650 +State +8,739 +3,431 +1,713 +Total +current income taxes +63,206 +21,325 +10,363 +Deferred: +Federal +74,003 +2,834 +8,430 +State +12,428 +517 +1,457 +Total +deferred income taxes +86,431 +3,351 +9,887 +Total +income taxes +$ +149,637 +$ +24,676 +$ +20,250 +Income +tax expense differed from the amounts computed by applying the U.S. federal +income tax rate of 35% (in thousands). +2006 +2005 +2004 +Computed +"expected" tax +$ +135,594 +$ +23,145 +$ +18,717 +State +income tax +13,744 +2,566 +2,061 +Percentage +depletion +(545 +) +(771 +) +(649 +) +Domestic +production activities deduction +- +(399 +) +- +Other +844 +135 +121 +$ +149,637 +$ +24,676 +$ +20,250 +The +Company did not have any net income from Qualified Production Activities +("QPAI"), due to its tax filing election to expense the majority of its +intangible drilling costs incurred in 2006. Accordingly, the domestic production +activities deduction, which is statutorily equal to three percent of QPAI, +was +zero for 2006. +The +Internal Revenue Service (“IRS”) has proposed certain adjustments to the +Company’s federal tax returns for 2003 and 2004. The Company has entered into an +agreement with the IRS concerning some of the proposed adjustments and has +reached an informal understanding with the IRS regarding the others. The +additional federal and state tax expense, including interest, totals +approximately $0.6 million, which was accrued for primarily in prior periods. +In +addition, the proposed adjustments also result in the current taxation in 2003 +and 2004 of items previously deferred. Accordingly, as of December 31, 2006, +the +Company has accrued a current federal and state tax liability of $4.6 million, +including applicable interest, which will be due upon completion of the IRS +audit. +F-18 +Index +PETROLEUM +DEVELOPMENT CORPORATION +The +tax +effects of temporary differences that give rise to significant portions of +the +deferred tax assets and deferred tax liabilities at December 31, 2006 and 2005, +are presented below (in thousands). +2006 +2005 +Deferred +tax assets: +Allowance +for doubtful accounts +$ +161 +$ +159 +Drilling +notes +46 +71 +Deferred +revenue related to cash withheld for future plugging cost +929 +824 +Deferred +compensation +2,105 +904 +Asset +retirement obligations +4,428 +3,242 +Derivatives +- +1,562 +Employee +benefits +798 +- +Other +- +8 +Total +gross deferred tax assets +8,467 +6,770 +Less +valuation allowance +- +- +Deferred +tax assets +8,467 +6,770 +Deferred +tax liabilities: +Properties +and equipment, principally due to differences in depreciation and +amortization +(58,790 +) +(31,811 +) +Like +kind exchange - deferred gain +(63,783 +) +- +Unrealized +gains - derivatives +(1,203 +) +- +Total +gross deferred tax liabilities +(123,776 +) +(31,811 +) +Net +deferred tax liability +$ +(115,309 +) +$ +(25,041 +) +Classification +in the Consolidated Balance Sheets: +Net +current deferred tax assets* +$ +1,084 +$ +1,848 +Net +non-current deferred tax liability +(116,393 +) +(26,889 +) +Net +deferred tax liability +$ +(115,309 +) +$ +(25,041 +) +*included +in other current assets +As +noted +above, deferred tax liabilities increased substantially in 2006 due to the +Company’s utilization of the like-kind exchange tax deferral for a portion of +the taxable gain on the undeveloped land sale (Note 15). The deferred tax +liability on property and equipment increased primarily as a result of the +election to expense, for current tax purposes, approximately $55 million of +intangible drilling costs. In addition, approximately $6.8 million of the +increase in the deferred liability is due to the Unioil acquisition. +In +assessing whether a valuation allowance for the deferred tax assets should +be +recorded, management considers whether it is more likely than not that some +portion or all of the deferred tax assets will not be realized. The ultimate +realization of deferred tax assets is dependent upon the generation of future +taxable income during the periods in which those temporary differences become +deductible. Based upon the level of historical taxable income and projections +for future taxable income over the periods in which the deferred tax assets +are +deductible, management believes it is more likely than not that the Company +will +realize the benefits of these deductible differences. The amount of the deferred +tax asset considered realizable, however, could be reduced in the near term +if +estimates of future taxable income during the carryforward period are +reduced. +F-19 +Index +PETROLEUM +DEVELOPMENT CORPORATION +NOTE +7 - ASSET RETIREMENT OBLIGATIONS +Changes +in carrying amounts of the asset retirement obligations associated with the +Company’s working interest in oil and gas properties are as follows (in +thousands): +2006 +2005 +Balance +at beginning of year +$ +8,333 +$ +7,998 +Obligations +assumed with development activities and acquisitions +1,264 +302 +Obligations +discharged with disposed properties and asset retirements +(115 +) +(446 +) +Accretion +expense +515 +465 +Revisions +to estimated cash flows +1,969 +14 +Balance +at end of year +$ +11,966 +$ +8,333 +If +the +fair value of the estimated asset retirement obligation changes, an adjustment +is recorded to both the asset retirement obligation and the asset retirement +cost. Approximately $50,000 of the asset retirement obligations were classified +as short-term and included in other accrued expenses as of December 31, 2006 +and +2005. +NOTE +8 - COMMON STOCK +Stock-Based +Compensation Plans +Approved +by the shareholders in June 2004, the Company maintains a long-term equity +compensation plan for officers and certain key employees of the Company (the +"2004 Plan"). In accordance with the plan, awards may be issued in the form +of +stock options, stock appreciation rights, restricted stock or performance +shares. A total of 750,000 new shares of common stock have been reserved for +issuance. Awards pursuant to the plan vest over periods set at the discretion +of +the Compensation Committee of the Company’s Board of Directors (“Board”) and +have a maximum exercisable period of ten years. As of December 31, 2006, 565,702 +common shares remain available for future awards. +Approved +by the shareholders in June 2005, the Company also maintains a restricted stock +plan for non-employee directors. A total of 40,000 new shares of common stock +have been reserved for issuance under the plan. Awards pursuant to the plan +are +subject to restrictions ending on the earliest of various retirement or +termination dates, including certain provisions for change in control. During +2006 and 2005, 6,551 and 6,895 common shares, respectively, were awarded in +accordance with the plan. Compensation expense for each of the years ended +December 31, 2006 and 2005, related to these restricted shares was $0.1 million. +As of December 31, 2006, 26,554 common shares remain available for future +awards. +In +August +1999, the shareholders approved the 1999 Incentive Stock Option and +Non-Qualified Stock Option Plan. A total of 500,000 shares of the Company’s +common stock were reserved for issuance upon the exercise of stock options. +All +shares authorized to be awarded pursuant to this plan were awarded in years +prior to 2002. At December 31, 2006, options for 49,000 common shares remain +outstanding and exercisable through 2011, at which time the options will +expire. +Stock +Option Awards. +The +Company granted stock options in previous years under several stock compensation +plans. Outstanding options expire ten years from the date of grant and become +exercisable ratably over a four year period. The Company did not grant any +stock +option awards in 2005. The fair values of stock options granted during the +years +ended December 31, 2006 and 2004, were estimated at the date of grant using +a +Black-Scholes option-pricing model assuming no dividends and the following +weighted average assumptions: +For +the year ended December 31, +2006 +2004 +Expected +Volatility +40.4 +% +39.7 +% +Expected +term (in years) +6 +7 +Risk-free +interest rate +4.2 +% +4.1 +% +Weighted-average +grant date fair value per share +$ +20.30 +$ +16.75 +F-20 +Index +PETROLEUM +DEVELOPMENT CORPORATION +Expected +volatilities are based on the Company's historical volatility. The expected +life +of an award is estimated using historical exercise behavior data. The risk-free +interest rate is based on the U.S. Treasury yields in effect at the time of +grant and extrapolated to approximate the expected life of the award. The +Company does not expect to pay dividends, nor does it expect to declare +dividends in the foreseeable future. +The +following table provides a summary of the Company's stock option award activity +for the year ended December 31, 2006: +Number +of +Shares +Underlying +Options +Weighted +Average +Exercise +Price +Per +Share +Weighted +Average +Remaining +Contractual +Term +(years) +Outstanding +at December 31, 2005 +73,880 +$ +11.96 +Granted +23,687 +44.76 +Exercised +(8,000 +) +3.88 +Outstanding +at December 31, 2006 +89,567 +21.36 +5.6 +Vested +and expected to vest at December 31, 2006 +85,808 +20.32 +5.4 +Exercisable +at December 31, 2006 +57,440 +9.38 +3.7 +Year +Ended December 31, +(in +millions) +2006 +2005 +2004 +Total +intrinsic value of options exercised +$ +0.3 +$ +0.1 +$ +27.6 +Total +intrinsic value of options outstanding +2.0 +1.6 +2.1 +Total +intrinsic value of options exercisable +1.9 +1.6 +2.0 +The +intrinsic value of options exercised represents the amount by which the market +value of the Company’s stock at date of exercise exceeds the exercise price of +the option. The intrinsic values of the options outstanding and exercisable +represent the amount by which the closing market price of the Company’s common +stock at the last trading day of the year exceeds the exercise price of the +options. +Total +unrecognized compensation cost related to stock options granted under the 2004 +Plan was $0.5 million as of December 31, 2006. This cost is expected to be +recognized over a weighted average period of 2.7 years. +During +2004, 337,360 stock option shares were exercised by employees exchanging 62,999 +mature shares of stock with a fair value of $1.4 million. All of the mature +shares exchanged were subsequently cancelled. +Restricted +Stock Awards. +The +Company began issuing shares of restricted common stock to employees in 2004. +The fair value of the awards issued is determined based on the fair market +value +of the shares on the date of grant. The grant date fair value is amortized +over +the vesting period, ratably over four years from the date of grant for employees +and the lesser of three years or remaining elected term at date of issuance +for +directors. +The +following table provides a summary of the Company's restricted stock award +activity for the year ended December 31, 2006: +Restricted +Shares +Weighted +Average +Grant-Date +Fair +Value +Non-vested +restricted stock at December 31, 2005 +38,430 +$ +32.68 +Granted +118,498 +40.65 +Vested +(19,602 +) +30.47 +Forfeited +(5,596 +) +40.05 +Non-vested +restricted stock at December 31, 2006 +131,730 +$ +39.87 +F-21 +Index +PETROLEUM +DEVELOPMENT CORPORATION +Year +Ended December 31, +(in +millions) +2006 +2005 +2004 +Total +intrinsic value of restricted stock awards vested +$ +0.8 +$ +0.2 +$ +- +Total +intrinsic value of restricted stock awards outstanding +5.7 +1.3 +0.9 +The +intrinsic value above is based upon the closing market price of the Company's +common stock on the last trading date of the year, $43.05. +The +total +compensation cost related to non-vested awards not yet recognized as of December +31, 2006, is $3.9 million. The cost is expected to be recognized over a +weighted-average period of 3.2 years. +Conversion +of Predecessor Shares +The +Company has historically understated the number of shares issued and outstanding +primarily as a result of improper conversion of predecessor company shares +dating back to 1969. The impact of this adjustment on the balance sheet was +less +than $1 thousand, and the impact of the exclusion of these shares as outstanding +was not material to the Company's reported earnings per share. The Company +has +adjusted the amount of shares and the balance in common stock in the +accompanying consolidated statement of shareholders’ equity as of January 1, +2006. +Treasury +Share Purchases +In +March +2004, the Compensation Committee of the Company's Board of Directors ("Board") +approved the purchase of 48,650 shares of common stock from one of the Company’s +officers. The purchase price of the common stock was the closing price on the +date of the purchase of $26.61 per share and totaled $1.3 million, which +approximated the tax savings to be realized by the Company as a result of the +exercise of said officer’s non-qualified stock options in 2004. The Company also +purchased 1,703 shares from an employee upon retirement from the Company in +June +2004. All shares purchased were subsequently retired. +In +March +2005, the Company publicly announced the authorization by its Board to purchase +up to 2% of the Company's outstanding common stock (331,796 shares) at fair +market value at the date of purchase. In June 2005, the Board approved an +amendment of the size of the stock purchase from 2% to 10% (1,658,980 shares) +of +the Company’s then outstanding common stock. Under the program, the Board had +discretion as to the dates of purchase and amounts of stock to be purchased +and +whether or not to make purchases. The Company purchased pursuant to the plan +331,796 common shares at a cost of $7.9 million ($23.75 average price paid +per +share). This program expired on December 31, 2005. All shares purchased in +accordance with the program have subsequently been retired. +In +January 2006, the Company announced that +its +Board authorized the purchase of up to 10% (1,627,500 shares) of the Company's +common stock during 2006. Stock purchases under this program were made in the +open market or in private transactions, at times and in amounts that management +deemed appropriate. In October 2006, the Company completed its January 2006 +program. Total shares purchased pursuant to the program were 1,627,500 common +shares at a cost of $66.3 million ($40.75 average price paid per share), +including 100,000 shares from an executive officer of the Company at a cost +of +$4.1 million ($40.66 price paid per share). All shares purchased in accordance +with the program have subsequently been retired. +On +October 16, 2006, the Board of Directors of the Company approved a second 2006 +purchase program authorizing the Company to purchase up to 10% (1,477,109 +shares) of the Company’s then outstanding common stock through April 2008. Stock +purchases under this program may be made in the open market or in private +transactions, at times and in amounts that management deems appropriate. The +Company may terminate or limit the stock purchase program at any +time. +Stock +Repurchase Agreement +In +May +2004, the Company repurchased 50,487 shares of common stock from the estate +of +one of the Company’s former officer in accordance with the terms of a stock +repurchase agreement. The repurchase totaled $1.4 million of which $1 million +was funded by life insurance proceeds. Similar agreements with all other +executive officers were terminated in December 2005. +NOTE +9 - EMPLOYEE BENEFIT PLANS +The +Company sponsors a qualified deferred compensation plan covering substantially +all of its employees. The plan consists of a 401(k) retirement plan with a +profit sharing component. The plan enables eligible employees to contribute +a +portion of their compensation through payroll deductions in accordance with +specific guidelines. The Company provides a discretionary matching contribution +based on a percentage of the employees' contributions up to certain limits. +The +Company's contribution to the profit sharing component is discretionary. Total +Company contributions, to both 401(k) and profit sharing, in 2006, 2005 and +2004, were $3.1 million, $0.9 million and $0.7 million, +respectively. +F-22 +Index +PETROLEUM +DEVELOPMENT CORPORATION +The +Company provides a supplemental retirement benefit of deferred compensation +under terms of the various employment agreements with certain executive +officers. During 2006, 2005 and 2004, the Company charged $0.3 million, $0.2 +million and $0.2 million related to this plan to general and administrative +expenses, respectively, and has recorded a related liability in the amount +$1.9 +million and $1.1 million as of December 31, 2006 and 2005, respectively. +In +addition to the supplemental retirement benefit of deferred compensation, the +Company offers a supplemental healthcare benefit covering certain executive +officers and their spouses in accordance with each officer's employment +agreement. During 2006, the Company charged $0.1 million related to this plan +to +general and administrative expenses and has a related liability in the amount +of +$0.6 million as of December 31, 2006. +The +Company maintains a non-qualified deferred compensation plan for non-employee +directors of the Company. The amount of compensation deferred by each +participant is based on participant elections. The amounts deferred pursuant +to +the plan are invested in the Company's common stock, maintained in a rabbi +trust +and are classified in the accompanying balance sheet as treasury shares as +a +component of shareholders' equity. The plan may be settled in either cash or +shares as requested by the participant. As of December 31, 2006, the Company +had +recorded a long-term liability of $0.2 million, which is included in other +liabilities in the accompanying consolidated balance sheet. +NOTE +10 - EARNINGS PER SHARE +The +following is a reconciliation of the numerators and denominators used in the +calculation of basic and diluted earnings per share for the years ended December +31, (in thousands, except per share amounts): +2006 +2005 +2004 +Weighted +average common shares outstanding +15,660 +16,362 +16,239 +Dilutive +effect of share-based compensation: +Unamortized +portion of restricted stock +22 +13 +1 +Stock +options +55 +52 +366 +Non +employee director deferred compensation +4 +- +- +Weighted +average common and common equivalent shares +outstanding +15,741 +16,427 +16,606 +Net +income +$ +237,772 +$ +41,452 +$ +33,228 +Basic +earnings per common share +$ +15.18 +$ +2.53 +$ +2.05 +Diluted +earnings per common share +$ +15.11 +$ +2.52 +$ +2.00 +Options +with an exercise price exceeding the average price of the underlying securities +are not considered to be dilutive, or anti-dilutive, and are included in the +calculation of the denominator for diluted earnings per share. Common share +equivalents attributable to anti-dilutive options, and therefore not included +in +the computation of earnings per share, for the years ended December 31, 2006, +2005 and 2004, were 23,687, 16,880 and 16,880, respectively. +NOTE +11 - TRANSACTIONS WITH AFFILIATES +Funds +held for future distribution on the consolidated balance sheets was relatively +unchanged at $31.4 million for each of the years ended December 31, 2006 and +2005. These funds primarily represent amounts owed to affiliated partnerships +for undistributed production proceeds as of December 31, 2006 and 2005, +respectively. +The +Company provided oil and gas well drilling services and well operations and +pipeline services to affiliated partnerships. Substantially all of the Company's +revenue and expenses related to oil and gas well drilling operations and +revenues from well operations and pipeline income are associated with services +provided to the investing partners. Amounts due from/to the affiliated +partnership are principally amounts related to derivative +positions. +F-23 +Index +PETROLEUM +DEVELOPMENT CORPORATION +Management +fees collected from the affiliated partnerships amounted to $1.3 million, $1.7 +million and $1.5 million for the years ended December 31, 2006, 2005 and 2004, +respectively, and are included in other income on the accompanying consolidated +statements of income. +Revenues +from oil and gas well drilling operations and costs of oil and gas well drilling +operations each include $0.1 million, $0.2 million and $0.1 million during +2006, +2005 and 2004, respectively, related to investments made by officers of the +Company for working interests in wells drilled during the respective years. +The +Company through its wholly-owned subsidiary, PDC +Securities Incorporated, acts as Dealer-Manager of the drilling partnerships. +PDC +Securities receives the applicable commissions and marketing allowances from +the +Escrow Agent of the drilling program and distributes them to the soliciting +broker/dealers who sell the programs. The commissions and marketing allowances +received by +PDC +Securities are included in other income net of the commissions distributed +to +the soliciting broker/dealer. The commissions and marketing allowances received +by PDC Securities and distributed to the Soliciting Broker/Dealers amounted +to +$8.8 million, $11.4 million and $9.7 million for the years ended December 31, +2006, 2005 and 2004, respectively. +During +2006, 2005 and 2004, the Company paid $18,000, $25,900 and $22,500, +respectively, to the Corporate Secretary's law firm for various legal +services. +NOTE +12 - COMMITMENTS AND CONTINGENCIES +The +Company would be exposed to oil and natural gas price fluctuations on underlying +purchase and sale contracts should the counterparties to the Company's +derivative instruments or the counterparties to the Company's gas marketing +contracts not perform. Nonperformance is not anticipated. There were no +counterparty default losses in 2006, 2005 or 2004. +The +Company is a party to an exploration agreement with an unaffiliated party. +The +agreement requires the Company to drill a minimum of 25 wells through June +30, +2007. For each well the Company fails to drill prior to June 30, 2007, the +Company will be required to pay liquidated damages equal to $125,000 per +un-drilled well, for a maximum contingency of $3.1 million. Drilling pursuant +to +the agreement commenced in February 2007. +In +connection with the Company’s sale of undeveloped leaseholds in July 2006, the +Company is obligated to either drill 16 wells on specifically identified acreage +over the next three years (five by December 31, 2007, another five by December +31, 2008, and another six by December 31, 2009) or pay liquidated damages of +$1.6 million per un-drilled well for a total contingent obligation of $25.6 +million, of which $8 million is reflected in current liabilities, and $17.6 +million is reflected as a deferred gain on sale of leaseholds, a long-term +liability, in the consolidated balance sheets. See Note 15 for additional +disclosure related to the sale. +Substantially +all of the Company's drilling programs contain a repurchase provision where +investing partners may request that the Company purchase their partnership +units +at any time beginning with the third anniversary of the first cash distribution. +The provision provides that the Company is obligated to purchase an aggregate +of +10% of the initial subscriptions per calendar year (at a minimum price of four +times the most recent 12 months' cash distributions), if repurchase is requested +by investors, and subject to the Company's financial ability to do so. The +maximum annual repurchase obligation as of December 31, 2006, was approximately +$12.3 million. The Company has adequate liquidity to meet this obligation. +During 2006 and 2005, the Company paid $0.8 million and $0.4 million, +respectively, under this provision for the repurchase of partnership units. +As +of December 31, 2006, outstanding repurchase offers to investing partners +totaled $0.2 million, which $0.1 million of the outstanding offers was +consummated in 2007 prior to expiration. +The +Company's drilling programs formed from 1996 through the second quarter of +2005 +contain a performance supplement that provides for changes in the distribution +of partnership profits if certain levels of performance are not met. The terms +of this provision in the partnership agreements are not a guarantee of a rate +of +return on an investment in the partnership. Under those specific conditions, +such changes can result in the Company’s share of an affected partnership’s +profits being reduced by up to one half of the amount to which it otherwise +would be entitled in the affected period. In no event would the Company be +obligated to assume a disproportionate share of losses in such partnerships; +should the partnerships which contain this provision in the partnership +agreements incur a loss, the Company’s share of such losses would be unaffected +by the terms of this provision. In accordance with these provisions, the +Company’s share of partnership profits was reduced by an aggregate of $1 +million, $0.7 million and $0.6 million during 2006, 2005 and 2004, respectively. +As of December 31, 2006 and 2005, based on production through December 31 of +the +corresponding year, the Company had accrued $0.4 million and zero, +respectively. +As +Managing General Partner of 76 partnerships the Company has liability for any +potential casualty losses in excess of the partnership assets and insurance. +In +January 2007, the Company purchased the remaining working interests in 44 of +the +76 partnerships, which were sponsored by the Company in the late 1980s and +1990s +(see Note 16). The +Company's management believes the casualty insurance coverage carried by the +Company and its subcontractors is adequate to meet this potential +liability. +F-24 +Index +PETROLEUM +DEVELOPMENT CORPORATION +In +order +to secure the services for drilling rigs, the Company made commitments to the +drilling contractors, which call for a minimum commitment of $9,000 daily for +a +specified amount of time if the Company ceases to use the drilling rigs, an +event that is not anticipated to occur, and a maximum commitment of $34,400 +daily for a specified amount of time for daily use of the drilling rigs. As +of +December 31, 2006, commitments for these two separate contracts expire in July +2009 and May 2010. As of December 31, 2006, the Company has an outstanding +minimum commitment for $9.4 million and an outstanding maximum commitment for +$36.1 million. +From +time +to time the Company is a party to various legal proceedings in the ordinary +course of business. The Company is not currently a party to any litigation that +it believes would have a materially adverse affect on the Company's business, +financial condition, results of operations, or liquidity. +Recent +litigation has commenced against several companies in our industry regarding +royalty practices and payments in jurisdictions where the Company conducts +business. While the Company's business model differs from those of the litigants +in those cases, and the Company has not been named in any litigation, has not +had similar litigation commenced, nor has such litigation been threatened, +there +can be no assurance that the Company will not be a party to any litigation +or to +similar litigation in the future. +NOTE +13 - LEASE OBLIGATIONS +The +Company has entered into operating leases on behalf of itself and its affiliated +partnerships principally for the leasing of natural gas compressors on its +Michigan operating facilities. Additionally, the Company has operating leases +for general office equipment. The future minimum lease payments under these +non-cancelable operating leases as of December 31, 2006, are as follows: (in +thousands) +Year +Lease +Amount +2007 +$ +502 +2008 +493 +2009 +495 +2010 +347 +2011 +208 +Thereafter +4 +$ +2,049 +The +Company's share of this lease expense for operating leases for the years ended +December 31, 2006, 2005 and 2004 was $0.4 million, $0.3 million and $0.3 +million, respectively. +NOTE +14 - DERIVATIVE FINANCIAL INSTRUMENTS +The +Company utilizes commodity based derivative instruments to manage a portion +of +its exposure to price risk from its oil and natural gas sales and marketing +activities. Company policy prohibits the use of oil and natural gas future +and +option contracts for speculative purposes. These instruments consist of +NYMEX-traded natural gas futures contracts and option contracts for Appalachian +and Michigan production, Panhandle-based contracts and NYMEX-traded contracts +for NECO production and CIG-based contracts for other Colorado production. +These +derivative instruments have the effect of locking in for specified periods +(at +predetermined prices or ranges of prices) the prices the Company will receive +for the volume to which the derivative relates and, in the case of RNG, the +cost +of gas supplies purchased for marketing activities. As a result, while these +derivatives are structured to reduce the Company's exposure to changes in price +associated with the derivative commodity, they also limit the benefit the +Company might otherwise have received from price changes associated with the +derivative commodity. RNG also enters into fixed-price physical purchase and +sale agreements that are derivative contracts. +The +net +fair value of the commodity based derivatives was $13.6 million of which $1.1 +million is included in other long term assets at December 31, 2006. At December +31, 2005, the net fair value of commodity based derivatives was $(9.4) million +of which $(1.4) million is included in other long term liabilities. The Company +recognized in the statement of income an unrealized gain on commodity based +derivatives of $7.6 million for the year ended December 31, 2006, and unrealized +losses of $3.2 million and $1.1 million for the years ended December 31, 2005, +and 2004, respectively. +F-25 +Index +PETROLEUM +DEVELOPMENT CORPORATION +The +following tables summarize the open derivative option and purchase and sales +contracts for Riley Natural Gas and the Company as of December 31, 2006 and +2005. +Riley +Natural Gas +Open +Derivative Positions +(dollars +in thousands, except average price data) +Commodity +Type +Quantity +Gas-MMbtu +Weighted +Average +Price +Total +Contract +Amount +Fair +Value +Total +Positions as of December 31, 2006 +Natural +Gas +Cash +Settled Futures/Swaps Purchases +246,900 +$ +7.34 +$ +1,811 +$ +(304 +) +Natural +Gas +Cash +Settled Futures/Swaps Sales +1,952,150 +8.42 +16,444 +2,815 +Natural +Gas +Cash +Settled Basis Swap Purchases +90,000 +0.42 +38 +(12 +) +Natural +Gas +Cash +Settled Basis Swap Sales +20,000 +0.50 +10 +4 +Natural +Gas +Cash +Settled Option Purchases +220,000 +5.50 +1,210 +64 +Natural +Gas +Cash +Settled Option Sales +110,000 +10.10 +1,111 +(39 +) +Natural +Gas +Physical +Purchases +1,964,150 +8.27 +16,244 +(1,974 +) +Natural +Gas +Physical +Sales +114,974 +9.62 +1,106 +310 +Natural +Gas +Physical +Basis Purchases +20,000 +0.45 +9 +(3 +) +Natural +Gas +Physical +Basis Sales +90,000 +0.44 +39 +14 +Positions +maturing in 12 months following December 31, 2006 +Natural +Gas +Cash +Settled Futures/Swaps Purchases +246,900 +$ +7.34 +$ +1,811 +$ +(304 +) +Natural +Gas +Cash +Settled Futures/Swaps Sales +1,637,150 +8.37 +13,697 +2,637 +Natural +Gas +Cash +Settled Basis Swap Purchases +90,000 +0.42 +38 +(12 +) +Natural +Gas +Cash +Settled Basis Swap Sales +20,000 +0.50 +10 +4 +Natural +Gas +Cash +Settled Option Purchases +220,000 +5.50 +1,210 +64 +Natural +Gas +Cash +Settled Option Sales +110,000 +10.10 +1,111 +(39 +) +Natural +Gas +Physical +Purchases +1,649,150 +8.27 +13,641 +(2,027 +) +Natural +Gas +Physical +Sales +114,974 +9.62 +1,105 +310 +Natural +Gas +Physical +Basis Purchases +20,000 +0.45 +9 +(3 +) +Natural +Gas +Physical +Basis Sales +90,000 +0.44 +39 +14 +Prior +Year Total Positions as of December 31, 2005 +Natural +Gas +Cash +Settled Futures/Swaps Purchases +1,025,500 +$ +9.05 +$ +9,283 +$ +1,983 +Natural +Gas +Cash +Settled Futures/Swaps Sales +3,149,000 +7.95 +25,018 +(8,689 +) +Natural +Gas +Cash +Settled Basis Swap Purchases +450,000 +0.91 +409 +(158 +) +Natural +Gas +Cash +Settled Basis Swap Sales +240,000 +0.50 +120 +4 +Natural +Gas +Physical +Purchases +2,819,000 +8.32 +23,456 +7,858 +Natural +Gas +Physical +Sales +585,222 +10.72 +6,272 +(670 +) +Natural +Gas +Physical +Basis Purchases +240,000 +0.45 +108 +8 +Natural +Gas +Physical +Basis Sales +450,000 +0.94 +420 +169 +The +maximum term for the derivative contracts listed above is 25 +months. +F-26 +Index +PETROLEUM +DEVELOPMENT CORPORATION +Petroleum +Development Corporation +Open +Derivative Positions +(dollars +in thousands, except average price data) +Commodity +Type +Quantity +Gas-MMbtu +Oil-Barrels +Weighted +Average +Price +Total +Contract +Amount +Fair +Value +Total +Positions as of December 31, 2006 +Natural +Gas +Cash +Settled Option Sales +17,390,000 +$ +5.56 +$ +96,613 +$ +12,597 +Natural +Gas +Cash +Settled Option Purchases +2,155,000 +10.34 +22,287 +(14 +) +Oil +Cash +Settled Option Purchases +300,000 +50.00 +15,000 +155 +Positions +maturing in 12 months following December 31, 2006 +Natural +Gas +Cash +Settled Option Sales +15,530,000 +$ +5.53 +$ +85,850 +$ +11,682 +Natural +Gas +Cash +Settled Option Purchases +2,155,000 +10.34 +22,287 +(14 +) +Oil +Cash +Settled Option Purchases +300,000 +50.00 +15,000 +155 +Prior +Year Total Positions as of December 31, 2005 +Natural +Gas +Cash +Settled Option Sales +5,665,000 +$ +8.17 +$ +46,273 +$ +(12,531 +) +Natural +Gas +Cash +Settled Option Purchases +14,030,000 +6.36 +89,210 +2,660 +The +maximum term for the derivative contracts listed above is 15 +months. +In +addition to including the gross assets and liabilities related to the Company's +share of oil and gas production, the above tables and the accompanying +consolidated balance sheets include the gross assets and liabilities related +to +derivative contracts entered into by the Company on behalf of the affiliate +partnerships as the Managing General Partner. The accompanying consolidated +balance sheets include the fair value of derivatives and a corresponding net +payable to the partnerships of $7.5 million as of December 31, 2006 and a net +receivable from the partnerships of $5.4 million as of December 31, 2005. In +addition to the short-term fair value of derivatives shown in the accompanying +consolidated balance sheet there are long-term assets and long-term liabilities +which total to a net long-term asset of approximately $0.9 million and $1.3 +million as of December 31, 2006 and 2005, respectively, related to the fair +value of derivatives included in the accompanying consolidated balance +sheets. +The +Company is required to maintain margin deposits with brokers for outstanding +futures contracts. As of December 31, 2006 and 2005, restricted cash in the +amount of $0.5 million and $1.5 million was on deposit. +An +interest rate swap agreement was used to reduce the potential impact of +increases in interest rates on variable rate long-term debt. The swap agreement +expired in October 2004. The agreement required the Company, on a quarterly +basis, to make a fixed-rate interest payment of 6.89% plus its current LIBOR +rate margin (+1.50% at December 31, 2003) on a $10 million amount related to +its +outstanding line of credit. The change in the fair value of the swap was +included as a component of interest expense; the related gain was $0.6 million +for the year ended December 31, 2004. +By +using +derivative financial instruments to manage exposures to changes in interest +rates and commodity prices, the Company exposes itself to credit risk and market +risk. Credit risk is the failure of the counterparty to perform under the terms +of the derivative contract. When the fair value of a derivative contract is +positive, the counterparty owes the Company, which creates repayment risk. +The +Company minimizes the credit or repayment risk in derivative instruments by +entering into transactions with high-quality counterparties. There were no +counterparty defaults during the years ended December 31, 2006, 2005 and +2004. +F-27 +Index +PETROLEUM +DEVELOPMENT CORPORATION +The +following changes in the fair value of commodity based derivatives are reflected +in the consolidated statements of income (in millions): +Realized +gains/(losses) +Unrealized +gains/(losses) +Statement +of Income Line Item +2006 +2005 +2004 +2006 +2005 +2004 +Oil +and gas price risk management gain (loss), net +$ +1.9 +$ +(6.4 +) +$ +(1.6 +) +$ +7.2 +$ +(3.0 +) +$ +(1.5 +) +Gas +sales from marketing activities +2.6 +(5.6 +) +0.8 +12.3 +(8.5 +) +1.2 +Cost +of gas marketing activities +(1.9 +) +(1.3 +) +(3.3 +) +(11.9 +) +8.3 +(0.8 +) +Oil +and +gas price risk management gain (loss), net includes realized and unrealized +gains and losses on commodity based derivatives related to the Company’s oil and +gas sales. Gas sales from marketing activities and cost of gas marketing +activities includes realized and unrealized gains and losses on commodity based +derivatives related to the RNG gas sales and gas purchases, respectively. +NOTE +15 - SALE OF OIL AND GAS PROPERTIES +Grand +Valley Field Acreage +In +July +2006, the Company sold to an unaffiliated company a portion of its undeveloped +leasehold located in Grand Valley Field, Garfield County, Colorado. The sale +encompassed 100% of the working interest in approximately 8,700 acres, including +approximately 6,400 acres of the Company's Chevron leasehold and 2,300 acres +of +the Company's Puckett Land Company leasehold. The Company retained approximately +475 undeveloped locations on 10 acre spacing on the Grand Valley Field leasehold +in addition to all of its producing properties in the field. The proceeds from +the sale were $353.6 million. +The +Company recorded a gain on sale of leaseholds of $328 million and a deferred +gain on sale of leaseholds of $25.6 million. The Company is obligated to either +drill 16 wells on specifically identified acreage over the next three years +(five by December 31, 2007, another five by December 31, 2008, and another +six +by December 31, 2009) or pay liquidated damages of $1.6 million per un-drilled +well. The Company expects to drill the wells for its own benefit and, as such, +will record the costs of the wells drilled in accordance with its oil and gas +properties accounting policy. For each well the Company drills, the Company +will +recognize $1.6 million of the deferred gain when drilling is complete. +Alternatively, should the Company not first drill the wells, the unaffiliated +company has the option to drill the wells for its benefit and, should it decide +to exercise its option, with each well drilled, the Company would recognize +both +$1.6 million of the amount deferred and $0.4 million to be paid to the Company +by the unaffiliated company. At December 31, 2006, $8 million of the deferred +gain on sale of leaseholds is classified as short-term and included in other +current liabilities in the accompanying consolidated balance sheet. +In +conjunction with the sale, the Company entered into a LKE agreement, in +accordance with IRC Section 1031, with a “qualified intermediary.” Proceeds in +the amount of $300 million were transferred directly to the qualified +intermediary to be held in trust pursuant to the terms of the LKE agreement. +The +Company had until mid-January 2007 to close any acquisition of suitable +like-kind property, allowing the Company to take advantage of the income tax +deferral benefits of a LKE transaction. See Note 16 for a further discussion +of +the acquisition of suitable like-kind properties. +During +2005, the Company sold a portion of one of its undeveloped Grand Valley Field, +Garfield County, Colorado leases to an unaffiliated entity. The proceeds of +the +sale were $6.2 million and the Company’s carrying value of the property was +zero. The Company was required to remit $1 million to the original lessor, +unless it commenced construction of certain facilities adjacent to this +undeveloped property subject to certain timing conditions. The Company commenced +construction of the facilities in 2005. The gain of $6.2 million was recognized +in 2005 and is included in gain on sale of leaseholds in the accompanying +consolidated statement of income. +Others +Additionally, +in 2005, the Company completed the sale to an unaffiliated entity of 111 +Pennsylvania wells it purchased in 1998. The Company received proceeds of $3.4 +million and recorded a gain of $1.5 million, which is included in gain on sale +of leaseholds in the accompanying consolidated statement of income. +F-28 +Index +PETROLEUM +DEVELOPMENT CORPORATION +NOTE +16 - SUBSEQUENT EVENTS +Acquisition +of IRC Section 1031 - Like-Kind Exchange Properties +In +January 2007, the Company completed its acquisitions of suitable like-kind +properties in accordance with the LKE agreement it entered into in connection +with its sale of undeveloped leaseholds located in Grand Valley Field, Garfield +Country, Colorado in July 2006. The Company acquired for cash qualifying oil +and +gas properties totaling $191.5 million as described below. +EXCO +Resources Inc. +On +January 5, 2007, the Company completed its purchase of EXCO Resources Inc.’s +producing properties and remaining undeveloped drilling locations and acreage +in +the Wattenberg Field area of the DJ Basin, Colorado. The cash consideration +paid +for the EXCO properties was $130.9 million. The acquisition included +substantially all of EXCO’s assets in the area and encompassed 144 oil and gas +wells (approximating 25.5 Bcfe, net of royalty interests, proved developed +reserves as of December 31, 2005) and 8,160 acres of leasehold. The wells and +leases acquired are located in Weld, Adams, Larimer, and Broomfield Counties, +Colorado. The Company will operate the assets and holds a majority working +interest in the properties. +Company-Sponsored +Partnerships . +On +January 10, 2007, the Company completed the purchase of the remaining working +interests in 44 Company-sponsored partnerships for $58.8 million. The +transaction resulted in an increase in the Company’s net interest in 718 wells +that are currently operated by the Company. The wells are located primarily +in +the Appalachian Basin and Michigan. +Other. +The +Company acquired from unaffiliated parties undeveloped leaseholds in Erath +County, Texas for $1.8 million. +Other +Acquisitions +On +February 22, 2007, the Company acquired, from an unaffiliated party 28 producing +wells and associated undeveloped acreage located in Colorado (Wattenberg Field) +for a purchase price of $11.8 million. The acquisition encompasses current +daily +production of approximately 668 Mcfe (520 Mcf of gas and 25 barrels of oil +per +day), net to the interests acquired, 100 or more undeveloped drilling locations, +19.1 Bcfe of proved reserves, and an additional 7.5 Bcfe of probable +reserves. +NOTE +17 - BUSINESS SEGMENTS +The +Company's +operating activities can be divided into four major segments: drilling and +development, natural gas marketing, oil and gas sales, and well operations +and +pipeline income. The Company drills natural gas wells for Company-sponsored +drilling partnerships and retains an interest in each well. A wholly-owned +subsidiary, Riley Natural Gas, engages in the marketing of natural gas to +commercial and industrial end-users. The Company owns an interest in +approximately 3,100 wells from which it sells its oil and gas production from +its working interests in the wells. The Company charges Company-sponsored +partnerships and other third parties competitive industry rates for well +operations and gas gathering. All material inter-company accounts and +transactions between segments have been eliminated. Segment information for +the +years ended December 31, 2006, 2005 and 2004 is presented below (in +thousands). +F-29 +Index +PETROLEUM +DEVELOPMENT CORPORATION +Year +Ended December 31, +2006 +2005 +2004 +REVENUES +Drilling +and development +$ +17,917 +$ +99,963 +$ +94,076 +Natural +gas marketing +131,326 +121,114 +94,628 +Oil +and gas sales (1) +124,336 +93,191 +66,407 +Well +operations and pipeline income +10,704 +8,760 +7,677 +Unallocated +amounts +2,220 +2,170 +1,695 +Total +$ +286,503 +$ +325,198 +$ +264,483 +SEGMENT +INCOME BEFORE INCOME TAXES +Drilling +and development +$ +5,300 +$ +11,778 +$ +16,380 +Natural +gas marketing +1,816 +1,737 +1,784 +Oil +and gas sales (2) +61,868 +46,095 +35,090 +Well +operations and pipeline income (3) +2,823 +3,539 +3,695 +Unallocated +amounts +General +and administrative expense +(19,047 +) +(6,960 +) +(4,506 +) +Gain +on sale of leaseholds +328,000 +7,669 +- +Interest +income (4) +7,407 +625 +138 +Interest +expense +(2,443 +) +(217 +) +(238 +) +Other +(5) +1,685 +1,862 +1,135 +Total +$ +387,409 +$ +66,128 +$ +53,478 +As +of December 31, +SEGMENT +ASSETS +Drilling +and development +$ +87,746 +$ +89,030 +$ +64,348 +Natural +gas marketing +39,899 +56,518 +31,234 +Oil +& gas sales +394,952 +251,897 +205,680 +Well +operations and pipeline income +28,895 +31,407 +16,518 +Unallocated +amounts +Cash +109,467 +3,383 +112 +Designated +cash - property acquisitions (6) +191,512 +- +- +Other +31,816 +12,126 +11,561 +Total +$ +884,287 +$ +444,361 +$ +329,453 +EXPENDITURES +FOR SEGMENT LONG-LIVED ASSETS +Drilling +and development +$ +- +$ +- +$ +- +Natural +gas marketing +- +1 +6 +Oil +& gas sales +133,401 +92,907 +45,713 +Well +operations and pipeline income +1,419 +3,949 +1,911 +Unallocated +amounts +12,125 +2,452 +1,302 +Total +$ +146,945 +$ +99,309 +$ +48,932 +(1) +Includes +oil and gas price risk management gains (losses), +net. +(2) +Includes +$8.1 million and $11.1 million in exploration costs and $31.3 million +and +$19.3 million in DD&A for the years ended December 31, 2006 and 2005, +respectively. +(3) +Includes +$1.9 million and $1.5 million in DD&A for the years ended December 31, +2006 and 2005, respectively. +(4) +Includes +interest income for PDC operations, $0.6 and $0.3 million in interest +income allocated to Natural gas marketing for the years ended December +31, +2006 and 2005, respectively, in addition to partnership management +fees. +(5) +Includes +$0.5 million and $0.3 million in DD&A for the years ended December 31, +2006 and 2005, respectively. +(6) +Amount +was expended in early 2007 in LKE transactions; the assets and liabilities +of which will be included in the oil and gas sales +segment. +F-30 +Index +PETROLEUM +DEVELOPMENT CORPORATION +NOTE +18 - SUPPLEMENTAL OIL AND GAS INFORMATION - UNAUDITED +Costs +Incurred in Oil and Gas Property Acquisition, Exploration and Development +Activities (Unaudited) +Costs +incurred by the Company in oil and gas property acquisition, exploration and +development are presented below (in thousands). +Year +ended December 31, +2006 +2005 +2004 +Acquisition +of properties: +Unproved +properties +$ +11,926 +$ +16,910 +$ +4,583 +Proved +properties +802 +1,608 +720 +Development +costs +114,487 +68,605 +32,700 +Exploration +costs +20,894 +12,943 +4,170 +Total +costs incurred +$ +148,109 +$ +100,066 +$ +42,173 +The +proved reserves attributable to the development costs in the above table were +70,499 MMcf and 3,148 MBbls for 2006, 85,624 MMcf and 1,576 MBbls for 2005, +40,716 MMcf and 358 MBbls for 2004. Of the above development costs incurred +for +the years ended December 31, 2006, 2005 and 2004, the amounts of $1 million, +$6.9 million and $1.8 million, respectively, were incurred to develop proved +undeveloped properties from the prior year end. +Property +acquisition costs include costs incurred to purchase, lease or otherwise acquire +a property. Development costs include costs incurred to gain access to and +prepare development well locations for drilling, to drill and equip development +wells, recompletions and to provide facilities to extract, treat, gather and +store oil and gas. Exploration costs include costs incurred in identifying +areas +that may warrant examination and in examining specific areas that are considered +to have prospects of containing oil and gas reserves. +Capitalized +Oil and Gas Costs (Unaudited) +Aggregate +capitalized costs for the Company related to oil and gas exploration and +production activities with applicable accumulated depreciation, depletion and +amortization are presented below (in thousands): +December +31, +2006 +2005 +Proved +oil and gas properties +$ +473,451 +$ +334,301 +Unproved +oil and gas properties +27,055 +19,846 +500,506 +354,147 +Less +accumulated depreciation, depletion and amortization +133,172 +102,513 +$ +367,334 +$ +251,634 +F-31 +Index +PETROLEUM +DEVELOPMENT CORPORATION +Suspended +Well Costs (Unaudited) +The +following table lists the capitalized exploratory well costs which are pending +the determination of proved reserves (dollars +in thousands). +2006 +2005 +2004 +Beginning +balance at January 1 +$ +1,918 +$ +4,170 +$ +- +Additions +to capitalized exploratory well costs pending the determination of +proved +reserves +12,016 +6,441 +4,170 +Reclassifications +to wells, facilities and equipment based on the determination of +proved +reserves +(13,169 +) +(4,523 +) +- +Capitalized +exploratory well costs charged to expense +- +(4,170 +) +- +Ending +balance at December 31 +$ +765 +$ +1,918 +$ +4,170 +As +of +December 31, 2006, the one well awaiting the determination of proved reserves +has not been capitalized for a period greater than one year. +Results +of Operations for Oil and Gas Producing Activities +(Unaudited) +The +results of operations for oil and gas producing activities (excluding marketing) +are presented below (in thousands). +Years +Ended December 31, +2006 +2005 +2004 +Revenue: +Oil +and gas sales +$ +115,189 +$ +102,559 +$ +69,492 +Oil +and gas price risk management gain (loss), net +9,147 +(9,368 +) +(3,085 +) +124,336 +93,191 +66,407 +Expenses: +Production +costs +20,855 +16,194 +14,201 +Depreciation, +depletion and amortization +30,988 +19,322 +16,680 +Exploration +costs +8,131 +11,115 +- +59,974 +46,631 +30,881 +Results +of operations for oil and gas producing activities before provision +for +income taxes +64,362 +46,560 +35,526 +Provision +for income taxes +24,818 +18,112 +13,820 +Results +of operations for oil and gas producing activities (excluding corporate +overhead and interest costs) +$ +39,544 +$ +28,448 +$ +21,706 +F-32 +Index +PETROLEUM +DEVELOPMENT CORPORATION +Production +costs include those costs incurred to operate and maintain productive wells +and +related equipment, including costs such as labor, repairs, maintenance, +materials, supplies, fuel consumed, insurance and production and severance +taxes. In addition, production costs include administrative expenses and +depreciation applicable to support equipment associated with these activities. +Depreciation, depletion and amortization expense includes those costs associated +with capitalized acquisition, exploration and development costs, but does not +include the depreciation applicable to support equipment. The provision for +income taxes is computed using statutory tax rates. +Net +Proved Oil and Gas Reserves (Unaudited) +The +proved reserves of oil and gas of the Company have been estimated by independent +petroleum engineers at December 31, 2006, 2005 and 2004. These reserves have +been prepared in compliance with the SEC and FASB rules which require that +reserve reports be prepared under economic and operating conditions existing +at +the Company’s year-end with no provision for price and cost escalation except by +contractual arrangements. An analysis of the change in estimated quantities +of +oil and gas reserves, all of which are located within the United States, is +shown below: +Oil +(MBbls) +2006 +2005 +2004 +Proved +developed and undeveloped reserves: +Beginning +of year +4,538 +3,316 +3,029 +Revisions +of previous estimates +35 +80 +305 +Beginning +of year as revised +4,573 +3,396 +3,334 +New +discoveries and extensions +Rocky +Mountain region +3,148 +1,576 +358 +Dispositions +to partnerships +(92 +) +- +(12 +) +Purchases +of reserves: +Michigan +- +- +- +Rocky +Mountain region +274 +5 +17 +Appalachian +- +- +- +Production +(631 +) +(439 +) +(381 +) +End +of year +7,272 +4,538 +3,316 +Proved +developed reserves: +Beginning +of year +3,860 +3,190 +2,889 +End +of year +4,629 +3,860 +3,190 +Natural +Gas (MMcf) +2006 +2005 +2004 +Proved +developed and undeveloped reserves: +Beginning +of year +247,288 +197,549 +180,998 +Revisions +of previous estimates +(28,067 +) +(15,850 +) +(10,635 +) +Beginning +of year as revised +219,221 +181,699 +170,363 +New +discoveries and extensions +Rocky +Mountain region +70,499 +85,624 +40,716 +Dispositions +to partnerships +(1,215 +) +(9,556 +) +(4,240 +) +Purchases +of reserves: +Michigan +Basin +35 +47 +96 +Rocky +Mountain region +3,477 +71 +242 +Appalachian +basin +222 +434 +744 +Production +(13,161 +) +(11,031 +) +(10,372 +) +End +of year +279,078 +247,288 +197,549 +Proved +developed reserves: +Beginning +of year +155,354 +146,152 +134,936 +End +of year +158,978 +155,354 +146,152 +F-33 +Index +PETROLEUM +DEVELOPMENT CORPORATION +Standardized +Measure of Discounted Future Net Cash Flows and Changes Therein Relating to +Proved Oil and Gas Reserves (Unaudited) +Summarized +in the following table is information for the Company with respect to the +standardized measure of discounted future net cash flows relating to proved +oil +and gas reserves. Future cash inflows are computed by applying year-end prices +of oil and gas relating to the Company's proved reserves to the year-end +quantities of those reserves. Future production, development, site restoration +and abandonment costs are derived based on current costs assuming continuation +of existing economic conditions. Future income tax expenses are computed by +applying the statutory rate in effect at the end of each year to the future +pretax net cash flows, less the tax basis of the properties and gives effect +to +permanent differences, tax credits and allowances related to the properties +(in +thousands). +2006 +2005 +2004 +Future +estimated cash flows +$ +1,804,796 +$ +2,381,238 +$ +1,298,394 +Future +estimated production costs +(571,346 +) +(545,683 +) +(319,065 +) +Future +estimated development costs +(373,460 +) +(207,164 +) +(95,498 +) +Future +estimated income tax expense +(334,536 +) +(633,444 +) +(343,810 +) +Future +net cash flows +525,454 +994,947 +540,021 +10% +annual discount for estimated timing of cash flows +(309,792 +) +(589,517 +) +(310,593 +) +Standardized +measure of discounted future estimated net cash +flows +$ +215,662 +$ +405,430 +$ +229,428 +The +following table summarizes the principal sources of change in the standardized +measure of discounted future estimated net cash flows (in +thousands). +2006 +2005 +2004 +Sales +of oil and gas production net of production costs +$ +(94,337 +) +$ +(86,366 +) +$ +(55,291 +) +Net +changes in prices and production costs +(299,721 +) +208,353 +26,768 +Extensions, +discoveries, and improved recovery, less related costs +46,109 +150,654 +51,413 +Sales +of reserves +(3,356 +) +(14,456 +) +(7,565 +) +Purchase +of reserves +11,003 +1,266 +1,953 +Development +costs incurred during the period +20,051 +24,035 +8,495 +Revisions +of previous quantity estimates +(23,146 +) +(24,130 +) +6,312 +Changes +in estimated income taxes +120,818 +(112,054 +) +(16,160 +) +Accretion +of discount +62,838 +38,241 +33,500 +Timing +and other +(30,027 +) +(9,541 +) +(22,380 +) +Total +$ +(189,768 +) +$ +176,002 +$ +27,045 +It +is +necessary to emphasize that the data presented should not be viewed as +representing the expected cash flow from, or current value of, existing proved +reserves since the computations are based on a large number of estimates and +arbitrary assumptions. Reserve quantities cannot be measured with precision +and +their estimation requires many judgmental determinations and frequent revisions. +The required projection of production and related expenditures over time +requires further estimates with respect to pipeline availability, rates of +demand and governmental control. Actual future prices and costs are likely +to be +substantially different from the current prices and costs utilized in the +computation of reported amounts. Any analysis or evaluation of the reported +amounts should give specific recognition to the computational methods utilized +and the limitations inherent therein. +F-34 +Index +PETROLEUM +DEVELOPMENT CORPORATION +The +estimated present value of future cash flows relating to proved reserves is +extremely sensitive to prices used at any measurement period. The average prices +used for each commodity for the years ended December 31, 2006, 2005 and 2004 +are +presented below. +Average +Price +As +of December 31: +Oil +Gas +2006 +$ +57.70 +$ +4.96 +2005 +$ +58.25 +$ +8.56 +2004 +$ +41.63 +$ +5.87 +F-35 +Index +PETROLEUM +DEVELOPMENT CORPORATION +NOTE +19 - QUARTERLY FINANCIAL DATA (UNAUDITED) +Quarterly +financial data for the years ended December 31, 2006 and 2005, are presented +below The sum of the quarters may not equal the total of the year's net income +per share due to changes in the weighted average shares outstanding throughout +the year (in thousands, except per share data). +2006 +First +Quarter +Second +Quarter +Third +Quarter +Fourth +Quarter +Total +As +Reported +(1) +As +Revised +(2) +As +Reported +(1) +As +Revised +(2) +As +Reported +(1) +As +Revised +(2) +Revenues: +Oil +and gas well drilling operations +$ +5,278 +$ +5,278 +$ +3,745 +$ +3,745 +$ +2,659 +$ +2,659 +$ +6,235 +$ +17,917 +Gas +sales from marketing activities +41,942 +41,942 +29,129 +29,129 +30,374 +30,374 +29,880 +131,325 +Oil +and gas sales +29,208 +28,332 +27,267 +27,992 +29,663 +30,577 +28,288 +115,189 +Well +operations and pipeline income +2,290 +2,290 +2,486 +2,486 +2,530 +2,536 +3,392 +10,704 +Oil +and gas price risk management gains, net +4,435 +4,925 +1,367 +1,370 +2,912 +2,707 +145 +9,147 +Other +income +3 +3 +21 +21 +1,964 +1,964 +233 +2,221 +Total +revenues +83,156 +82,770 +64,015 +64,743 +70,102 +70,817 +68,173 +286,503 +Costs +and expenses: +Cost +of oil and gas well drilling operations +4,081 +4,212 +3,159 +3,278 +4,311 +3,838 +1,289 +12,617 +Cost +of gas marketing activities +41,775 +41,780 +28,462 +28,471 +29,883 +29,988 +29,911 +130,150 +Oil +and gas production and well operations costs +7,261 +6,949 +6,770 +6,830 +8,762 +8,584 +6,658 +29,021 +Exploration +costs +1,163 +1,208 +1,657 +1,898 +1,749 +2,180 +2,845 +8,131 +General +and administrative expense +3,981 +3,719 +4,667 +5,102 +4,759 +5,357 +4,869 +19,047 +Depreciation, +depletion and amortization +6,616 +6,587 +7,617 +7,605 +8,322 +8,300 +11,243 +33,735 +Total +costs and expenses +64,877 +64,455 +52,332 +53,184 +57,786 +58,247 +56,815 +232,701 +Gain +on sale of leaseholds +- +- +- +- +328,000 +328,000 +- +328,000 +Income +from operations +18,279 +18,315 +11,683 +11,559 +340,316 +340,570 +11,358 +381,802 +Interest +income +388 +392 +343 +349 +3,427 +3,475 +3,834 +8,050 +Interest +expense +(73 +) +(352 +) +(125 +) +(436 +) +(34 +) +(366 +) +(1,289 +) +(2,443 +) +Income +before income taxes +18,594 +18,355 +11,901 +11,472 +343,709 +343,679 +13,903 +387,409 +Income +taxes +6,797 +6,710 +4,351 +4,192 +132,795 +132,795 +5,940 +149,637 +Net +income +$ +11,797 +$ +11,645 +$ +7,550 +$ +7,280 +$ +210,914 +$ +210,884 +$ +7,963 +$ +237,772 +Basic +earnings per common share +$ +0.73 +$ +0.72 +$ +0.47 +$ +0.45 +$ +13.39 +$ +13.39 +$ +0.54 +$ +15.18 +Diluted +earnings per common share +$ +0.73 +$ +0.72 +$ +0.47 +$ +0.45 +$ +13.33 +$ +13.33 +$ +0.54 +$ +15.11 +(1) +As +previously reported in the corresponding Form 10-Q reclassified to +conform +to current year presentation. See Note 1 for detailed discussion +of +reclassifications which impact current year presentation. In addition, +$0.3 million was reclassified from cost of oil and gas well drilling +operations to general and administrative expense and $0.8 million +was +reclassified from oil and gas production and well operations cost +to +exploration costs in the third quarter of +2006. +(2) +The +revised quarterly data in the above table reflects the impact on +the +quarterly results previously reported in 2006 of the adjustments +recorded +pursuant to SEC SAB No. 108 as described in Note +1. +F-36 +Index +PETROLEUM +DEVELOPMENT CORPORATION +2005 +Quarter +First +Second +Third +Fourth +Year +Revenues: +Oil +and gas well drilling operations +$ +25,366 +$ +28,111 +$ +32,267 +$ +14,219 +$ +99,963 +Gas +sales from marketing activities +17,522 +25,917 +14,970 +62,695 +121,104 +Oil +and gas sales +18,664 +21,543 +28,414 +33,938 +102,559 +Well +operations and pipeline income +1,927 +2,068 +2,291 +2,474 +8,760 +Oil +and gas price risk management (losses) gains, net +(3,659 +) +858 +(9,922 +) +3,355 +(9,368 +) +Other +income +(243 +) +1,860 +7 +556 +2,180 +Total +revenues +59,577 +80,357 +68,027 +117,237 +325,198 +Costs +and expenses: +Cost +of oil and gas well drilling operations +20,644 +23,743 +28,734 +15,064 +88,185 +Cost +of gas marketing activities +17,902 +26,177 +14,269 +61,296 +119,644 +Oil +and gas production costs and well operations costs +4,093 +4,595 +6,379 +5,333 +20,400 +Exploration +costs +- +4,864 +136 +6,115 +11,115 +General +and administrative expense +1,617 +1,266 +1,646 +2,431 +6,960 +Depreciation, +depletion and amortization +4,857 +4,845 +5,120 +6,294 +21,116 +Total +costs and expenses +49,113 +65,490 +56,284 +96,533 +267,420 +Gain +on sale of leaseholds +6,216 +1,453 +- +- +7,669 +Income +from operations +16,680 +16,320 +11,743 +20,704 +65,447 +Interest +income +241 +179 +202 +276 +898 +Interest +expense +(33 +) +(29 +) +(26 +) +(129 +) +(217 +) +Income +before income taxes +16,888 +16,470 +11,919 +20,851 +66,128 +Income +taxes +6,248 +6,091 +4,413 +7,924 +24,676 +Net +income +$ +10,640 +$ +10,379 +$ +7,506 +$ +12,927 +$ +41,452 +Basic +earnings per common share +$ +0.64 +$ +0.63 +$ +0.46 +$ +0.80 +$ +2.53 +Diluted +earnings per common share +$ +0.64 +$ +0.63 +$ +0.46 +$ +0.79 +$ +2.52 +F-37 +Index +PETROLEUM +DEVELOPMENT CORPORATION +VALUATION +AND QUALIFYING ACCOUNTS AND RESERVES +(in +thousands) +Description +Beginning +balance +Additions +charged +to +cost +and +expenses +Deductions +Ending +balance +Allowance +for doubtful accounts deducted from accounts receivable in the balance +sheet +2006 +$ +409 +$ +7 +$ +1 +$ +415 +2005 +$ +409 +$ +- +$ +- +$ +409 +2004 +$ +487 +$ +- +$ +78 +(a) +$ +409 +(a) Deduction +relates to the write-off of accounts receivable deemed +uncollectible. +F-38 \ No newline at end of file diff --git a/raw/filings/0000077877/2006/0001140361-07-010649/filing_metadata.csv b/raw/filings/0000077877/2006/0001140361-07-010649/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..f6bba76ec66a8d4f1bdaa68fef5dce31bc9a66ac --- /dev/null +++ b/raw/filings/0000077877/2006/0001140361-07-010649/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 +0000077877,PDCE,"PDC ENERGY, INC.",10-K,2007-05-23,2006-12-31,2007-05-23T10:08:16.000Z,0001140361-07-010649,form10-k.htm,PETROLEUM DEVELOPMENT CORP. 10-K 12-31-2006,4391314,0,0,https://www.sec.gov/Archives/edgar/data/77877/000114036107010649/form10-k.htm,https://www.sec.gov/Archives/edgar/data/77877/000114036107010649/,2006,2006,1 diff --git a/raw/filings/0000077877/2006/0001140361-07-010649/item1.txt b/raw/filings/0000077877/2006/0001140361-07-010649/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2006/0001140361-07-010649/item13.txt b/raw/filings/0000077877/2006/0001140361-07-010649/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2006/0001140361-07-010649/item9a.txt b/raw/filings/0000077877/2006/0001140361-07-010649/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2006/0001140361-07-010649/rp_note.txt b/raw/filings/0000077877/2006/0001140361-07-010649/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2006/0001140361-07-010649/rpt_disclosure.txt b/raw/filings/0000077877/2006/0001140361-07-010649/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..e13bfc21f8804780232ee1edcffcb2b0b9781e07 --- /dev/null +++ b/raw/filings/0000077877/2006/0001140361-07-010649/rpt_disclosure.txt @@ -0,0 +1,105 @@ +Transactions with Related Persons +The +Board +has adopted a policy for the review, approval and ratification of transactions +that involve related parties and potential conflicts of interest. +The +related party transaction policy applies to each director and executive officer +of the Company, any nominee for election as a director, any security holder +who +is known to own more than five percent of the Company's voting securities, +any +immediate family member of any of the foregoing persons and any corporation, +firm or association in which one or more of the Company's directors are +directors or officers, or have a substantial financial interest. +Under +the +related party transaction policy a related person transaction is a transaction +or arrangement involving a related person in which the Company is a participant +or that would require disclosure in the Company's filings with the SEC as +a +transaction with a related person. +The +related persons must disclose to the Audit Committee any potential related +person transactions and must disclose all material facts with respect to +such +interest. All related person transactions will be reviewed by the +Audit Committee. In determining whether to approve or ratify a +transaction, the Audit Committee will consider the relevant facts and +circumstances of the transaction which may include factors such as the +relationship of the related person with the Company, the materiality or +significance of the transaction to the Company and the business purpose and +reasonableness of the transaction, whether the transaction is comparable +to a +transaction that could be available to the Company on an arms-length basis, +and +the impact of the transaction on the Company's business and +operations. +19 +TOC +During +the year ended December 31, 2006, there was no transaction or series of +transactions, or any currently proposed transaction, in which the amount +involved exceeds $120,000 and in which any director, executive officer, holder +of more than 5% of the Company's common stock or any member of the immediate +family of any of the foregoing persons had or will have a direct or indirect +material interest. +Indemnification +of Directors and +Officers +The +Company's By-Laws provide that the Company shall indemnify any director, +officer, employee, or other agent of the Company who is or was a party, or +is +threatened to be made a party, to any proceeding (other than an action by +or in +the right of the Company to procure a judgment in its favor) by reason of +the +fact that such person is or was an agent of the Company, against expenses, +judgments, fines, settlements, and other amounts actually and reasonably +incurred in connection with such proceeding, if that person acted in good +faith +and in a manner that person reasonably believed to be in the best interest +of +the Company, and in the case of a criminal proceeding, had no reasonable +cause +to believe the conduct of that person was unlawful. +The +Company has entered into separate indemnification agreements with each of +its +directors and officers whereby the Company has agreed to indemnify the director +or officer against all expenses, including attorneys' fees, and other amounts +reasonably incurred by the officer or director in connection with any +threatened, pending or completed civil, criminal, administrative or +investigative action or proceeding to which such person is party by reason +of +the fact that he is or was a director or officer, as the case may be, of +the +Company, if the person acted in good faith and in a manner reasonably believed +to be in or not opposed to the best interests of the Company, and, with respect +to any criminal action or proceeding, the person had no reasonable cause +to +believe such conduct to be unlawful. The agreements provide for the +advancement of expenses and that the Company has the right to purchase and +maintain insurance on behalf of the director or officer against any liability +or +liabilities asserted against him, whether or not the Company would have the +power to indemnify the person against such liability under any provision +of the +agreement. The Company has agreed to indemnify such person against +expenses actually and reasonably incurred in connection with any action in +which +the person has been successful on the merits or +otherwise. Indemnification must also be provided by the Company +(unless ordered otherwise by a court) only as authorized in the specific +case +upon a determination that the indemnification of the person is appropriate +because he has met the applicable standard of conduct described in the agreement +made by (i) the Board of Directors, by a majority vote of a quorum consisting +of +directors who are not parties to such action or proceeding, (ii) independent +legal counsel in a written opinion or (iii) the shareholders of the +Company. +Additional +Information +The \ No newline at end of file diff --git a/raw/filings/0000077877/2007/0001140361-08-007391/filing.txt b/raw/filings/0000077877/2007/0001140361-08-007391/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..e892d42d91acc0edb7f23d57d18ec69c8767ca77 --- /dev/null +++ b/raw/filings/0000077877/2007/0001140361-08-007391/filing.txt @@ -0,0 +1,14085 @@ +10-K +1 +form10k.htm +PETROLEUM DEVELOPMENT CORPORATION 10-K 12-31-2007 +form10k.htm +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, 2007 +or +¨ TRANSITION REPORT +PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF +1934 +Commission +File Number 000-07246 +PETROLEUM +DEVELOPMENT CORPORATION +( Exact name of registrant as specified +in its charter) +Nevada +95-2636730 +(State +of Incorporation) +(I.R.S. +Employer Identification No.) +120 +Genesis Boulevard +Bridgeport, +West Virginia 26330 +(Address +of principal executive offices) (Zip Code) +Registrant's +telephone number, including area code: (304) 842-3597 +Securities +registered pursuant to Section 12(b) of the Act: +Title +of Each Class +Name +of Each Exchange on Which Registered +Common +Stock, par value $.01 per share +NASDAQ +Global Select Market +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 ¨ No +x +Indicate by check mark if +registrant is not required to file reports pursuant to Section 13 or Section +15(d) of the Act. Yes ¨ 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 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. ¨ +Indicate +by check mark whether the registrant is a large accelerated filer, an +accelerated filer, or non-accelerated file. See definition of +"accelerated filer and larger accelerated filer" in Rule 12b-2 of the Exchange +Act: +Large +accelerated filer ¨ +Accelerated +filer x +Non-accelerated +filer ¨ +Smaller +reporting company ¨ +Indicate by check mark whether the +registrant is a shell company (as defined in Rule 12b-2 of the Exchange +Act). Yes ¨ No +x +The +aggregate market value of our common stock held by non-affiliates on June 30, +2007, was $679,172,437 (based on the then closing price of $47.48). +As +of March 14, 2008, there were 14,851,234 shares of our common stock +outstanding. +DOCUMENTS +INCORPORATED BY REFERENCE +The +information required by Part III of this Form is incorporated by reference to +our definitive proxy statement to be filed pursuant to Regulation 14A for our +2008 Annual Meeting of Shareholders. +1 +PETROLEUM +DEVELOPMENT CORPORATION +2007 +ANNUAL REPORT ON FORM 10-K +TABLE OF CONTENTS +PART +I +Page +Item +1. +Business +3 +Item1A. +Risk +Factors +18 +Item1B. +Unresolved Staff +Comments +26 +Item +2. +Properties +26 +Item +3. +Legal +Proceedings +27 +Item +4. +Submission of Matters to a Vote +of Security Holders +27 +PART +II +Item +5. +Market for the Registrant’s +Common Equity, Related Stockholder Matters and Issuer Purchases of Equity +Securities +27 +Item +6. +Selected Financial +Data +30 +Item +7. +Management’s Discussion and +Analysis of Financial Condition and Results of +Operations +31 +Item +7A. +Quantitative and Qualitative +Disclosures About Market Risk +56 +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 +60 +Item +9B. +Other +Information +61 +PART +III +Item +10. +Directors, Executive Officers +and Corporate Governance +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, and Director Independence +62 +Item +14. +Principal Accounting Fees and +Services +62 +PART +IV +Item +15. +Exhibits, Financial Statement Schedules +63 +SIGNATURES +64 +GLOSSARY OF OIL AND NATURAL GAS TERMS +65 +2 +Table of Contents +PART I +REFERENCES +TO THE REGISTRANT +Unless +the context otherwise requires, references to "PDC", "the Company", "we", "us", +"our", "ours", or "ourselves" in this report refer to the registrant, Petroleum +Development Corporation, together with our subsidiaries, proportionate share of +our sponsored drilling partnerships and an entity in which we have a controlling +interest. +SPECIAL +NOTE REGARDING FORWARD-LOOKING STATEMENTS +This +report 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 regarding our business, financial condition, results of operations and +prospects. Words such as expects, anticipates, intends, plans, +believes, seeks, estimates and similar expressions or variations of such words +are intended to identify forward-looking statements herein, which include +statements of estimated oil and gas +production and reserves, drilling plans, future cash flows, anticipated +liquidity, anticipated capital expenditures and our management’s strategies, +plans and objectives. However, these are not the exclusive means of +identifying forward-looking statements herein. Although +forward-looking statements contained in this report reflect our good faith +judgment, such statements can only be based on facts and factors currently known +to us. Consequently, forward-looking statements are inherently +subject to risks and uncertainties, including risks and uncertainties incidental +to the exploration for, and the acquisition, development, production and +marketing of, natural gas and oil, and actual outcomes may differ materially +from the results and outcomes discussed in the forward-looking +statements. Important factors that could cause actual results to +differ materially from the forward looking statements include, but are not +limited to: +· +changes +in production volumes, worldwide demand, and commodity prices for +petroleum natural resources; +· +the +timing and extent of our success in discovering, acquiring, developing and +producing natural gas and oil +reserves; +· +our +ability to acquire leases, drilling rigs, supplies and services at +reasonable prices; +· +the +availability of capital to us; +· +risks +incident to the drilling and operation of natural gas and oil +wells; +· +future +production and development costs; +· +the +effect of existing and future laws, governmental regulations and the +political and economic climate of the United +States; +· +the +effect of natural gas and oil derivatives +activities; +· +conditions +in the capital markets; and +· +losses +possible from pending or future +litigation. +Further, +we urge you to carefully review and consider the disclosures made in this +report, including the risks and uncertainties that may affect our business as +described herein under Item 1A, Risk Factors , and our other +filings with the Securities and Exchange Commission, or SEC. We +caution you not to place undue reliance on forward-looking statements, which +speak only as of the date of this report. We undertake no obligation +to update publicly any forward-looking statements in order to reflect any event +or circumstance occurring after the date of this report or currently unknown +facts or conditions or the occurrence of unanticipated events. +ITEM 1. BUSINESS +General +We are an +independent energy company engaged in the exploration, development, production +and marketing of oil and natural gas. Since we began oil and gas +operations in 1969, we have grown through drilling and development activities, +acquisitions of producing natural gas and oil wells and the expansion of our +natural gas marketing activities. +As of +December 31, 2007, we owned interests in approximately 4,354 gross wells +located in the Rocky Mountain Region and the Appalachian and Michigan Basins +with 686 billion cubic feet equivalent, or Bcfe , of net proved +reserves, of which 86.6% was natural gas and 13.4% was oil. +During +2007, our share of production was 28 Bcfe, averaging 76.6 MMcfe per day, a 65% +increase over 46.4 MMcfe per day produced in 2006. We replaced our +2007 production with 391 Bcfe of new proved reserves, net of dispositions, for a +reserve replacement rate of 1,397%. Reserve replacement through the +drillbit was 256 Bcfe, or 914% of production, and reserve replacement +through acquisitions was 135 Bcfe, or 483% of production. Proved reserves grew +112% during 2007, from 323 Bcfe to 686 Bcfe, of which 54% were proved developed +reserves . +3 +Table of Contents +We make +available free of charge on our website at www.petd.com our annual +reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form +8-K, and any amendments to these reports as soon as reasonably practicable after +we electronically file these reports with, or furnish them to, the +SEC. We will also make available to any shareholder, without charge, +a copy of our Annual Report on Form 10-K, or any other filing, as filed with the +SEC, by mail. For a mailed copy of a report, you may contact +Petroleum Development Corporation, Investor Relations and Communications +Department, P.O. Box 26, Bridgeport, WV 26330, or call toll free (800) +624-3821. +In +addition to our SEC filings, other information, including our press releases, +Bylaws, Committee Charters, Code of Business Conduct and Ethics, Shareholder +Communication Policy, Board Nomination Procedures and the Whistleblower and +Qualified Legal Compliance Committee Hotline, is also available at our +website. +Business +Strategy +Our +primary objective is to continue to grow our reserves, production, net income +and cash flow. To achieve meaningful increases in these key areas, we +maintain an active drilling program that focuses on low risk development of our +oil and natural gas reserves, limited exploratory drilling and the acquisition +of producing properties with significant development potential. +Drill +and Develop +Our +acreage holdings include positions in the Rocky Mountain Region and the +Appalachian, Michigan and Fort Worth Basins. In the Rocky Mountain +Region, we focus on developmental drilling in Northeastern Colorado, or NECO, +the Wattenberg Field (both located in the DJ Basin), the Grand Valley Field, +Piceance Basin, and additional limited development in Burke County, North +Dakota. We drilled 349 gross wells in 2007, compared to 231 gross +wells in 2006. In addition, we seek to maximize the value of our +existing wells through a program of well recompletions and refractures . During +2007, we recompleted and/or refractured a total of 181 wells compared to +43 in 2006. +We +believe that we will be able to continue to drill a substantial number of new +wells on our current undeveloped properties. As of December 31, 2007, +we had leases or other development rights to approximately 200,000 acres, of +which approximately 164,000 acres, or 82%, were in the Rocky Mountain +Region. We plan to drill approximately 360 gross, 330 net, wells in +2008, excluding exploratory wells. We also plan to recomplete +approximately 100 gross Wattenberg Field wells (Colorado) and 30 +gross wells in the Appalachian Basin during 2008. To support +future development activities we have conducted exploratory drilling in the past +and will continue exploratory drilling plans in 2008. The goal of the +exploration program is to develop several significant new areas for us to +include in our future development drilling activity. +Strategically +Acquire +Our +acquisition efforts focus on producing properties that complement our existing +operations and have a significant undeveloped acreage component. When +weighing potential acquisitions, we prefer properties that have most of their +value in producing wells, behind the pipe reserves or high quality proved +undeveloped locations. Historically, acquisitions have offered +efficiency improvements through economies of scale in management and +administration costs. Since December 2006, we completed three +acquisitions of assets or companies in our core operating area of the Wattenberg +Field in Colorado, in addition to the acquisition of assets in southwestern +Pennsylvania which are in close proximity to our existing assets in the +Appalachian Basin. See Note 2 , Acquisitions , to our +consolidated financial statements included in this report. +Manage +Risk +We seek +opportunities to reduce the risk inherent to our business in the oil and natural +gas industry by focusing our drilling efforts primarily on lower risk development wells and +by maintaining positions in several different geographic regions and +markets. Historically we have concentrated on development drilling +and geographical diversification to reduce risk levels associated with natural +gas and oil drilling, production and markets. Currently, a majority +of our proved reserves are located in the Rocky Mountain Region due to our +success in that area over the past several years. However, we benefit +from operational diversity in the Rocky Mountain Region by maintaining +significant activity and production in three separate areas, including the Grand +Valley Field of the Piceance Basin in western Colorado, the Wattenberg Field in +northern Colorado and the NECO area. Additionally, we regularly +review opportunities to further diversify into other regions where we can apply +our operational expertise. We believe development drilling will +remain the foundation of our drilling activities in the future because it is +less risky than exploratory drilling and is likely to generate cash returns more +quickly. However, we expect that future activities may include a +somewhat higher level of exploratory drilling in light of the increasing cost of +accessing high-quality development opportunities and our ability, through +increased size and financial strength, to pursue exploratory activities of +greater significance. Additionally, exploratory activities have the +potential to identify new development opportunities at a cost competitive to the +current cost of acquiring proven locations. +4 +Table of Contents +To help +manage the risks associated with the oil and gas industry, we maintain a +conservative financial approach and proactively employ strategies to reduce the +effects of commodity price volatility. We have utilized asset sales +to maximize cash for acquisitions, to reduce debt and preserve our financial +flexibility. We also believe that successful oil and natural gas +marketing is essential to risk management and profitable +operations. To further this goal, we utilize Riley Natural Gas, or +RNG, a wholly-owned subsidiary, to manage the marketing of our oil and natural +gas and our use of oil and natural gas commodity derivatives as risk management +tools. This allows us to maintain better control over third party +risk in sales and derivative activities. We use oil and natural gas +derivatives contracts, or hedges, in order to reduce the effects of volatile +commodity prices. We currently have derivative contracts in place on +a significant portion of our production; however, pursuant to our derivative +policy, all volumes for derivatives contracts are limited to 80% of our +estimated production for the future periods based only on proved developed +producing production as defined in SEC reserve rules. As of March 3, +2008, we had oil and natural gas hedges in place covering 41% of our expected +oil production and 62% of our expected natural gas production in +2008. Further, while our derivative instruments are utilized to hedge +our oil and gas production, they do not qualify for use of hedge accounting +under the terms of SFAS No. 133, resulting in the potential for significant +earnings volatility. See Note 1 , Summary of Significant Accounting +Polices – Derivative Financial Instruments , to our consolidated financial +statements included in this report. +Business +Segments +We divide +our operating activities into four segments: +· +oil +and gas sales; +· +natural +gas marketing; +· +drilling +and development; and +· +well +operations and pipeline income. +See Note 17 , Business Segments , to our +consolidated financial statements. +Oil +and Gas Sales +Our oil +and gas sales segment is our fastest growing business segment and reflects +revenues and expenses from production and sale of natural gas and +oil. We have interests in approximately 4,354 wells ranging from a +few percent to 100%. During 2007, approximately 11% of our oil and +gas sales revenue was generated by the Appalachian Basin, 6% by the Michigan +Basin and 83% by Rocky Mountain Region. As of the end of 2007, our +total proved reserves were located as follows: Appalachian Basin 15%, Michigan +4% and Rocky Mountain Region 81%. The majority of our undeveloped acreage +is in the Rocky Mountain Region, where we focused our 2007 drilling +activities. This segment represents approximately 78% of our income +before income taxes for the year ended December 31, 2007. +Natural +Gas Marketing +Our +natural gas marketing segment is composed of our wholly owned subsidiary, RNG, +through which we purchase, aggregate and resell natural gas produced by us and +others. This allows us to diversify our operations beyond natural gas +drilling and production. Through RNG, we have established +relationships with many of the natural gas producers in the Appalachian Basin +and we have gained significant expertise in the natural gas end-user +market. We do not take speculative positions on commodity prices, and +we employ derivative strategies to manage the financial effects of commodity +price volatility. Our natural gas marketing segment represented +approximately 7% of our income before income taxes for the year ended December +31, 2007. +Drilling +and Development +Our +drilling and development segment reflects results of drilling and development +activities conducted for affiliated and non-affiliated +parties. Historically, we have engaged in these activities primarily +through sponsoring drilling partnerships, which allowed us to share the risks +and costs inherent in drilling and development operations with our investor +partners. In the future, we plan to evaluate the conduct of our +drilling and development operations based on a comparison of the capital costs +and risks associated with available financing alternatives. Beginning +with our third sponsored drilling partnership in 2005, we have drilled +partnership wells on a “cost-plus” basis, which means that we bill our investor +partners for the actual drilling costs plus a fixed drilling +fee. Prior to our cost-plus drilling arrangements, drilling was +conducted on a "footage" basis; where the Company bore the risk of changes in +costs. In addition, we have typically purchased a 20% to 37% working interest in +the wells developed through these partnerships. In September 2006, we +raised approximately $90 million through investor subscriptions in one drilling +partnership, and in August 2007, we raised approximately $90 million through an +additional drilling partnership. +5 +Table of Contents +Our +drilling and development segment represented approximately 18% of our income +before income taxes for the year ended December 31, 2007. In January +2008, we announced that we do not plan to sponsor new drilling partnerships in +2008 in order to focus our effort on maximizing the value of the existing +partnerships and our continuing growth through drilling and +exploration. However, a portion of the funds available for drilling +from the 2007 partnership were advanced and unexpended at the end of 2007, and +they will be used to drill wells and the associated income will be recognized in +2008. With our plans not to sponsor a drilling partnership in 2008, +we anticipate that its contribution to operating income to decline significantly +in 2008. +Well +Operations and Pipeline Income +We +operate approximately 99% of the wells in which we own a working +interest. With respect to wells in which we own an interest of less +than 100%, we charge the other working interest owners a competitive fee for +operating the well. Our well operations and pipeline income segment +represented approximately 6% of our income before income taxes for the year +ended December 31, 2007. +Areas +of Operations +We focus +our exploration, development and acquisition efforts in four geographic +regions: +· +Rocky +Mountain Region; +· +Appalachian +Basin; +· +Michigan +Basin; and +· +Fort +Worth Basin. +During +2007, we generated approximately 84.1% of our production from Rocky Mountain +Region wells, 9.8% of our production from Appalachian Basin wells, 6.1% of our +production from Michigan Basin wells. Production operations have not +commenced in the Fort Worth Basin. The majority of our undeveloped +acreage is in the Rocky Mountain Region and our current drilling plans continue +to be focused in that area. +Rocky Mountain +Region. In 1999, we began operations in the Rocky Mountain +Region, which includes our Colorado and North Dakota operations. The +region is further divided into four operating areas; (1) Grand Valley Field, (2) +Wattenberg Field, (3) NECO area and (4) North Dakota area. The Rocky +Mountain Region includes approximately 310,000 gross acres of +leasehold and approximately 2,117 oil and natural gas wells in which we own an +interest (approximately 99% are operated by us). The general details +of each area within the region are further outlined below: +· +Grand +Valley Field, Piceance Basin, Garfield County, +Colorado. We commenced operations in the area in late +1999 and currently own an interest in 225 gross, 102.9 net, natural gas +wells. Our leasehold position encompasses approximately 7,800 +gross acres with approximately 3,900 net undeveloped acres remaining for +development as of December 31, 2007. We drilled 53 gross, 41.7 +net , +wells in the area in 2007 and produced approximately 8.2 Bcfe net to our +interests. Development wells drilled in the area range from +7,000 to 9,500 feet in depth and the majority of wells are drilled +directionally from multi-well pads ranging from two to eight or more wells +per drilling pad. The primary target in the area is gas +reserves, developed from multiple sandstone reservoirs in the Mesaverde +Williams Fork formation. Well spacing is approximately ten +acres per well. +· +Wattenberg +Field, DJ Basin, Weld and Adams Counties, Colorado . We +commenced operations in the area in late 1999 and currently own an +interest in 1,242 gross, 747.6 net, oil and natural gas +wells. Our leasehold position encompasses approximately 65,000 +gross acres with approximately 13,100 net undeveloped acres remaining for +development as of December 31, 2007. We drilled 158 gross, +106.1 net, wells in the area in 2007 and produced approximately 11.1 Bcfe +net to our interests. Wells drilled in the area range from +approximately 7,000 to 8,000 feet in depth and generally target oil and +gas reserves in the Niobrara, Codell and J Sand +reservoirs. Well spacing ranges from 20 to 40 acres per +well. Operations in the area, in addition to the drilling of +new development wells, includes the refrac of Codell and Niobrara +reservoirs in existing wellbores whereby the Codell sandstone reservoir is +re-stimulated or fraced a second time and/or initial completion +attempts are made in the slightly shallower Niobrara carbonate +reservoir. +6 +Table of Contents +· +NECO area, +DJ Basin, Yuma County Colorado and Cheyenne County, +Kansas . We commenced operations in the area in 2003 and +currently own an interest in 586 gross, 383.3 net, natural gas +wells. Our leasehold position encompasses approximately 104,500 +gross acres with approximately 55,300 net undeveloped acres remaining for +development as of December 31, 2007. We drilled 123 gross, 115 +net, wells in the area in 2007 and produced approximately 3.6 Bcfe net to +our interests. Wells drilled in the area range from +approximately 1,500 to 3,000 feet in depth and target gas reserves in the +shallow Niobrara reservoir. Well spacing is approximately 40 +acres per well. New drilling operations range from exploratory +wells to test undrilled, seismically defined, structural features +at the Niobrara horizon to development wells targeting known reserves in +existing identified features. +· +North +Dakota, Burke County . We commenced operations in the +area in 2006 and currently own an interest in 13 gross, 4.6 net, oil and +natural gas wells. We divested the majority of our Bakken +project acreage in late 2007 (see Note 16 , Sale of Oil and Gas +Properties , to our consolidated financial statements included in +this report). Our remaining leasehold encompasses two project +areas in Burke County and encompasses approximately 101,300 gross acres +with approximately 60,000 net undeveloped acres remaining for development +as of December 31, 2007. The eastern area acreage is +prospective for development of oil and gas reserves in the Nesson +Formation. Nesson development wells are approximately 6,000 +feet in depth with single or multiple horizontal legs to 4,000 feet or +more in length for a measured length of 10,000 feet or more per +leg. The westernmost acreage block is undeveloped and includes +approximately 22,746 gross and 18,607 net acres. The western +project targets exploratory horizontal +drilling to the Midale/Nesson Formation at depths of approximately +6,800 feet with a lateral leg component of up to 6,100. We +drilled one unsuccessful vertical exploratory well in 2007 and anticipate +additional exploratory activity in +2008. +Appalachian +Basin. We have conducted operations in the Appalachian Basin +since our inception in 1969. We own an interest in approximately +2,027 gross, 1,501.6 net, oil and natural gas wells in West Virginia, +Pennsylvania, and Tennessee. We drilled 8 gross/net wells in the area +in 2007 and produced approximately 2.7 Bcfe net to our interests. The +majority of the West Virginia leasehold is developed on approximately 40 acre +spacing. We are currently evaluating the results of an infill +drilling project on a limited portion of our developed +leasehold. Wells located in this area are approximately 4,500 feet +deep and target predominantly gas reserves in Devonian and Mississippian aged +tight sandstone reservoirs. The majority of our 10,000 net +undeveloped acres was acquired through our Castle acquisition in October +2007. Development wells in this area target similar Devonian aged +sands as in West Virginia, at depths ranging from 3,000 to 4,500 +feet. +Michigan +Basin . We began +operations in the Michigan Basin in 1997 with the bulk of drilling activity +occurring prior to 2002. We own an interest in approximately 209 +gross, 145.6 net, oil and natural gas wells that produced 1.7 Bcfe net to our +interest in 2007. Wells in the area range from 1,000 to 2,500 feet in +depth and produce gas from the Antrim Shale. We drilled 3 gross and +net wells in 2007. +Fort Worth Basin, +Erath County, Texas . We have an +interest in approximately 10,800 gross, 8,900 net acres, in northeastern Erath +County. The leasehold acreage is prospective for the development of +oil and natural gas reserves in the Barnett Shale formation at depths of +approximately 5,000 feet. Development is typically with a horizontal +component of approximately 3,000 feet or more, resulting in an approximate +measured length of up to 8,000 feet or more in this area. As of +December 31, 2007, we have drilled one exploratory Barnett well to total +depth. The exploratory well was pending determination at December 31, +2007, see Note +4 , Properties and +Equipment - Suspended Well Costs . Completion operations have +not commenced as we are awaiting the completion of a third party gas gathering +infrastructure. +The table +below sets forth our productive wells by operating area at December 31, +2007. +Productive +Wells +Gas +Oil +Location +Gross +Net +Gross +Net +Appalachian +Basin +1,988 +1,486.2 +39 +15.4 +Michigan +Basin +202 +142.9 +7 +2.7 +Rocky +Mountain Region +Wattenberg +1,217 +728.3 +25 +19.3 +Grand +Valley +225 +102.9 +- +- +NECO +586 +383.3 +- +- +North +Dakota +4 +1.3 +9 +3.3 +Kansas +48 +47.0 +- +- +Wyoming +- +- +3 +0.7 +Total +Rocky Mountain Region +2,080 +1,262.8 +37 +23.3 +Fort +Worth Basin-Texas +1 +1.0 +- +- +Total +Productive Wells +4,271 +2,892.9 +83 +41.4 +7 +Table of Contents +Operations +Exploration +and Development Activities +Our +exploration and development activities focus on the identification and drilling +of new productive wells, the acquisition of existing producing wells from other +operator s , and maximizing the +value of our current properties through infill drilling, recompletions, and +other production enhancements. +Prospect +Generation +Our staff +of professional geologists is responsible for identifying areas with potential +for economic production of natural gas and oil. They utilize results +from logs, seismic data and other tools to evaluate existing wells and to +predict the location of economically attractive new natural gas and oil +reserves. To further this process, we have collected and continue to +collect logs, core data, production information and other raw data available +from state and private agencies, other companies and individuals actively +drilling in the regions being evaluated. From this information the +geologists develop models of the subsurface structures and formations that are +used to predict areas for prospective economic development. +On the +basis of these models, our land department obtains available natural gas and oil +leaseholds, farmouts and other development rights in these prospective +areas. In most cases, to secure a lease, we pay a lease bonus and +annual rental payments, converting, upon initiation of production, to a royalty . In +addition, overriding royalty payments may be granted to third parties in +conjunction with the acquisition of drilling rights initially leased by +others. As of December 31, 2007, we had leasehold rights to +approximately 200,000 acres available for development. +Drilling +Activities +The +following table summarizes our development and exploratory drilling activity for +the last five years. There is no correlation between the number of +productive wells completed during any period and the aggregate reserves +attributable to those wells. Productive wells consist of producing +wells and wells capable of commercial production. +2007 +2006 +2005 +Gross +Net +Gross +Net +Gross +Net +Development +Productive +(1) +327.0 +258.9 +216.0 +129.8 +232.0 +102.0 +Dry +11.0 +9.7 +6.0 +4.6 +2.0 +1.4 +Total +development +338.0 +268.6 +222.0 +134.4 +234.0 +103.4 +Exploratory +Productive (1) +1.0 +0.2 +8.0 +2.8 +3.0 +2.3 +Dry +7.0 +4.5 +1.0 +0.5 +5.0 +5.0 +Pending +determination +3.0 +3.0 +- +- +- +- +Total +exploratory +11.0 +7.7 +9.0 +3.3 +8.0 +7.3 +Total +Drilling Activity +349.0 +276.3 +231.0 +137.7 +242.0 +110.7 +(1) +As +of December 31, 2007, 128 of the 328 productive wells were awaiting gas +pipeline connection, of which 39 were connected and turned in line by +February 29, 2008. +8 +Table of Contents +The +following table sets forth the wells we drilled by operating area during the +periods indicated. +2007 +2006 +2005 +Gross +Net +Gross +Net +Gross +Net +Appalachian +Basin +8.0 +8.0 +- +- +- +- +Michigan +Basin +3.0 +3.0 +1.0 +1.0 +- +- +Rocky +Mountain Region +337.0 +264.3 +230.0 +136.7 +242.0 +110.7 +Fort +Worth Basin +1.0 +1.0 +- +- +- +- +Total +349.0 +276.3 +231.0 +137.7 +242.0 +110.7 +We plan +to drill approximately 360 gross wells, excluding exploratory wells, in +2008: 73 in the Appalachian Basin, 2 in the Michigan Basin and 285 in +the Rocky Mountain Region. +Typically, +we will act as driller-operator for these prospects, sometimes selling working +interests in the wells to Company-sponsored partnerships and other entities that +are interested in exploration or development of the prospects. We +retain a working interest in each well we drill. Occasionally, we +participate in wells as a working interest owner with another operator, +typically when we own a minority interest in the property to be +developed. +Most of +the wells we have drilled have targeted developmental natural gas reserves at +depths of less than 10,000 feet. Recently we began drilling to deeper +targets in the Rocky Mountain Region, including several wells with depths of +more than 12,000 feet and horizontal wells with a total drilled footage +approaching 20,000 feet. As wells are drilled to greater depths or +utilize more complicated and expensive drilling and completion methodologies, +they must also develop greater reserves and production to offer attractive +economics and reserves. However, the probability of encountering +problems when drilling wells at greater depths or utilizing horizontal drilling +is generally greater than when drilling a vertical well of lesser +depth. Nevertheless, with increasing costs for, and declining +availability of, proved developed drilling locations, we believe the additional +risk associated with drilling these types of prospects is justified by the +potential to generate additional proved locations and reserves at a +significantly lower cost than would be required to purchase proved undeveloped +locations. +We +drilled eleven exploratory wells in 2007: one was determined to be productive, +seven were determined to be dry, with the remaining three pending +determination. Costs of $4.2 million related to the exploratory dry +holes were expensed in 2007. We plan to conduct additional +exploratory drilling activities in 2008. See sections entitled Financing of Company Drilling and +Development Activities and Drilling and Development Activities +Conducted for Company Sponsored Partnerships below for additional +discussion regarding our drilling activities. +Much of +the work associated with drilling, completing and connecting wells, including +drilling, fracturing, logging and pipeline construction is performed under our +direction by subcontractors specializing in those operations, as is common in +the industry. When judged advantageous, material and services we use +in the development process are acquired through competitive bidding by approved +vendors. We also directly negotiate rates and costs for services and +supplies when conditions indicate that such an approach is +warranted. +Financing +of Company Drilling and Development Activities +We +conduct development drilling activities for our own account and act as operator +for other oil and gas owners. When conducting activities for our own +account, we have historically used cash flow from operations and capital +provided from our long term credit facility to fund our share of +operations. In the future, we may use other sources of funding, +including, but not limited to, asset sales, volumetric production payments, debt +securities, convertible debt securities and equity offerings. +Drilling +and Development Activities Conducted for Company Sponsored +Partnerships +In +addition to wells and interests in wells that we drill for ourselves, we also +act as operator for other oil and gas owners. Historically, these +other owners have included individuals, corporations, partnerships formed by +non-affiliated parties and other investors. We began sponsoring +drilling partnerships in 1984, and have sponsored one or more every year since +then. For many years, our drilling partners have consisted primarily +of public and private partnerships we sponsored. We contribute a cash +investment to purchase an interest in the drilling and development activities +and serve as the managing general partner for each partnership; accordingly, we +are subject to substantial cash commitments at the closing of each drilling +partnership. +In +January 2008, we announced that we do not plan to sponsor new drilling +partnerships in 2008 in order to focus our effort on continuing our growth +through drilling and exploration. However, a portion of the funds +available for drilling from the 2007 partnership were advanced and unexpended at +the end of 2007, and they will be used to drill wells and the associated income +will be recognized in 2008. +9 +Table of Contents +We +sponsored partnerships in 2007 and 2006, each with $90 million in subscriptions, +and in 2005, with $116 million in subscriptions. During 2007, we +sponsored one drilling partnership to which we contributed $38.7 million and +received a 37% working interest in the partnership. While funds were +received by us pursuant to drilling contracts in the years indicated, we +recognize revenues from drilling operations on the percentage of completion +method as the wells were drilled, rather than when funds were +received. Substantially all of our drilling and development funds +were received from partnerships in which we serve as managing general +partner. As wells produce for a number of years, we continue to serve +as operator for a number of partnerships and unaffiliated parties. +When +developing wells for our partnerships or others, we enter into a development +agreement with the investor partner, pursuant to which we agree to sell some or +all of our rights in a well to be drilled to the partnership or other +entity. The partnership or other entity thereby becomes owner of a +working interest in the well. In our financial reporting, we report +only our proportionate share of oil and gas reserves, production, oil and gas +sales and costs associated with wells in which other investors +participate. +Purchases +of Producing Properties +In +addition to drilling new wells, we continue to pursue opportunities to purchase +existing wells and development rights from other owners, as well as greater +ownership interests in the wells we operate. Generally, outside +interests purchased include a majority interest in the wells and the right to +operate the wells. In January 2007, we completed the purchase of +approximately 144 oil and gas wells and 8,160 acres of leaseholds in the +Wattenberg Field from EXCO Resources. Also in January 2007, we +purchased the outside partnership interests in 44 partnerships which we +sponsored and formed primarily in the late 1980s and 1990s. These +interests constituted the majority of the interests in 718 wells, primarily in +the Appalachian and Michigan Basins. In February 2007, we acquired +from an unrelated party 28 producing wells and associated undeveloped acreage in +Colorado. In October 2007, we purchased from unrelated parties a +majority working interest of 762 natural gas wells located in southwestern +Pennsylvania. We estimated that the acquisition included +approximately 47 Bcfe of reserves, or 31 Bcfe of proved reserves and 16 Bcfe of +unproved reserves. The purchase also included associated pipelines, +equipment, real estate and undeveloped acreage. +Production, Sales, Prices and Lifting +Costs +The +following table sets forth information regarding our production volumes, +oil and natural gas sales, average sales price received and average lifting cost +incurred for the periods indicated. +Year +Ended December 31, +2007 +2006 +2005 +Production (1) +Oil +(Bbls) +910,052 +631,395 +438,971 +Natural +gas (Mcf) +22,513,306 +13,160,784 +11,030,760 +Natural +gas equivalent (Mcfe) (2) +27,973,618 +16,949,154 +13,664,586 +Oil and Gas Sales (in +thousands) +Oil +sales +$ +55,196 +$ +37,460 +$ +22,193 +Gas +sales +119,991 +77,729 +80,366 +Total +oil and gas sales +$ +175,187 +$ +115,189 +$ +102,559 +Realized Gain (Loss) on +Derivatives, net (in thousands) +Oil +derivatives - realized (loss) gain +$ +(177 +) +$ +- +$ +(1,288) +Natural +gas derivatives - realized gain (loss) +7,350 +1,895 +(5,079) +Total +realized gain (loss) on derivatives, net +$ +7,173 +$ +1,895 +$ +(6,367) +Average +Sales Price +Oil +(per Bbl) (3) +$ +60.65 +$ +59.33 +$ +50.56 +Natural +gas (per Mcf) (3) +$ +5.33 +$ +5.91 +$ +7.29 +Natural +gas equivalent (per Mcfe) +$ +6.26 +$ +6.80 +$ +7.51 +Average +Sales Price (including realized gain (loss) on +derivatives) +Oil +(per Bbl) +$ +60.46 +$ +59.33 +$ +47.62 +Natural +gas (per Mcf) +$ +5.66 +$ +6.05 +$ +6.83 +Natural +gas equivalent (per Mcfe) +$ +6.52 +$ +6.91 +$ +7.04 +Average Production Cost +(Lifting Cost) per Mcfe (4) +$ +1.34 +$ +1.23 +$ +1.19 +10 +Table of Contents +(1) +Production +as shown in the table is net and is determined by multiplying the gross +production volume of properties in which we have an interest by the +percentage of the leasehold or other property interest we +own. +(2) +A +ratio of energy content of natural gas and oil (six Mcf of natural gas +equals one barrel of oil) was used to obtain a conversion factor to +convert oil production into equivalent Mcf of natural +gas. +(3) +We +utilize commodity based derivative instruments to manage a portion of our +exposure to price volatility of our natural gas and oil +sales. This amount excludes realized and unrealized gains and +losses on commodity based derivative +instruments. +(4) +Production +costs represent oil and gas operating expenses which include severance and +ad valorem taxes as reflected in our financial statements. See +Item 7, "Management's Discussion and Analysis of Financial Condition and +Results of Operations - Oil and Gas Production +and Well Operations Costs ." +Oil +and Natural Gas Reserves +All of +our natural gas and oil reserves are located in the United States. We +utilized the services of two independent petroleum engineers for our 2007 and +2006 independent reserve reports. Wright & Company prepared the +reserve reports for the Appalachian and Michigan Basins. Ryder Scott +Company, L.P. prepared the reserve reports for the Rocky Mountain +Region. Wright & Company prepared all of the reserve reports for +us for 2005 with the exception of our 2005 North Dakota wells which were +prepared by Ryder Scott Company, L.P. The independent engineers' +estimates are made using available geological and reservoir data as well as +production performance data. The estimates are prepared with respect +to reserve categorization, using the definitions for proved reserves set forth +in Regulation S-X, Rule 4-10(a) and subsequent SEC staff interpretations and +guidance. When preparing our reserve estimates, the independent +engineers did not independently verify the accuracy and completeness of +information and data furnished by us with respect to ownership interests, oil +and natural gas production, well test data, historical costs of operations and +developments, product prices, or any agreements relating to current and future +operations of properties and sales of production. Our independent +reserve estimates are reviewed and approved by our internal engineering staff +and management. +The +tables below set forth information as of December 31, 2007, regarding our +estimated proved reserves. Reserves cannot be measured exactly, +because reserve estimates involve subjective judgment. The estimates +must be reviewed periodically and adjusted to reflect additional information +gained from reservoir performance, new geological and geophysical data and +economic changes. Neither the present value of estimated future net +cash flows nor the standardized measure is intended to represent the current +market value of the estimated oil and natural gas reserves we own. +December +31, 2007 +Oil +(MBbl) +Gas +(MMcf) +Total +(MMcfe) +Proved +developed +8,927 +314,123 +367,685 +Proved +undeveloped +6,411 +279,440 +317,906 +Total +Proved +15,338 +593,563 +685,591 +Proved +Developed +Proved +Undeveloped +Total +Proved +(in +millions) +Estimated +future net cash flows (1) +$ +1,203 +$ +644 +$ +1,847 +Standardized +measure +(1)(2) +600 +153 +753 +(1) +Estimated +future net cash flow represents the estimated future gross revenue to be +generated from the production of proved reserves, net of estimated +production costs, future development costs and income tax expense, using +prices and costs in effect at December 31, 2007. The prices +used in our reserve reports yield weighted average wellhead prices of +$80.67 per barrel of oil and $6.77 per Mcf of natural +gas. These prices should not be interpreted as a prediction of +future prices, nor do they reflect the value of our commodity hedges in +place at December 31, 2007. The amounts shown do not give +effect to non-property related expenses, such as corporate general and +administrative expenses and debt service, or to depreciation, depletion +and amortization. +(2) +The +standardized +measure of discounted future net cash flows is calculated in +accordance with Statement of Financial Accounting Standards (“SFAS”) No. +69, which requires the future cash flows to be discounted. The +discount rate used was 10%. Additional information on this +measure is presented in Note 20 , +"Supplemental Oil and Gas Information," of our consolidated financial +statements included in this report. +11 +Table of Contents +December +31, 2007 +Oil +(MBbl) +Gas +(MMcf) +Gas +Equivalent (MMcfe) +Percent +Proved +developed +Appalachian +Basin +34 +80,355 +80,559 +22 +% +Michigan +Basin +58 +23,979 +24,327 +7 +% +Rocky +Mountain Region +Wattenberg +8,473 +67,227 +118,065 +32 +% +Grand +Valley +107 +91,326 +91,968 +25 +% +NECO +- +50,942 +50,942 +14 +% +North +Dakota +250 +294 +1,794 +0 +% +Wyoming +5 +- +30 +0 +% +Total +Rocky Mountain Region +8,835 +209,789 +262,799 +71 +% +Total +proved developed +8,927 +314,123 +367,685 +100 +% +Proved +undeveloped +Appalachian +- +22,115 +22,115 +7 +% +Rocky +Mountain Region +Wattenberg +6,210 +40,729 +77,989 +24 +% +Grand +Valley +201 +200,998 +202,204 +64 +% +NECO +- +15,598 +15,598 +5 +% +Total +Rocky Mountain Region +6,411 +257,325 +295,791 +93 +% +Total +proved undeveloped +6,411 +279,440 +317,906 +100 +% +Proved +reserves +Appalachian +34 +102,470 +102,674 +15 +% +Michigan +58 +23,979 +24,327 +4 +% +Rocky +Mountain Region +Wattenberg +14,683 +107,956 +196,054 +28 +% +Grand +Valley +308 +292,324 +294,172 +43 +% +NECO +- +66,540 +66,540 +10 +% +North +Dakota +250 +294 +1,794 +0 +% +Wyoming +5 +- +30 +0 +% +Total +Rocky Mountain Region +15,246 +467,114 +558,590 +81 +% +Total +proved reserves +15,338 +593,563 +685,591 +100 +% +Acreage +The +following table sets forth by operating area leased acres as of December 31, +2007. +Developed +Undeveloped +Total +Location +Gross +Net +Gross +Net +Gross +Net +Appalachian +Basin +84,240 +84,240 +10,000 +10,000 +94,240 +94,240 +Michigan +Basin +8,240 +8,240 +440 +440 +8,680 +8,680 +New +York +- +- +19,500 +16,575 +19,500 +16,575 +Rocky +Mountain Region +Wattenberg +50,860 +47,440 +14,093 +13,143 +64,953 +60,583 +Grand +Valley +2,994 +2,994 +3,900 +3,900 +6,894 +6,894 +NECO +26,392 +18,680 +78,147 +55,320 +104,539 +74,000 +North +Dakota +7,453 +4,767 +93,814 +59,972 +101,267 +64,739 +Wyoming +- +- +31,945 +31,945 +31,945 +31,945 +Total +Rocky Mountain Region +87,699 +73,881 +221,899 +164,280 +309,598 +238,161 +Fort +Worth Basin +- +- +10,804 +8,868 +10,804 +8,868 +Total +Acreage +180,179 +166,361 +262,643 +200,163 +442,822 +366,524 +Title +to Properties +We +believe that we hold good and defensible title to our developed properties, in +accordance with standards generally accepted in the oil and natural gas +industry. As is customary in the industry, a perfunctory title +examination is conducted at the time the undeveloped properties are +acquired. Prior to the commencement of drilling operations, a title +examination is conducted and curative work is performed with respect to +discovered defects which we deem to be significant. Title +examinations have been performed with respect to substantially all of our +producing properties. Two properties in our Grand Valley Field +represent 43% of our total proved reserves. +12 +Table of Contents +The +properties we own are subject to royalty, overriding royalty and other +outstanding interests customary to the industry. The properties may +also be subject to additional burdens, liens or encumbrances customary to the +industry, including items such as operating agreements, current taxes, +development obligations under natural gas and oil leases, farm-out agreements +and other restrictions. We do not believe that any of these burdens +will materially interfere with the use of the properties. +Natural +Gas Sales +We +generally sell the natural gas that we produce under contracts with monthly +pricing provisions. Virtually all of our contracts include provisions +wherein prices change monthly with changes in the market, for which certain +adjustments may be made based on whether a well delivers to a gathering or +transmission line, quality of natural gas and prevailing supply and demand +conditions, so that the price of the natural gas fluctuates to remain +competitive with other available natural gas supplies. As a result, +our revenues from the sale of natural gas will suffer if market prices decline +and benefit if they increase. We believe that the pricing provisions +of our natural gas contracts are customary in the industry. We also +enter into financial derivatives such as puts, collars, or swaps in order to +protect against possible price instability regarding the physical sales +market. +We +sell our natural gas to industrial end-users, utilities, other gas marketers, +and other wholesale gas purchasers. During 2007, the natural gas we +produce was sold at prices ranging from $1.68 to $18.56 per Mcf, depending upon +well location, the date of the sales contract and other factors. Our +weighted net average price of natural gas sold in 2007 was $5.33 per +Mcf. +In +general, we, together with our marketing subsidiary, RNG, have been and expect +to continue to be able to produce and sell natural gas from our wells without +significant curtailment and at competitive prices. We do experience +limited curtailments from time to time due to pipeline maintenance and operating +issues, and during October 2007, we chose to curtail some of our Piceance Basin +production due to low prices. Open access transportation through the +country's interstate pipeline system gives us access to a broad range of +markets. Whenever feasible, we obtain access to multiple pipelines +and markets from each of our gathering systems seeking the best available market +for our natural gas at any point in time. +Oil +Sales +The +majority of our wells in the Wattenberg Field in Colorado and our wells in North +Dakota produce oil in addition to natural gas. As of December 31, +2007, oil represented 13.4% of our total equivalent reserves and accounted for +approximately 31.5% of our oil and gas sales revenue for the year ended December +31, 2007. +We are +currently able to sell all the oil that we can produce under existing sales +contracts with petroleum refiners and marketers. We do not refine any +of our oil production. Our crude oil production is sold to purchasers +at or near our wells under both short and long-term purchase contracts with +monthly pricing provisions. During 2007, oil we produced sold at +prices ranging from $41.03 to $76.03 per barrel, depending upon the location and +quality of oil. Our weighted net average price per barrel of oil sold +in 2007 was $60.65. +Natural +Gas Marketing +Our +natural gas marketing activities involve the purchase of natural gas from other +producers and the sale of that natural gas along with the natural gas we +produce. We believe that in a deregulated market, successful natural +gas marketing is an essential component of profitable operations. A +variety of factors affect the market for natural gas, including: +· +the +availability of other domestic +production; +· +natural +gas imports; +· +the +availability and price of alternative +fuels; +· +the +proximity and capacity of natural gas +pipelines; +· +general +fluctuations in the supply and demand for natural gas; +and +· +the +effects of state and federal regulations on natural gas production and +sales. +The +natural gas industry also competes with other industries in supplying the energy +and fuel requirements of industrial, commercial and individual +customers. +13 +Table of Contents +RNG, our +wholly owned subsidiary, is a natural gas marketing company that specializes in +the purchase, aggregation and sale of natural gas production in our Eastern +operating areas. RNG markets the natural gas we produce and also +purchases natural gas in the Appalachian Basin from other producers and resells +it to utilities, end users or other marketers. RNG's employees have +extensive knowledge of natural gas markets in our areas of +operations. Such knowledge assists us in maximizing our prices as we +market natural gas from PDC-operated wells. The gas is marketed to +natural gas utilities, industrial and commercial customers as well as other +marketers, either directly through our gathering system, or through +transportation services provided by regulated interstate pipeline +companies. +Commodity +Risk Management Activities +We +utilize commodity based derivative instruments to manage a portion of the +exposure to price volatility stemming from our oil and natural gas sales and +marketing activities. These instruments consist of over-the-counter +swaps, NYMEX -traded natural +gas futures and option contracts for Appalachian and Michigan production, +Colorado Interstate Gas Index, or CIG, and Panhandle Eastern Pipeline-based +contracts for Colorado natural gas production and NYMEX-traded oil futures and +option contracts for Colorado oil production. We may utilize +derivatives based on other indices or markets where appropriate. The +contracts economically provide price protection for committed and anticipated +oil and natural gas purchases and sales, generally forecasted to occur within +the next two- to three-year period. Our policies prohibit the use of +oil and natural gas futures, swaps or options for speculative purposes and +permit utilization of derivatives only if there is an underlying physical +position. +RNG has +extensive experience with the use of cash-settled derivatives to reduce the risk +and effect of natural gas price changes. RNG uses these financial +derivatives to coordinate fixed purchases and sales. We use financial +derivatives to establish "floors" and "ceilings" or "collars" on the possible +range of the prices realized for the sale of natural gas and oil. RNG +also enters into back-to-back fixed-price purchases and sales contracts with +counterparties. These fixed physical contracts meet the SFAS No. 133, +Accounting for Derivative +Instruments and Certain Hedging Activities , definition of a +derivative. Both types of derivatives (i.e., the physical deals and +the cash settled contracts) are carried on the balance sheet at fair value with +changes in fair values recognized currently in the income +statement. +We are +subject to price fluctuations for natural gas sold in the spot market and under +market index contracts. We continue to evaluate the potential for +reducing these risks by entering into derivative transactions. In +addition, we may close out any portion of derivatives that may exist from time +to time which may result in a realized gain or loss on that derivative +transaction. We manage price risk on only a portion of our +anticipated production, so the remaining portion of our production is subject to +the full fluctuation of market pricing. +Well +Operations +At +December 31, 2007, we had an interest in approximately 2,117 wells in the Rocky +Mountain Region, 2,027 wells in the Appalachian Basin, and 209 wells in the +Michigan Basin. Our ownership interest in these wells range up to +100% and as of December 31, 2007, on average, we had approximately 67.4% +ownership interest in the wells we operated. +We are +paid a monthly operating fee for the portion of each well we operate that is +owned by others, including our sponsored partnerships. The fee is +competitive with rates charged by other operators in the area. The +fee covers monthly operating and accounting costs, insurance and other recurring +costs. We may also receive additional compensation, at competitive +rates, for special non-recurring activities, such as reworks and +recompletions. If we purchase well interests belonging to investors +in the partnerships, we then account for the purchased interests as being owned +by us, which results in a decrease in well operations income. As of +December 31, 2007, we operate approximately 99% of the wells in which we own a +working interest. +Transportation +Natural +gas wells are connected by pipelines to natural gas markets. Over the +years, we have developed, own and operate gathering systems in some of our areas +of operations. We also continue to construct new trunk lines as +necessary to provide for the marketing of natural gas being developed from new +areas and to enhance or maintain our existing systems. Pipelines and +related facilities can represent a significant portion of the capital costs of +developing wells, particularly in new areas located at a distance from existing +pipelines. We consider these costs in our evaluation of our leasing, +development and acquisition opportunities. +14 +Table of Contents +Governmental +Regulation +While the +prices of oil and natural gas are set by the market, other aspects of our +business and the oil and natural gas industry in general are heavily +regulated. The availability of a ready market for oil and natural gas +production depends on several factors beyond our control. These +factors include regulation of production, federal and state regulations +governing environmental quality and pollution control, the amount of oil and +natural gas available for sale, the availability of adequate pipeline and other +transportation and processing facilities and the marketing of competitive +fuels. State and federal regulations generally are intended to +protect consumers from unfair treatment and oppressive control, to reduce the +risk to the public and workers from the drilling, completion, production and +transportation of oil and natural gas, to prevent waste of oil and natural gas, +to protect rights to between owners in a common reservoir and to control +contamination of the environment. Pipelines are subject to the +jurisdiction of various federal, state and local agencies. In the +western part of the United States, the federal and state governments own a large +percentage of the land and the rights to develop oil and natural +gas. Recently, we have increased our positions in these types of +leases. Generally, government leases are subject to additional +regulations and controls not commonly seen on private leases. We take +the steps necessary to comply with applicable regulations, both on our own +behalf and as part of the services we provide to our drilling +partnerships. We believe that we are in compliance with such +statutes, rules, regulations and governmental orders, although there can be no +assurance that this is or will remain the case. The following summary +discussion of the regulation of the United States oil and natural gas industry +is not intended to constitute a complete discussion of the various statutes, +rules, regulations and environmental orders to which our operations may be +subject. +Regulation +of Oil and Natural Gas Exploration and Production +Our +exploration and production business is subject to various federal, state and +local laws and regulations on taxation, the development, production and +marketing of oil and gas and environmental and safety matters. Many +laws and regulations require drilling permits and govern the spacing of wells, +rates of production, water discharge, prevention of waste and other +matters. Prior to commencing drilling activities for a well, we must +procure permits and/or approvals for the various stages of the drilling process +from the applicable state and local agencies in the state in which the area to +be drilled is located. The permits and approvals include those for +the drilling of wells. Also, regulated matters include: +· +bond +requirements in order to drill or operate +wells; +· +the +location of wells; +· +the +method of drilling and casing +wells; +· +the +surface use and restoration of well +properties; +· +the +plugging and abandoning of wells; +and +· +the +disposal of fluids. +Our +operations are also subject to various conservation laws and +regulations. These include the regulation of the size of drilling and +spacing units or proration units, the density of wells which may be drilled and +the unitization or pooling of properties. In this regard, some states +allow the forced pooling or integration of tracts to facilitate exploration +while other states rely primarily or exclusively on voluntary pooling of lands +and leases. In areas where pooling is voluntary, it may be more +difficult to form units, and therefore, more difficult to develop a project if +the operator owns less than 100% of the leasehold. In addition, state +conservation laws may establish maximum rates of production from oil and natural +gas wells, generally prohibiting the venting or flaring of natural gas and +imposing certain requirements regarding the ratability of +production. Where wells are to be drilled on state or federal leases, +additional regulations and conditions may apply. The effect of these +regulations may limit the amount of oil and natural gas we can produce from our +wells and may limit the number of wells or the locations at which we can +drill. Such laws and regulations may increase the costs of planning, +designing, drilling, installing, operating and abandoning our oil and natural +gas wells and other facilities. In addition, these laws and +regulations, and any others that are passed by the jurisdictions where we have +production, could limit the total number of wells drilled or the allowable +production from successful wells, which could limit our reserves. As +a result, we are unable to predict the future cost or effect of complying with +such regulations. +Regulation +of Sales and Transportation of Natural Gas +Historically, +the price of natural gas was subject to limitation by federal +legislation. The Natural Gas Wellhead Decontrol Act removed, as of +January 1, 1993, all remaining federal price controls from natural gas sold in +"first sales" on or after that date. The Federal Energy Regulatory +Commission's, or FERC, jurisdiction over natural gas transportation was +unaffected by the Decontrol Act. While sales by producers of natural +gas and all sales of crude oil, condensate and natural gas liquids +can currently be made at market prices, there are a number of proposed bills in +the United States Congress to reenact price controls or impose “windfall +profits” or similar taxes in the future on oil and natural gas +prices. The passage of one of those bills or similar legislation +could have the effect of reducing the price we receive for our production, or +substantially increasing the tax burden associated with our production +operations. +15 +Table of Contents +We move +natural gas through pipelines owned by other companies, and sell natural gas to +other companies that also utilize common carrier pipeline +facilities. Natural gas pipeline interstate transmission and storage +activities are subject to regulation by the FERC under the Natural Gas Act of +1938, or NGA, and under the Natural Gas Policy Act of 1978, and, as such, rates +and charges for the transportation of natural gas in interstate commerce, +accounting, and the extension, enlargement or abandonment of its jurisdictional +facilities, among other things, are subject to regulation. Each +natural gas pipeline company holds certificates of public convenience and +necessity issued by the FERC authorizing ownership and operation of all +pipelines, facilities and properties for which certificates are required under +the NGA. Each natural gas pipeline company is also subject to the +Natural Gas Pipeline Safety Act of 1968, as amended, which regulates safety +requirements in the design, construction, operation and maintenance of +interstate natural gas transmission facilities. FERC regulations +govern how interstate pipelines communicate and do business with their +affiliates. Interstate pipelines may not operate their pipeline +systems to preferentially benefit their marketing affiliates. +Each +interstate natural gas pipeline company establishes its rates primarily through +the FERC’s ratemaking process. Key determinants in the ratemaking +process are: +· +costs +of providing service, including depreciation +expense; +· +allowed +rate of return, including the equity component of the capital structure +and related income taxes; and +· +volume +throughput assumptions. +The +availability, terms and cost of transportation affect our natural gas +sales. In the past, FERC has undertaken various initiatives to +increase competition within the natural gas industry. As a result of +initiatives like FERC Order No. 636, issued in April 1992, the interstate +natural gas transportation and marketing system was substantially restructured +to remove various barriers and practices that historically limited non-pipeline +natural gas sellers, including producers, from effectively competing with +interstate pipelines for sales to local distribution companies and large +industrial and commercial customers. The most significant provisions +of Order No. 636 require that interstate pipelines provide transportation +separate or "unbundled" from their sales service, and require that pipelines +provide firm and interruptible transportation service on an open access basis +that is equal for all natural gas suppliers. In many instances, the +result of Order No. 636 and related initiatives has been to substantially reduce +or eliminate the interstate pipelines' traditional role as wholesalers of +natural gas in favor of providing only storage and transportation +services. Another effect of regulatory restructuring is greater +access to transportation on interstate pipelines. In some cases, +producers and marketers have benefited from this +availability. However, competition among suppliers has greatly +increased and traditional long-term producer-pipeline contracts are +rare. Furthermore, gathering facilities of interstate pipelines are +no longer regulated by FERC, thus allowing gatherers to charge higher gathering +rates. +Additional +proposals and proceedings that might affect the natural gas industry occur +frequently in Congress, FERC, state commissions, state legislatures, 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 FERC and Congress will continue. We +cannot determine to what extent our future operations and earnings will be +affected by new legislation, new regulations, or changes in existing regulation, +at federal, state or local levels. +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. Public interest in the protection of the environment has +increased dramatically in recent years. The trend of more expansive +and tougher environmental legislation and regulations could +continue. To the extent laws are enacted or other governmental action +is taken that restricts drilling or imposes environmental protection +requirements that result in increased costs and reduced access to the natural +gas industry in general, our business and prospects could be adversely +affected. +We +generate wastes that may be subject to the Federal Resource Conservation and +Recovery Act, or RCRA, and comparable state statutes. The U.S. +Environmental Protection Agency, or EPA, and various state agencies have limited +the approved methods of disposal for certain hazardous and non-hazardous +wastes. Furthermore, certain wastes generated by our operations that +are currently exempt from treatment as "hazardous wastes" may in the future be +designated as "hazardous wastes," and therefore be subject to more rigorous and +costly operating and disposal requirements. +We +currently own or lease numerous properties that for many years have been used +for the exploration and production of oil and natural gas. Although +we believe that we have utilized good operating and waste disposal practices, +and when necessary, appropriate remediation techniques, prior owners and +operators of these properties may not have utilized similar practices and +techniques, and hydrocarbons or other wastes may have been disposed of or +released on or under the properties that we own or lease or on or under +locations where such wastes have been taken for disposal. These +properties and the wastes disposed thereon may be subject to the Comprehensive +Environmental Response, Compensation and Liability Act, or CERCLA, RCRA and +analogous state laws, as well as state laws governing the management of oil and +natural gas wastes. Under such laws, 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) or to perform remedial plugging operations to prevent +future contamination. +16 +Table of Contents +CERCLA +and similar state laws impose liability, without regard to fault or the legality +of the original conduct, on certain classes of persons that are considered to +have contributed to the release of a "hazardous substance" into the +environment. These persons include the owner or operator of the +disposal site or sites where the release occurred and companies that disposed of +or arranged for the disposal of the hazardous substances found at the +site. Persons who are or were responsible for release of hazardous +substances under CERCLA may be subject to full liability for the costs of +cleaning up the hazardous substances that have been released into the +environment and for damages to natural resources, and 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. As an owner and operator of oil and natural gas +wells, we may be liable pursuant to CERCLA and similar state laws. +Our +operations may be subject to the Clean Air Act, or CAA, and comparable state and +local requirements. Amendments to the CAA were adopted in 1990 and +contain provisions that may result in the gradual imposition of certain +pollution control requirements with respect to air emissions from our +operations. The EPA and states have been developing regulations to +implement these requirements. We may be required to incur certain +capital expenditures in the next several years for air pollution control +equipment in connection with maintaining or obtaining operating permits and +approvals addressing other air emission-related issues. The state of +Colorado has also indicated it intends to implement new air regulations later in +2008 which affect the oil and gas industry, including our operations, related to +air emissions and wildlife. +The +Federal Clean Water Act, or CWA, and analogous state laws impose strict controls +against the discharge of pollutants, including spills and leaks of oil and other +substances. The CWA also regulates storm water run-off from oil and +gas facilities and requires a storm water discharge permit for certain +activities. Spill prevention, control, and countermeasure +requirements of the CWA require appropriate containment terms and similar +structures to help prevent the contamination of navigable waters in the event of +a petroleum hydrocarbon tank spill, rupture, or leak. +Oil +production is subject to many of the same operating hazards and environmental +concerns as natural gas production, but is also subject to the risk of oil +spills. Federal regulations require certain owners or operators of +facilities that store or otherwise handle oil, including us, to procure and +implement Spill Prevention, Control and Counter-measures plans relating to the +possible discharge of oil into surface waters. The Oil Pollution Act +of 1990, or OPA, subjects owners of facilities to strict joint and several +liability for all containment and cleanup costs and certain other damages +arising from oil spills. Noncompliance with OPA may result in varying +civil and criminal penalties and liabilities. We are also subject to +the CWA and analogous state laws relating to the control of water pollution, +which laws provide varying civil and criminal penalties and liabilities for +release of petroleum or its derivatives into surface waters or into the +ground. Historically, we have not experienced any significant oil +discharge or oil spill problems. +Our +expenses relating to preserving the environment during 2007 were not significant +in relation to operating costs and we expect no material change in +2008. Environmental regulations have had no materially adverse effect +on our operations to date, but no assurance can be given that environmental +regulations will not, in the future, result in a curtailment of production or +otherwise have a materially adverse effect on our business, financial condition +or results of operations. +Operating +Hazards and Insurance +Our +exploration and production operations include a variety of operating risks, +including the risk of fire, explosions, blowouts, cratering, pipe failure, +casing collapse, abnormally pressured formations, and environmental hazards such +as gas leaks, ruptures and discharges of toxic gas. The occurrence of +any of these could result in substantial losses to us due to injury and loss of +life, severe damage to and destruction of property, natural resources and +equipment, pollution and other environmental damage, clean-up responsibilities, +regulatory investigation and penalties and suspension of +operations. Our pipeline, gathering and distribution operations are +subject to the many hazards inherent in the natural gas +industry. These hazards include damage to wells, pipelines and other +related equipment, damage to property caused by hurricanes, floods, fires and +other acts of God, inadvertent damage from construction equipment, leakage of +natural gas and other hydrocarbons, fires and explosions and other hazards that +could also result in personal injury and loss of life, pollution and suspension +of operations. +Any +significant problems related to our facilities could adversely affect our +ability to conduct our operations. In accordance with customary +industry practice, we maintain insurance against some, but not all, potential +risks; however, there can be no assurance that such insurance will be adequate +to cover any losses or exposure for liability. The occurrence of a +significant event not fully insured against could materially adversely affect +our operations and financial condition. We cannot predict whether +insurance will continue to be available at premium levels that justify our +purchase or whether insurance will be available at all. Furthermore, +we are not insured against our economic losses resulting from damage or +destruction to third party property, such as the Rockies Express pipeline; such +an event could result in significantly lower regional prices or our inability to +deliver gas. +17 +Table of Contents +Competition +We +believe that our exploration, drilling and production capabilities and the +experience of our management and professional staff generally enable us to +compete effectively. We encounter competition from numerous other oil +and natural gas companies, drilling and income programs and partnerships in all +areas of operations, including drilling and marketing oil and natural gas and +obtaining desirable oil and natural gas leases on producing +properties. Many of these competitors possess larger staffs and +greater financial resources than we do, which may enable them to identify and +acquire desirable producing properties and drilling prospects more +economically. Our ability to explore for oil and natural gas +prospects and to acquire additional properties in the future depends upon our +ability to conduct our operations, to evaluate and select suitable properties +and to consummate transactions in this highly competitive +environment. We also face intense competition in the marketing of +natural gas from competitors including other producers as well as marketing +companies. Also, international developments and the possible improved +economics of domestic natural gas exploration may influence other companies to +increase their domestic oil and natural gas exploration. Furthermore, +competition among companies for favorable prospects can be expected to continue, +and it is anticipated that the cost of acquiring properties may increase in the +future. During 2007, our industry experienced continued strong demand +for drilling services and supplies. This is resulting in increasing +costs, and in some cases the demand for supplies and services exceeds the +available supplies. This can result in higher well costs and delays +in the execution of planned drilling operations. Factors affecting +competition in the oil and natural gas industry include price, location of +drilling, availability of drilling prospects and drilling rigs, pipeline +capacity, quality of production and volumes produced. We believe that +we can compete effectively in the oil and natural gas industry in each of the +listed areas. Nevertheless, our business, financial condition and +results of operations could be materially adversely affected by +competition. We also compete with other oil and gas companies as well +as companies in other industries for the capital we need to conduct our +operations. Recently, turmoil in the capital markets has made capital +more expensive and difficult to obtain. In the event that we do not +have adequate capital to execute our business plan, we may be forced to curtail +our drilling and acquisition activities. +Employees +As of +December 31, 2007, we had 256 employees, including 164 in production, 7 in +natural gas marketing, 26 in exploration and development, 37 in finance, +accounting and data processing, and 22 in administration. Our +engineers, supervisors and well tenders are responsible for the day-to-day +operation of wells and pipeline systems. In addition, we retain +subcontractors to perform drilling, fracturing, logging, and pipeline +construction functions at drilling sites, with our employees supervising the +activities of the subcontractors. In 2007, the total number of +Company employees increased by 67. +Our +employees are not covered by a collective bargaining agreement. We +consider relations with our employees to be excellent. +ITEM 1A. RISK FACTORS +You +should carefully consider the following risk factors in addition to the other +information included in this report. Each of these risk factors could +adversely affect our business, operating results and financial condition, as +well as adversely affect the value of an investment in our common stock or other +securities. +Risks +Related to Our Business and the Natural Gas and Oil Industry +Our +"material weaknesses" in our internal control over financial reporting and +resulting ineffective disclosure controls and procedures could have a material +adverse effect on the reliability of our financial statements and our ability to +file public reports on time, raise capital and meet our debt +obligations. +Our +management assessed the effectiveness of our internal control over financial +reporting as of December 31, 2007, and pursuant to this assessment, identified +two material weaknesses in our internal control over financial reporting. The +existence of any material weaknesses means there is a deficiency, or a +combination of deficiencies, in internal control over financial reporting, such +that there is a reasonable possibility that a material misstatement of our +annual or interim financial statements will not be prevented or detected on a +timely basis. The two material weaknesses relate to our failure to +maintain effective controls over some of our key financial statement +spreadsheets that support all significant balance sheet and income statement +accounts and our failure to ensure proper accounting for derivative +activities. For a more detailed discussion of our material +weaknesses, see Item 8, Management's Report on Internal +Control over Financial Reporting , and Item 9A, Controls and Procedures of +this report. As a result of these material weaknesses, our management +concluded that our disclosure controls and procedures were not effective as of +December 31, 2007. +18 +Table of Contents +Failure +to maintain effective internal control over financial reporting and/or effective +disclosure controls and procedures could prevent us from being able to prevent +fraud and/or provide reliable financial statements and other public +reports. Such circumstances could harm our business and operating +results, cause investors to lose confidence in the accuracy and completeness of +our financial statements and reports, and have a material adverse effect on the +trading price of our debt and equity securities and our ability to raise capital +necessary for our operations. These failures may also adversely +affect our ability to file our periodic reports with the SEC on +time. Being late in filing our periodic reports with the +SEC may result in the delisting of our common stock from the NASDAQ +Stock Market or a default under our senior credit agreement, the indenture +governing our outstanding 12% senior notes due 2018, and any other +instruments governing debt that we may incur in the +future. Ultimately, such defaults could lead to the acceleration of +our debt obligations, and if an acceleration of our debt obligations were to +occur, we would probably not have sufficient funds to repay those obligations +immediately, and we would be forced to seek alternative repayment arrangements +either through a bankruptcy or an out of court debt +restructuring. Consequently, our material weaknesses could lead to +significant and negative changes to our financial condition and the value of our +equity and debt securities. +Natural +gas and oil prices fluctuate unpredictably and a decline in natural gas and oil +prices can significantly affect the value of our assets, our financial results +and impede our growth. +Our +revenue, profitability and cash flow depend in large part upon the prices and +demand for natural gas and oil. The markets for these commodities are +very volatile, and even relatively modest drops in prices can significantly +affect our financial results and impede our growth. Changes in +natural gas and oil prices have a significant effect on our cash flow and on the +value of our reserves, which can in turn reduce our borrowing base under our +senior credit agreement. Prices for natural gas and oil may fluctuate +widely in response to relatively minor changes in the supply of and demand for +natural gas and oil, market uncertainty and a variety of additional factors that +are beyond our control, including national and international economic and +political factors and federal and state legislation. +The +prices of natural gas and oil are volatile, often fluctuating +greatly. Lower natural gas and oil prices may not only reduce our +revenues, but also may reduce the amount of natural gas and oil that we can +produce economically. As a result, we may have to make substantial +downward adjustments to our estimated proved reserves. If this occurs +or if our estimates of development costs increase, production data factors +change or our exploration results deteriorate, accounting rules may require us +to write-down operating assets to fair value, as a non-cash charge to +earnings. We assess impairment of capitalized costs of proved natural +gas and oil properties by comparing net capitalized costs to estimated +undiscounted future net cash flows on a field-by-field basis using estimated +production based upon prices at which management reasonably estimates such +products may be sold. In 2006, we recorded an impairment charge of +$1.5 million related to our Nesson field in North Dakota. There were +no impairments during 2007 or 2005. We may incur impairment charges +in the future, which could have a material adverse effect on the results of our +operations. +A +substantial part of our natural gas and oil production is located in the Rocky +Mountain Region, making it vulnerable to risks associated with operating in a +single major geographic area. +Our +operations have been focused on the Rocky Mountain Region, which means our +current producing properties and new drilling opportunities are geographically +concentrated in that area. Because our operations are not as +diversified geographically as many of our competitors, the success of our +operations and our profitability may be disproportionately exposed to the effect +of any regional events, including fluctuations in prices of natural gas and oil +produced from the wells in the region, natural disasters, restrictive +governmental regulations, transportation capacity constraints, curtailment of +production or interruption of transportation, and any resulting delays or +interruptions of production from existing or planned new wells. +During +the second half of 2007, natural gas prices in the Rocky Mountain Region have +fallen disproportionately when compared to other markets, due in part to +continuing constraints in transporting natural gas from producing properties in +the region. Because of the concentration of our operations in the +Rocky Mountain Region, such price decreases are more likely to have a material +adverse effect on our revenue, profitability and cash flow than those of our +more geographically diverse competitors. +Our +estimated natural gas and oil reserves are based on many assumptions that may +turn out to be inaccurate. Any material inaccuracies in these reserve +estimates or underlying assumptions may materially affect the quantities and +present value of our reserves. +No one +can measure underground accumulations of natural gas and oil in an exact +way. Natural gas and oil reserve engineering requires subjective +estimates of underground accumulations of natural gas and oil and assumptions +concerning future natural gas and oil prices, production levels, and operating +and development costs over the economic life of the properties. As a +result, estimated quantities of proved reserves and projections of future +production rates and the timing of development expenditures may be +inaccurate. Independent petroleum engineers prepare our estimates of +natural gas and oil reserves using pricing, production, cost, tax and other +information that we provide. The reserve estimates are based on +certain assumptions regarding future natural gas and oil prices, production +levels, and operating and development costs that may prove +incorrect. Any significant variance from these assumptions to actual +figures could greatly affect: +19 +Table of Contents +· +the +estimates of reserves; +· +the +economically recoverable quantities of natural gas and oil attributable to +any particular group of properties; +· +future +depreciation, depletion and amortization rates and +amounts; +· +the +classifications of reserves based on risk of recovery; +and +· +estimates +of the future net cash flows. +Some of +our reserve estimates must be made with limited production history, which +renders these reserve estimates less reliable than estimates based on a longer +production history. Numerous changes over time to the assumptions on +which the reserve estimates are based, as described above, often result in the +actual quantities of natural gas and oil recovered being different from earlier +reserve estimates. +The +present value of our estimated future net cash flows from proved reserves is not +necessarily the same as the current market value of our estimated natural gas +and oil reserves (the SEC requires the use of year end prices). The +estimated discounted future net cash flows from proved reserves are based on +selling prices in effect on the day of estimate (year end). However, +factors such as actual prices we receive for natural gas and oil and hedging +instruments, the amount and timing of actual production, amount and timing of +future development costs, supply of and demand for natural gas and oil, and +changes in governmental regulations or taxation also affect our actual future +net cash flows from our natural gas and oil properties. +The +timing of both our production and incurrence of expenses in connection with the +development and production of natural gas and oil properties will affect the +timing of actual future net cash flows from proved reserves, and thus their +actual present value. In addition, the 10% discount factor (the rate +required by the SEC) we use when calculating discounted future net cash flows +may not be the most appropriate discount factor based on interest rates +currently in effect and risks associated with our natural gas and oil properties +or the natural gas and oil industry in general. +Unless +natural gas and oil reserves are replaced as they are produced, our reserves and +production will decline, which would adversely affect our future business, +financial condition and results of operations. +Producing +natural gas and oil reservoirs generally are characterized by declining +production rates that vary depending upon reservoir characteristics and other +factors. The rate of decline will change if production from existing +wells declines in a different manner than we estimated and the rate can change +due to other circumstances. Thus, our future natural gas and oil +reserves and production and, therefore, our cash flow and income, are highly +dependent on efficiently developing and exploiting our current reserves and +economically finding or acquiring additional recoverable reserves. We +may not be able to develop, discover or acquire additional reserves to replace +our current and future production at acceptable costs. As a result, +our future operations, financial condition and results of operations would be +adversely affected. +Acquisitions +are subject to the uncertainties of evaluating recoverable reserves and +potential liabilities. +Acquisitions +of producing properties and undeveloped properties have been an important part +of our historical growth. We expect acquisitions will also contribute +to our future growth. Successful acquisitions require an assessment +of a number of factors, many of which are beyond our control. These +factors include recoverable reserves, development potential, future natural gas +and oil prices, operating costs and potential environmental and other +liabilities. Such assessments are inexact and their accuracy is +inherently uncertain. In connection with our assessments, we perform +engineering, geological and geophysical reviews of the acquired properties, +which we believe is generally consistent with industry +practices. However, such reviews are not likely to permit us to +become sufficiently familiar with the properties to fully assess their +deficiencies and capabilities. We do not inspect every well prior to +an acquisition. Even when we inspect a well, we do not always +discover structural, subsurface and environmental problems that may exist or +arise. In some cases, our review prior to signing a definitive +purchase agreement may be even more limited. +Our focus +on acquiring producing natural gas and oil properties may increase our potential +exposure to liabilities and costs for environmental and other problems existing +on acquired properties. Often we are not entitled to contractual +indemnification associated with acquired properties. Normally, we +acquire interests in properties on an “as is” basis with no or limited remedies +for breaches of representations and warranties, as was the case in the +acquisitions of assets from EXCO Resources Inc. and Castle, as well as the +acquisition of all shares of Unioil. We could incur significant +unknown liabilities, including environmental liabilities, or experience losses +due to title defects, in our acquisitions for which we have limited or no +contractual remedies or insurance coverage. +20 +Table of Contents +Additionally, +significant acquisitions can change the nature of our operations 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. For example, in the Castle acquisition, +we acquired interests in wells which we will need to operate together with other +partners, we acquired pipelines that we will need to operate and expect we will +need to commit to drilling in the acquired areas to achieve the expected +benefits. Consequently, we may not be able to efficiently realize the +assumed or expected economic benefits of properties that we acquire, if at +all. +When +drilling prospects, we may not yield natural gas or oil in commercially viable +quantities. +A +prospect is a property on which our geologists have identified what they +believe, based on available information, to be indications of natural gas or oil +bearing rocks. However, our geologists cannot know conclusively prior +to drilling and testing whether natural gas or oil will be present or, if +present, whether natural gas or oil will be present in sufficient quantities to +repay drilling or completion costs and generate a profit given the available +data and technology. If a well is determined to be dry or uneconomic, +which can occur even though it contains some oil or natural gas, it is +classified as a dry hole and must be plugged and abandoned in accordance with +applicable regulations. This generally results in the loss of the +entire cost of drilling and completion to that point, the cost of plugging, and +lease costs associated with the prospect. Even wells that are +completed and placed into production may not produce sufficient natural gas and +oil to be profitable. If we drill a dry hole or unprofitable well on +current and future prospects, the profitability of our operations will decline +and our value will likely be reduced. In sum, the cost of drilling, +completing and operating any well is often uncertain and new wells may not be +productive. +We +may not be able to identify enough attractive prospects on a timely basis to +meet our development needs, which could limit our future development +opportunities. +Our +geologists have identified a number of potential drilling locations on our +existing acreage. These drilling locations must be replaced as they +are drilled for us to continue to grow our reserves and +production. Our ability to identify and acquire new drilling +locations depends on a number of uncertainties, including the availability of +capital, regulatory approvals, natural gas and oil prices, competition, costs, +availability of drilling rigs, drilling results and the ability of our +geologists to successfully identify potentially successful new areas to +develop. Because of these uncertainties, our profitability and growth +opportunities may be limited by the timely availability of new drilling +locations. As a result, our operations and profitability could be +adversely affected. +Drilling +for and producing natural gas and oil are high risk activities with many +uncertainties that could adversely affect our business, financial condition and +results of operations. +Drilling +activities are subject to many risks, including the risk that we will not +discover commercially productive reservoirs. Drilling for natural gas and oil +can be unprofitable, not only due to dry holes, but also due to curtailments, +delays or cancellations as a result of other factors, including: +· +unusual +or unexpected geological +formations; +· +pressures; +· +fires; +· +blowouts; +· +loss +of drilling fluid circulation; +· +title +problems; +· +facility +or equipment malfunctions; +· +unexpected +operational events; +· +shortages +or delivery delays of equipment and +services; +· +compliance +with environmental and other governmental requirements; +and +· +adverse +weather conditions. +Any of +these risks can cause substantial losses, including personal injury or loss of +life, damage to or destruction of property, natural resources and equipment, +pollution, environmental contamination or loss of wells and regulatory +penalties. We maintain insurance against various losses and +liabilities arising from operations; however, insurance against all operational +risks is not available. Additionally, our management may elect not to +obtain insurance if the cost of available insurance is excessive relative to the +perceived risks presented. Thus, losses could occur for uninsurable or uninsured +risks or in amounts in excess of existing insurance coverage. The +occurrence of an event that is not fully covered by insurance could have a +material adverse effect on business activities, financial condition and results +of operations. +21 +Table of Contents +We +may be forced to curtail our drilling operations, thereby reducing revenue and +profits from new natural gas and oil wells and from our drilling and completion +activities, due to increased drilling activity, particularly in the Rocky +Mountain Region, which may create a shortage of drilling rigs, service +providers, or materials. +With high +natural gas and oil prices, many natural gas and oil companies have increased +the drilling and completing of new wells and the reworking of old +wells. At the same time there is a limited supply of drilling rigs, +completion equipment and qualified personnel to provide the services necessary +to drill, complete and rework new wells. We do not own any drilling +rigs. The Rocky Mountain Region has seen a great increase in activity over the +past few years. If the demand for these goods and services continues +to increase, shortages may develop, which could result in increased prices for +these goods and services or our inability to complete all of the drilling we +have planned. Thus, we could be forced to drill less, and we could +temporarily or permanently lose all or part of our drilling operations, +negatively affecting our profits. +Our oil and gas well drilling +operations segment has historically received most of its revenue from the +partnerships we sponsor, and a reduction or loss of that business could reduce +or eliminated the revenue, profit and cash flow associated with those +activities. +Our +oil and gas well drilling operations segment has historically received most of +its revenue from the partnerships we sponsor. We sponsor oil and natural +gas partnerships through a network of non-affiliated NASD broker dealers. +In January 2008, we announced that we would not be offering a partnership in +2008. There can be no assurance that the network of brokers will be +available or can be recreated if we wish to use partnerships to raise funds in +future years. In that situation, our operations and profitability could be +adversely affected. +Under +the “successful efforts” accounting method that we use, unsuccessful exploratory +wells must be expensed in the period when they are determined to be +non-productive, which reduces our net income in such periods and could have a +negative effect on our profitability. +We +conducted exploratory drilling in 2006 and 2007 and plan to continue exploratory +drilling in 2008 in order to identify additional opportunities for future +development. Under the “successful efforts” method of accounting that +we use, the cost of unsuccessful exploratory wells must be charged to expense in +the period when they are determined to be unsuccessful. In addition, +lease costs for acreage condemned by the unsuccessful well must also be +expensed. In contrast, unsuccessful development wells are capitalized +as a part of the investment in the field where they are +located. Because exploratory wells generally are more likely to be +unsuccessful than development wells, we anticipate that some or all of our +exploratory wells may not be productive. The costs of such +unsuccessful exploratory wells could result in a significant reduction in our +profitability in periods when the costs are required to be expensed and these +increased costs could reduce our net income and have a negative effect on our +profitability and ability to repay or refinance our indebtedness. +Increasing +finding and development costs may impair our profitability. +In order +to continue to grow and maintain our profitability, we must annually add new +reserves that exceed our yearly production at a finding and development cost +that yields an acceptable operating margin and depreciation, depletion and +amortization rate. Without cost effective exploration, development or +acquisition activities, our production, reserves and profitability will decline +over time. Given the relative maturity of most natural gas and oil +basins in North America and the high level of activity in the industry, the cost +of finding new reserves through exploration and development operations has been +increasing. The acquisition market for natural gas and oil properties +has become extremely competitive among producers for additional production and +expanded drilling opportunities in North America. Acquisition values +climbed toward historic highs during 2006 and 2007 on a per unit basis, +particularly in the Rocky Mountain Region, and we believe these values may +continue to increase in 2008. This increase in finding and +development costs results in higher depreciation, depletion and amortization +rates. If the upward trend in finding and development costs +continues, we will be exposed to an increased likelihood of a write-down in +carrying value of our natural gas and oil properties in response to falling +commodity prices and reduced profitability of our operations. +Our +development and exploration operations require substantial capital, and we may +be unable to obtain needed capital or financing on satisfactory terms, which +could lead to a loss of properties and a decline in our natural gas and oil +reserves. +The +natural gas and oil industry is capital intensive. We make and expect +to continue to make substantial capital expenditures in our business and +operations for the exploration, development, production and acquisition of +natural gas and oil reserves. To date, we have financed capital +expenditures primarily with bank borrowings and cash generated by +operations. We intend to finance our future capital expenditures with +cash flow from operations and our existing and planned financing +arrangements. Our cash flow from operations and access to capital are +subject to a number of variables, including: +· +our +proved reserves; +· +the +amount of natural gas and oil we are able to produce from existing +wells; +· +the +prices at which natural gas and oil are +sold; +· +the +costs to produce oil and natural gas; +and +· +our +ability to acquire, locate and produce new +reserves. +If our +revenues or the borrowing base under our credit facility decreases as a result +of lower natural gas and oil prices, operating difficulties, declines in +reserves or for any other reason, then we may have limited ability to obtain the +capital necessary to sustain our operations at current levels. We +may, from time to time, need to seek additional financing. There can +be no assurance as to the availability or terms of any additional +financing. +22 +Table of Contents +If our revenues or the +borrowing base under our revolving credit facility decrease as a result of lower +natural gas and oil prices, or we incur operating difficulties, declines in +reserves or for any other reason, we may have limited ability to obtain the +capital necessary to sustain our operations at planned +levels. +If +additional capital is needed, we may not be able to obtain debt or equity +financing on favorable terms, or at all. If cash generated by our +operations or sale of drilling partnerships or available under our revolving +credit facility is not sufficient to meet our capital requirements, failure to +obtain additional financing could result in a curtailment of the exploration and +development of our prospects, which in turn could lead to a possible loss of +properties, decline in natural gas and oil reserves and a decline in our +profitability. +Our +credit facility has substantial restrictions and financial covenants and we may +have difficulty obtaining additional credit, which could adversely affect our +operations. +We depend +on our revolving credit facility for future capital needs. The terms +of the borrowing agreement require us to comply with certain financial covenants +and ratios. Our ability to comply with these restrictions and +covenants in the future is uncertain and will be affected by the levels of cash +flows from operations and events or circumstances beyond our +control. Our failure to comply with any of the restrictions and +covenants under the revolving credit facility or other debt financing could +result in a default under those facilities, which could cause all of our +existing indebtedness to be immediately due and payable. +The +revolving credit facility limits the amounts we can borrow to a borrowing base +amount, determined by the lenders in their sole discretion based upon projected +revenues from the natural gas and oil properties securing their +loan. The lenders can unilaterally adjust the borrowing base and the +borrowings permitted to be outstanding under the revolving credit +facility. Outstanding borrowings in excess of the borrowing base must +be repaid immediately, or we must pledge other natural gas and oil properties as +additional collateral. We do not currently have any substantial unpledged +properties, and we may not have the financial resources in the future to make +any mandatory principal prepayments required under the revolving credit +facility. Our inability to borrow additional funds under our credit +facility could adversely affect our operations. +Seasonal +weather conditions and lease stipulations adversely affect our ability to +conduct drilling activities in some of the areas where we operate. +Seasonal +weather conditions and lease stipulations designed to protect various wildlife +affect natural gas and oil operations in the Rocky Mountains. In +certain areas, including parts of the Piceance Basin in Colorado, drilling and +other natural gas and oil activities are restricted or prohibited by lease +stipulations, or prevented by weather conditions, for up to six months out of +the year. This limits our operations in those areas and can intensify +competition during those months for drilling rigs, oil field equipment, +services, supplies and qualified personnel, which may lead to periodic +shortages. These constraints and the resulting shortages or high +costs could delay our operations and materially increase operating and capital +costs and therefore adversely affect our profitability. +We +have limited control over activities on properties in which we own an interest +but we do not operate, which could reduce our production and +revenues. +We +operate most of the wells in which we own an interest. However, there +are some wells we do not operate because we participate through joint operating +agreements under which we own partial interests in natural gas and oil +properties operated by other entities. If we do not operate the +properties in which we own an interest, we do not have control over normal +operating procedures, expenditures or future development of underlying +properties. The failure of an operator to adequately perform +operations, or an operator’s breach of the applicable agreements, could reduce +production and revenues and affect our profitability. The success and +timing of drilling and development activities on properties operated by others +therefore depends upon a number of factors outside of our control, including the +operator’s timing and amount of capital expenditures, expertise (including +safety and environmental compliance) and financial resources, inclusion of other +participants in drilling wells, and use of technology. +Market +conditions or operational impediments could hinder our access to natural gas and +oil markets or delay production. +Market +conditions or the unavailability of satisfactory natural gas and oil +transportation arrangements may hinder our access to natural gas and oil markets +or delay our production. The availability of a ready market for +natural gas and oil production depends on a number of factors, including the +demand for and supply of natural gas and oil and the proximity of reserves to +pipelines and terminal facilities. Our ability to market our +production depends in substantial part on the availability and capacity of +gathering systems, pipelines and processing facilities owned and operated by +third parties. Failure to obtain such services on acceptable terms +could materially harm our business. We may be required to shut in +wells for lack of market or because of inadequacy, unavailability or the pricing +associated with natural gas pipeline, gathering system capacity or processing +facilities. If that were to occur, we would be unable to realize +revenue from those wells until we made production arrangements to deliver the +product to market. Thus, our profitability would be adversely +affected. +23 +Table of Contents +Our +derivative activities could result in financial losses or reduced +income. +We use +derivatives for a portion of our natural gas and oil production from our own +wells, our partnerships and for natural gas purchases and sales by our marketing +subsidiary to achieve a more predictable cash flow, to reduce exposure to +adverse fluctuations in the prices of natural gas and oil, and to allow our +natural gas marketing company to offer pricing options to natural gas sellers +and purchasers. These arrangements expose us to the risk of financial loss in +some circumstances, including when purchases or sales are different than +expected, the counter-party to the derivative contract defaults on its contract +obligations, or when there is a change in the expected differential between the +underlying price in the derivative agreement and actual prices that we +receive. In addition, derivative arrangements may limit the benefit +from changes in the prices for natural gas and oil and may require the use of +our resources to meet cash margin requirements. Since our derivatives +do not currently qualify for use of hedge accounting, changes in the fair value +of derivatives are recorded in our income statements, and our net income is +subject to greater volatility than if our derivative instruments qualified for +hedge accounting. For instance, we have recently increased our derivative +use. The market prices for oil and natural gas, however, have continued to +increase since such derivatives were entered; if such market pricing continues, +it could result in significant non-cash charges each quarter, which could have a +material negative affect on our net income. +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 natural gas and oil sales or joint +interest billings to a small number of third parties in the energy +industry. This concentration of customers and joint interest owners +may affect our overall credit risk in that these entities may be similarly +affected by changes in economic and other conditions. In addition, +our natural gas and oil derivatives as well as the derivatives used by our +marketing subsidiary expose us to credit risk in the event of nonperformance by +counterparties. +Terrorist +attacks or similar hostilities may adversely affect our results of +operations. +Increasing +terrorist attacks around the world have created many economic and political +uncertainties, some of which may materially adversely affect our +business. Uncertainty surrounding military strikes or a sustained +military campaign may affect our operations in unpredictable ways, including +disruptions of fuel supplies and markets, particularly oil, and the possibility +that infrastructure facilities, including pipelines, production facilities, +processing plants and refineries, could be direct targets of, or indirect +casualties of, an act of terror or war. The continuation of these +attacks may subject our operations to increased risks and, depending on their +ultimate magnitude, could have a material adverse effect on our business, +results of operations, financial condition and prospects. +Our +insurance coverage may not be sufficient to cover some liabilities or losses +that we may incur. +The +occurrence of a significant accident or other event not fully covered by +insurance could have a material adverse effect on our operations and financial +condition. Insurance does not protect us against all operational +risks. We do not carry business interruption insurance at levels that +would provide enough funds for us to continue operating without access to other +funds. For some risks, we may not obtain insurance if we believe the +cost of available insurance is excessive relative to the risks +presented. In addition, pollution and environmental risks that we are +subject to are generally not fully insurable. +We +may not be able to keep pace with technological developments in our +industry. +The +natural gas and oil industry is characterized by rapid and significant +technological advancements and introductions of new products and services using +new technologies. As our competitors use or develop new technologies, +we may be placed at a competitive disadvantage, and competitive pressures may +force us to implement those new technologies at substantial cost. In +addition, other natural gas and oil companies 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. We may not be able to respond to these competitive pressures +and implement new technologies on a timely basis or at an acceptable +cost. If one or more of the technologies we use now or in the future +were to become obsolete or if we were unable to use the most advanced +commercially available technology, our business, financial condition and results +of operations could be materially adversely affected. +Competition +in the natural gas and oil industry is intense, which may adversely affect our +ability to succeed. +The +natural gas and oil industry is intensely competitive, and we compete with other +companies that have greater resources. Many of these companies not +only explore for and produce natural gas and oil, but also carry on refining +operations and market petroleum and other products on a regional, national or +worldwide basis. These companies may be able to pay more for +productive natural gas and oil properties and exploratory prospects or define, +evaluate, bid for and purchase a greater number of properties and prospects than +we can. In addition, these companies may have a greater ability to +continue exploration activities during periods of low natural gas and oil market +prices. Larger competitors may be able to absorb the burden of +present and future federal, state, local and other laws and regulations more +easily than we can, which can adversely affect our competitive +position. Our ability to acquire additional properties and to +discover reserves in the future will be dependent upon our ability to +evaluate and select suitable properties and to consummate transactions in a +highly competitive environment. In addition, because many companies +in our industry have greater financial and human resources, we may be at a +disadvantage in bidding for exploratory prospects and producing natural gas and +oil properties. These factors could adversely affect the success of +our operations and our profitability. +24 +Table of Contents +We +are subject to complex federal, state, local and other laws and regulations that +could adversely affect the cost, manner or feasibility of doing +business. +Our +exploration, development, production and marketing operations are regulated +extensively at the federal, state and local levels. Environmental and other +governmental laws and regulations have increased the costs to plan, design, +drill, install, operate and abandon natural gas and oil wells. Under +these laws and regulations, we could also be liable for personal injuries, +property damage and other damages. Failure to comply with these laws +and regulations may result in the suspension or termination of operations and +subject us to administrative, civil and criminal penalties. Moreover, +public interest in environmental protection has increased in recent years, and +environmental organizations have opposed, with some success, certain drilling +projects. +Part of +the regulatory environment includes federal requirements for obtaining +environmental assessments, environmental impact studies and/or plans of +development before commencing exploration and production +activities. In addition, our activities are subject to the regulation +by natural gas and oil-producing states of conservation practices and protection +of correlative rights. These regulations affect our operations and +limit the quantity of natural gas and oil that can be produced and +sold. A major risk inherent in our drilling plans is the need to +obtain drilling permits from state and local authorities. Delays in +obtaining regulatory approvals, drilling permits, 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. Additionally, the natural gas +and oil regulatory environment could change in ways that might substantially +increase our financial and managerial costs to comply with the requirements of +these laws and regulations and, consequently, adversely affect our +profitability. Furthermore, these additional costs may put us at a +competitive disadvantage compared to larger companies in the industry who can +spread such additional costs over a greater number of wells and larger operating +staff. +Litigation +has been commenced against us pertaining to our royalty practices and payments; +the cost of our defending these lawsuits, and any future similar lawsuit, could +be significant and any resulting judgments against us could have a material +adverse effect upon our financial condition. +Recent +litigation has commenced against us and several other companies in our industry +regarding royalty practices and payments in jurisdictions where we conduct +business. For more information on the two suits that currently relate +to us, see Item +3 , Legal +Proceedings . We intend to defend ourselves vigorously in these +cases. Even if the ultimate outcome of this litigation resulted in +our dismissal, defense costs could be significant. These costs would +be reflected in terms of dollar outlay as well as the amount of time, attention +and other resources that our management would have to appropriate to the +defense. Although we cannot predict an eventual outcome of this +litigation, a judgment in favor of a plaintiff could have a material adverse +effect on our financial condition. +Information +technology financial systems implementation problems could disrupt our internal +business operations and adversely affect our business financial results or our +ability to report our financial results. +We are +currently in the process of implementing a new financial software system to +enhance operating efficiencies and provide more effective management of our +business operations. Our implementation is based on a phased +approach, with the financial reporting system to be implemented in the first +quarter of 2008. Implementations of financial systems and related +software carry such risks as cost overruns, project delays and business +interruptions, which could increase our expense, have an adverse effect on our +business, our ability to report in +an accurate and timely manner our financial position and our results of +operations and cash flows. +Risks +Associated with Our Indebtedness +We +may incur additional indebtedness to facilitate our acquisition of additional +properties, which would increase our leverage and could negatively affect our +business or financial condition. +Our +business strategy includes the acquisition of additional properties that we +believe would have a positive effect on our current business and +operations. We expect to continue to pursue acquisitions of such +properties and may incur additional indebtedness to finance the +acquisitions. Our incurrence of additional indebtedness would +increase our leverage and our interest expense, which could have a negative +effect on our business or financial condition. +25 +Table of Contents +If +we fail to obtain additional financing, we may be unable to refinance our +existing debt, expand our current operations or acquire new businesses. This +could result in our failure to grow in accordance with our plans, or could +result in defaults in our obligations under our senior credit agreement or the +indenture relating to our outstanding senior notes. +In order +to refinance indebtedness, expand existing operations and acquire additional +businesses or properties, we will require substantial amounts of +capital. There can be no assurance that financing, whether from +equity or debt financings or other sources, will be available or, if available, +will be on terms satisfactory to us. If we are unable to obtain such +financing, we will be unable to acquire additional businesses and may be unable +to meet our obligations under our senior credit agreement and the indenture +relating to our outstanding senior notes or any other debt securities we may +issue in the future. +The +indenture governing our outstanding senior notes and our senior credit agreement +impose (and we anticipate that the indentures governing any other debt +securities we may issue will also impose) restrictions on us that may limit the +discretion of management in operating our business. That, in turn, could impair +our ability to meet our obligations. +The +indenture governing our outstanding senior notes and our senior credit agreement +contain (and we anticipate that the indentures governing any other debt +securities we may issue will also contain) various restrictive covenants that +limit management’s discretion in operating our business. In +particular, these covenants limit our ability to, among other +things: +· +incur +additional debt; +· +make +certain investments or pay dividends or distributions on our capital +stock, or purchase, redeem or retire capital +stock; +· +sell +assets, including capital stock of our restricted +subsidiaries; +· +restrict +dividends or other payments by restricted +subsidiaries; +· +create +liens; +· +enter +into transactions with affiliates; +and +· +merge +or consolidate with another +company. +These +covenants could materially and adversely affect our ability to finance our +future operations or capital needs. Furthermore, they may restrict +our ability to expand, to pursue our business strategies and otherwise conduct +our business. Our ability to comply with these covenants may be +affected by circumstances and events beyond our control, such as prevailing +economic conditions and changes in regulations, and we cannot assure you that we +will be able to comply with them. A breach of these covenants could +result in a default under the indenture governing our outstanding senior notes +and any other debt securities we may issue in the future and/or our senior +credit agreement. If there were an event of default under our +indenture and/or the senior credit agreement, the affected creditors could cause +all amounts borrowed under these instruments to be due and payable +immediately. Additionally, if we fail to repay indebtedness under our +senior credit agreement when it becomes due, the lenders under the senior credit +agreement could proceed against the assets which we have pledged to them as +security. Our assets and cash flow might not be sufficient to repay +our outstanding debt in the event of a default. +Our +senior credit agreement also requires us to maintain specified financial ratios +and satisfy certain financial tests. Our ability to maintain or meet +such financial ratios and tests may be affected by events beyond our control, +including changes in general economic and business conditions, and we cannot +assure you that we will maintain or meet such ratios and tests, or that the +lenders under the senior credit agreement will waive any failure to meet such +ratios or tests. +ITEM 1B . UNRESOLVED STAFF COMMENTS +None. +ITEM 2. PROPERTIES +Information +regarding our wells, production, proved reserves and acreage are included in +Item 1 and in Note +1 , Summary of +Significant Accounting Policies , to our consolidated financial statements +included in this report. +Substantially +all of our oil and natural gas properties have been mortgaged or pledged as +security for our credit facility. See Note 5 , Long Term Debt , to our +consolidated financial statements included in this report. +26 +Table of Contents +Facilities +We own +our 32,000 square feet corporate office building located in Bridgeport, West +Virginia. In February 2008, we entered into an agreement to lease +approximately 17,000 square feet of office space in a building under +construction near the corporate office and purchased an approximate 12 acre, +undeveloped parcel of land adjacent to our existing corporate offices for +potential future expansion of the corporate office facility. We +maintain a lease for 13,000 square feet of administrative office space in +downtown Denver, Colorado through May 2012. +We own or +lease field operating facilities in the following locations: +· +West +Virginia: Bridgeport, Glenville and West +Union +· +Michigan: Ossineke +· +Colorado: Evans, +Parachute and Wray +· +Pennsylvania: Indiana +and Mahaffey +ITEM 3. LEGAL PROCEEDINGS +Information +regarding our legal proceedings can be found in Note 8 , Commitments and Contingencies – +Litigation , to our consolidated financial statements included in this +report. +ITEM 4 . SUBMISSION OF MATTERS TO A VOTE OF SECURITY +HOLDERS +None. +PART +II +ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY, +RELATED STOCKHOLDERS MATTERS AND ISSUER PURCHASES OF EQUITY +SECURITIES. +Our +authorized capital stock consists of 50,000,000 shares of common stock, par +value $0.01 per share. There were 14,851,234 shares of common stock +issued and outstanding as of March 14, 2008. Our common stock is +traded on the NASDAQ Global Select Market under the ticker symbol +PETD. +The +following table sets forth the range of high and low sales prices for our common +stock as reported on the NASDAQ Global Select Market for the periods indicated +below. +High +Low +2007 +First +Quarter +$ +55.20 +$ +40.53 +Second +Quarter +55.24 +44.59 +Third +Quarter +51.13 +35.73 +Fourth +Quarter +61.91 +41.65 +2006 +First +Quarter +46.17 +32.12 +Second +Quarter +45.62 +32.51 +Third +Quarter +45.23 +33.16 +Fourth +Quarter +47.44 +36.54 +As of +March 14, 2008, we had approximately 1,242 shareholders of record. +We +have not paid any dividends on our common stock and currently intend to retain +earnings for use in our business. Therefore, we do not expect to +declare cash dividends in the foreseeable future. +27 +Table of Contents +ISSUER +PURCHASES OF EQUITY SECURITIES +Period +Total +Number +of +Shares +Purchased +Average +Price +Paid per +Share +Total +Number of Shares +Purchased +as +Part of +Publicly +Announced +Plans +or +Programs +Maximum +Number +of Shares that +May +Yet Be +Purchased +Under the +Plans +or +Programs +Shares +purchased prior to October 1, 2007, under the current +repurchase program. +6,833 +$ +50.63 +6,833 +1,470,276 +Fourth +quarter purchases: +October +1 - 31, 2007 +- +- +- +- +November +1-30, 2007 +- +- +- +- +December +1-31, 2007 +5,187 +57.93 +5,187 +1,465,089 +Total +fourth quarter purchases +5,187 +5,187 +Total +shares purchased under the current program +12,020 +53.78 +12,020 +1,465,089 +On +October 16, 2006, our Board of Directors approved a second 2006 share purchase +program authorizing us to purchase up to 10% of our then outstanding common +stock (1,477,109 shares) through April 2008. Stock purchases under +this program may be made in the open market or in private transactions, at times +and in amounts that we deem appropriate. Shares are generally +purchased at fair market value based on the closing price on the date of +purchase. Total shares purchased in 2007 pursuant to the program were +12,020 common shares at a cost of $0.6 million ($53.78 average price paid per +share), including 5,187 shares from our executive officers at a cost of $0.3 +million ($57.93 price paid per share). Shares purchased pursuant to +the plan were primarily to satisfy the statutory minimum tax withholding +requirement for restricted stock that vested in 2007. All shares were +subsequently retired. +Pursuant to +our senior notes indenture entered on February 8, 2008, any future purchases are +limited, see Note 19, Subsequent Events , +to our accompanying consolidated financial statements. +On +February 25, 2008, pursuant to a separation agreement, we purchased 50,000 +shares of our common stock from one of our executive officers at a cost of $3.4 +million, or $67.92 per share. See Note 19 , Subsequent Events , to our +consolidated financial statements included in this report. +28 +Table of Contents +SHAREHOLDER +PERFORMANCE GRAPH +The +performance graph below compares the cumulative total return of our common stock +over a five year period ended December 31, 2007, with the cumulative total +returns for the same period for a Standard Industrial Code Index, or SIC, and +the Standard and Poor's, or S&P, 500 Index. The SIC Code Index is +a weighted composite of 154 crude petroleum and natural gas +companies. The cumulative total shareholder return assumes that $100 +was invested, including reinvestment of dividends, if any, in our common stock +on December 31, 2002, and in the S&P 500 Index and the SIC Code Index on the +same date. The results shown in the graph below are not necessarily +indicative of future performance. +Year +Ended December 31, +2002 +2003 +2004 +2005 +2006 +2007 +PETROLEUM +DEVELOPMENT CORPORATION +$ +100.00 +$ +447.17 +$ +727.74 +$ +629.06 +$ +812.26 +$ +1,115.66 +SIC +CODE INDEX +100.00 +160.61 +204.02 +293.12 +381.13 +535.76 +S&P +500 INDEX +100.00 +128.68 +142.69 +149.70 +173.34 +182.87 +29 +Table of Contents +ITEM 6. SELECTED FINANCIAL DATA +Year +Ended December 31, +2007 +2006 +2005 +2004 +2003 +(in +thousands, except per share data) +Revenues: +Oil +and gas sales +$ +175,187 +$ +115,189 +$ +102,559 +$ +69,492 +$ +48,394 +Sales +from natural gas marketing activities +103,624 +131,325 +121,104 +94,627 +73,132 +Oil +and gas well drilling operations (1) +12,154 +17,917 +99,963 +94,076 +57,510 +Well +operations and pipeline income +9,342 +10,704 +8,760 +7,677 +6,907 +Oil +and gas price risk management (loss) gain, net +2,756 +9,147 +(9,368 +) +(3,085 +) +(812 +) +Other +2,172 +2,221 +2,180 +1,696 +3,338 +Total +revenues +305,235 +286,503 +325,198 +264,483 +188,469 +Costs +and expenses: +Oil +and gas production and well operations costs +49,264 +29,021 +20,400 +17,713 +13,630 +Cost +of natural gas marketing activities +100,584 +130,150 +119,644 +92,881 +72,361 +Cost +of oil and gas well drilling operations (1) +2,508 +12,617 +88,185 +77,696 +46,946 +Exploration +expense +23,551 +8,131 +11,115 +- +- +General +and administrative expense +30,968 +19,047 +6,960 +4,506 +4,975 +Depreciation, +depletion and amortization +70,844 +33,735 +21,116 +18,156 +15,313 +Total +costs and expenses +277,719 +232,701 +267,420 +210,952 +153,225 +Gain +on sale of leaseholds (2) +33,291 +328,000 +7,669 +- +- +Income +from operations +60,807 +381,802 +65,447 +53,531 +35,244 +Interest +income +2,662 +8,050 +898 +185 +190 +Interest +expense +(9,279 +) +(2,443 +) +(217 +) +(238 +) +(816 +) +Income +before income taxes and cumulative effect of change in accounting +principle +54,190 +387,409 +66,128 +53,478 +34,618 +Provision +for income taxes +20,981 +149,637 +24,676 +20,250 +11,934 +Income +before cumulative effect of change in accounting principle +33,209 +237,772 +41,452 +33,228 +22,684 +Cumulative +effect of change in accounting principle (net of taxes of $1,392) (3) +- +- +- +- +(2,271 +) +Net +income +$ +33,209 +$ +237,772 +$ +41,452 +$ +33,228 +$ +20,413 +Basic +earnings per common share +$ +2.25 +$ +15.18 +$ +2.53 +$ +2.05 +$ +1.30 +Diluted +earnings per share +$ +2.24 +$ +15.11 +$ +2.52 +$ +2.00 +$ +1.25 +December +31, +2007 +2006 +2005 +2004 +2003 +Total +assets +$ +1,050,479 +$ +884,287 +$ +444,361 +$ +329,453 +$ +294,004 +Working +capital (deficit) +$ +(50,212 +) +$ +29,180 +$ +(16,763 +) +$ +231 +$ +7,287 +Long-term +debt +$ +235,000 +$ +117,000 +$ +24,000 +$ +21,000 +$ +53,000 +Shareholders' +equity +$ +395,526 +$ +360,144 +$ +188,265 +$ +154,021 +$ +112,559 +(1) +In +December 2005, we began entering into cost-plus drilling service +arrangements, which are recorded on a net basis unlike our footage based +arrangements which are recorded on a gross basis. See Note 1 , +"Summary of Significant Accounting Policies," to our consolidated +financial statements included in this +report. +(2) +In +July 2006, we sold a portion of our undeveloped leasehold located in Grand +Valley Field, Garfield County, Colorado. See Note 16 , "Sale +of Oil and Gas Properties," to our consolidated financial statements +included in this report. +(3) +Represents +the income effect of the adoption of SFAS No. 143, Accounting for Asset +Retirement Obligations. See Note 7 , "Asset +Retirement Obligation," to our consolidated financial statements included +in this report. +30 +Table of Contents +ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF +FINANCIAL CONDITION AND RESULTS OF OPERATIONS +The +following discussion and analysis, as well as other sections in this Form 10-K, +should be read in conjunction with our accompanying consolidated financial +statements and related notes to consolidated financial statements included in +this report. +Year Ended December 31, +2007, Compared to December 31, 2006 +Management +Overview +Net +Income +The +following table presents net income and diluted earnings per share for the year +ended December 31, 2007 and 2006. +Year +Ended December 31, +Change +2007 +2006 +Amount +Percent +(dollars +in thousands, except per share data) +Net +income +$ +33,209 +$ +237,772 +$ +(204,563 +) +-86.0 +% +Diluted +earnings per share +$ +2.24 +$ +15.11 +$ +(12.87 +) +-85.2 +% +Net +income for 2007, declined significantly due to last year's $328 million pretax +gain associated with the July 2006 sale of a leasehold to an unrelated party +(see Gain on +Sale of Leaseholds below). In 2007, we had two sales of +leaseholds, which totaled $33.3 million pretax. The positive driver +of net income in 2007 was the 65% increase in production, which contributed to +the $60 million increase in oil and gas sales despite lower average natural gas +prices. The increase in oil and gas sales was offset by increases in +depreciation, depletion and amortization, or DD&A , +expense, production and well operations cost, exploration expense and +general and administrative expense. Additionally, gains from oil and +gas price risk management, net, decreased $6.4 million from a $9.1 million gain +in 2006 to a $2.8 million gain in 2007, primarily due to increasing oil prices +at the end of 2007. +Revenues +Revenues +for the years ended December 31, 2007 and 2006, are presented +below. +Year +Ended December 31, +Change +2007 +2006 +Amount +Percent +(dollars +in thousands) +Revenues: +Oil +and gas sales +$ +175,187 +$ +115,189 +$ +59,998 +52.1 +% +Sales +from natural gas marketing activities +103,624 +131,325 +(27,701 +) +-21.1 +% +Oil +and gas well drilling operations +12,154 +17,917 +(5,763 +) +-32.2 +% +Well +operations and pipeline income +9,342 +10,704 +(1,362 +) +-12.7 +% +Oil +and gas price risk management gain, net +2,756 +9,147 +(6,391 +) +-69.9 +% +Other +2,172 +2,221 +(49 +) +-2.2 +% +Total +revenues +$ +305,235 +$ +286,503 +$ +18,732 +6.5 +% +Total +revenues for 2007 were up $18.7 million or 6.5% over 2006. The +increase was primarily due to a 52.1 % increase in oil and gas sales largely +offset by declines in natural gas marketing activities, oil and gas well +drilling operations and oil and gas price risk management gain, +net. +31 +Table of Contents +Oil and +natural gas sales increased $60 million as a result of the increase in +production of 65% although natural gas prices declined an average of 10% per +Mcf. Our natural gas marketing division enters into fixed-price +physical purchase and sale agreements that qualify as derivative +contracts. In order to offset these fixed-price physical derivatives, +we enter into financial derivative instruments that have the effect of locking +in the prices we will receive or pay for the same volumes and period, offsetting +the physical derivative. The decreases in both sales from natural gas +marketing activities and oil and gas price risk management, net, are a result of +a comparison of lower natural gas prices at December 31, 2006, compared with the +higher fourth quarter and year-end 2007 pricing. Lower well +operations and pipeline income is directly attributable to our January 2007 +acquisition of the outstanding partnership interests in 44 of our sponsored +drilling partnerships for which we no longer receive income for operating these +wells and related pipelines. +Costs +and Expenses +Costs and +expenses for the years ended December 31, 2007 and 2006, are presented +below. +Year +Ended December 31, +Change +2007 +2006 +Amount +Percent +(dollars +in thousands) +Costs +and expenses: +Oil +and gas production and well operations cost +$ +49,264 +$ +29,021 +$ +20,243 +69.8 +% +Cost +of natural gas marketing activities +100,584 +130,150 +(29,566 +) +-22.7 +% +Cost +of oil and gas well drilling operations +2,508 +12,617 +(10,109 +) +-80.1 +% +Exploration +expense +23,551 +8,131 +15,420 +189.6 +% +General +and administrative expense +30,968 +19,047 +11,921 +62.6 +% +Depreciation, +depletion and amortization +70,844 +33,735 +37,109 +110.0 +% +Total +costs and expenses +$ +277,719 +$ +232,701 +$ +45,018 +19.4 +% +The +increase in total costs and expenses for 2007 compared to 2006 was a reflection +of our growth over the past year, which was funded primarily by the reinvestment +of the proceeds from the 2006 sale of undeveloped leasehold of $353.6 million +into productive operating properties. Due to the acquisitions and the +significant number of new wells drilled for our own account and placed in +service during 2007, we have substantially increased production, resulting in +higher costs and expenses. +The +increases in oil and gas production and well operations cost and DD&A +expense for 2007 over 2006 reflects the growth we are currently experiencing +through acquisitions and increased drilling. The larger number of new +wells drilled and the increasing cost of well drilling, completion and equipping +of new wells, along with the higher market cost of our 2007 property +acquisitions, is reflected in the DD&A rate of our oil and gas properties, +which increase from $1.86 per Mcfe in 2006 to $2.37 per Mcfe in +2007. The increase in exploration expense in 2007 was due to the +liquidated damages from an exploration agreement and the subsequent lease +abandonment, expense related to eight exploratory dry holes, including one that +was pending determination at December 31, 2006, and increases in other +exploratory costs. The decrease in natural gas marketing costs +corresponds to the decline in sales from natural gas marketing activities as +referenced above. While general and administrative expense increased +$11.9 million from 2006 to 2007, general and administrative expense on a unit of +production basis remained relatively unchanged. +See the +following discussion of results of operations describing in more detail the +components of revenues and expenses and, where significant, providing an +analysis of changes year over year and the cause or underlying reason for such +change. +Results +of Operations +Revenues +Oil +and Gas Sales +The table +below sets forth revenues for oil and gas sales for the years ended December 31, +2007 and 2006, excluding the impact of commodity based derivative instruments, +which are included in oil and gas price risk management gain, net in the +statement of income. +32 +Table of Contents +Year +Ended December 31, +Change +2007 +2006 +Amount +Percent +(dollars +in thousands) +Oil +and gas sales +$ +175,187 +$ +115,189 +$ +59,998 +52.1 +% +The +increase in oil and gas sales in 2007 was primarily due to increased volumes of +oil and natural gas of 65%, partially offset by lower average sales prices of +natural gas. The increased volume of oil and natural gas contributed +$75 million to oil and gas sales, while the decline in natural gas prices +reduced oil and gas sales by $14 million in 2007 compared to +2006. The increase in natural gas and oil volumes was the result of +our increased investment in oil and gas properties, primarily the fourth quarter +2006 and first quarter 2007 acquisitions and the significantly increase in the +number of wells we drilled for our own account over the past +year. The oil and gas sales generated during 2007 from the +acquisitions made in 2007 and December 2006, and their subsequent development, +were $45.8 million. +Oil and Natural +Gas Production. Oil and natural gas production by area of +operation along with average sales price (excluding derivative gains/losses) for +the year is presented below. +2007 +2006 +Change +Oil +(Bbls) +Natural +Gas (Mcf) +Natural +Gas Equivalent (Mcfe) +Oil +(Bbls) +Natural +Gas (Mcf) +Natural +Gas Equivalent (Mcfe) +Oil +(Bbls) +Natural +Gas (Mcf) +Natural +Gas Equivalent (Mcfe) +Production +(Mcf) +Appalachian +Basin +5,490 +2,711,300 +2,744,240 +1,837 +1,451,729 +1,462,751 +199 +% +87 +% +88 +% +Michigan +Basin +4,301 +1,678,155 +1,703,961 +4,439 +1,399,852 +1,426,486 +-3 +% +20 +% +19 +% +Rocky +Mountain Region +900,261 +18,123,851 +23,525,417 +625,119 +10,309,203 +14,059,917 +44 +% +76 +% +67 +% +Total +910,052 +22,513,306 +27,973,618 +631,395 +13,160,784 +16,949,154 +44 +% +71 +% +65 +% +2007 +2006 +Change +(in +thousands, except average price) +(in +thousands, except average price) +Sales +Appalachian +Basin +$ +324 +$ +18,952 +$ +19,276 +$ +110 +$ +10,699 +$ +10,809 +194 +% +77 +% +78 +% +Michigan +Basin +294 +10,270 +10,564 +271 +9,141 +9,412 +8 +% +12 +% +12 +% +Rocky +Mountain Region +54,578 +90,769 +145,347 +37,079 +57,889 +94,968 +47 +% +57 +% +53 +% +Total +$ +55,196 +$ +119,991 +$ +175,187 +$ +37,460 +$ +77,729 +$ +115,189 +47 +% +54 +% +52 +% +Average +Sales Price +(Oil +- per Bbl, Natural Gas - per Mcf) +Appalachian +Basin +$ +59.08 +$ +6.99 +$ +7.02 +$ +60.14 +$ +7.37 +$ +7.39 +-2 +% +-5 +% +-5 +% +Michigan +Basin +68.31 +6.12 +6.20 +61.07 +6.53 +6.60 +12 +% +-6 +% +-6 +% +Rocky +Mountain Region +60.62 +5.01 +6.18 +59.31 +5.62 +6.75 +2 +% +-11 +% +-9 +% +Total +$ +60.65 +$ +5.33 +$ +6.26 +$ +59.33 +$ +5.91 +$ +6.80 +2 +% +-10 +% +-8 +% +The +production generated from the acquisitions made in 2007 and December 2006, and +their subsequent development, was 6.5 Bcfe. This represents +approximately 59% of the total 11.0 Bcfe increase in production in 2007 compared +to 2006. +Late in +the second quarter of 2007, we placed into service the upgraded Garden Gulch +pipeline and compressor facility, which serves a majority of our wells in the +Piceance Basin. This upgrade included two new natural gas +compressors, with a third compressor added in the third quarter, and pipeline +facility enhancements. The upgrade and enhancements have increased +the capacity of the pipeline delivery system from 17,000 Mcf per day to +60,000 Mcf per day from the wells feeding this facility from the time of our +start-up in late June 2007. +Oil and Natural +Gas Pricing . Financial results depend +upon many factors, particularly the price of natural gas and our ability to +market our production effectively. Natural gas and oil prices have +been among the most volatile of all commodity prices. These price +variations have a material impact on our financial results. Natural +gas and oil prices also vary by region and locality, depending upon the distance +to markets, and the supply and demand relationships in that region or +locality. This can be especially true in the Rocky Mountain +Region. The combination of increased drilling activity and the lack +of local markets could result in a local market oversupply situation from time +to time. Such a situation existed in the Rocky Mountain Region during +2007, with production exceeding the local market demand and pipeline capacity to +non-local markets. The result, beginning in the second quarter of +2007 and continuing into the fourth quarter of 2007, had been a decrease in the +price of Rocky Mountain natural gas compared to the NYMEX price and other +markets as shown in the graph below. The expansion in January 2008 of +the Rockies Express pipeline, or REX, is the primary reason for the narrowing of +the NYMEX/CIG gap in December 2007 and forward. Once the third phase +of the expansion of the Rockies Express is completed in 2009, the pipeline +capacity is expected to increase by 64% to 1.8 Bcf/per day of natural gas from +the region. Like most producers in the region, we rely on major +interstate pipeline companies to construct these facilities to increase pipeline +capacity, rendering the timing and availability of these facilities beyond our +control. +33 +Table of Contents +Rocky +Mountain Region Pricing . Although our +weighted average price for natural gas in 2007 was $5.33 per Mcf, the price we +receive for a large portion of the natural gas produced in the Rocky Mountain +Region is based on a market basket of prices, which may include some gas sold at +the Colorado Interstate Gas, or CIG, Index. The CIG Index, and other +indices for production delivered to other Rocky Mountain pipelines, has +historically been less than the price received for natural gas produced in the +eastern regions, which is New York Mercantile Exchange, or NYMEX, +based. The natural gas price in the eastern regions, where 19.5% of +our total natural gas production for the year was produced, was $6.67 per Mcf +compared to our Rocky Mountain Region price per Mcf of $5.01. The +Rocky Mountain Region contributed 80.5% of our natural gas for the year and is +where we anticipate a majority of our future production increases will +occur. During 2007, through our derivative activities, we realized a +benefit from the floors put in place on our production in the Rocky Mountain +Region. We received $7.2 million in proceeds (gross, excluding the +cost of floors) from our derivative instruments during 2007 or $0.40 per Mcf, +which helped to offset the lower prices we received for our Rocky Mountain +Region natural gas. We report our activities from derivative +transactions under the oil and gas price risk management, net line item in our +accompanying consolidated statements of income. +The graph +below identifies the actual NYMEX and CIG natural gas prices by month from +January 2006 through February 2008 and the forward curve for natural gas prices +through March 2009 as of February 15, 2008. The forecasted prices in +the graph have been derived from the sources indicated and represent, in our +opinion, a reasonable view of the possible movement of the CIG and NYMEX natural +gas prices over the next thirteen months. However, because the prices +given in the graph represent forecasts of future matters and are subject to +future events which we cannot predict, we can give no assurance that these +forecasted prices will be as they are presented in the graph. An +investor should therefore not rely on these forecasted prices in making an +investment decision regarding our stock. +___________ +*Source: Derived +from various sources including FutureSource, Inside FERC’s Gas Market Report and +ClearPort Trading. +While the +above graph shows a large differential between recent NYMEX and CIG pricing, the +gap began narrowing in November 2007 and has continued. As of +February 15, 2008, the price differential between NYMEX and CIG for 2008 has +narrowed to $(1.32) from $(3.38) average for the fourth +quarter. Although 80.5% of our 2007 natural gas production came from +the Rocky Mountain Region, the Rocky Mountain natural gas pricing is based upon +other indices in addition to CIG. +The +table below identifies the basis of our natural gas and oil pricing on a sales +volume basis for the year ended December 31, 2007. It further +outlines that 38% of our natural gas sales are derived from the CIG Index and +other similarly priced Rocky Mountain pipelines. In 2007, we realized +considerably higher prices associated with our non CIG volumes. +34 +Table of Contents +Energy +Market Exposure +as +of December 31, 2007 +Area +Pricing +Basis +Commodity +Percent +of Oil and Gas Sales +Grand +Valley/Wattenberg +Rocky +Mountain (CIG, et. al.) +Gas +38% +Colorado/North +Dakota +NYMEX +Oil +16% +NECO/Grand +Valley +Mid +Continent (Panhandle Eastern) +Gas +29% +Appalachian +NYMEX +Gas +10% +Michigan +Mich-Con/NYMEX +Gas +4% +Wattenberg +Colorado +Liquids +Gas +2% +Other +Other +Gas/Oil +1% +100% +Sales +from Natural Gas Marketing Activities +Revenues +from natural gas marketing activities for the years ended December 31, 2007 and +2006, are presented below. +Year +Ended December 31, +Change +2007 +2006 +Amount +Percent +(dollars +in thousands) +Sales +from natural gas marketing activities +$ +103,624 +$ +131,325 +$ +(27,701 +) +-21.1 +% +The +decrease in sales from natural gas marketing activities in 2007 was primarily +due to a decrease in prices and a decrease in volumes sold, along with a $14 +million decrease in unrealized gains on derivative transactions, from a $12.3 +million gain in 2007 to a $1.7 million loss in 2007. In 2007, prices +were 5% lower on average than in 2006, resulting in a $4.8 million decline in +sales, and volumes sold decreased by 9%, resulting in an additional $8.8 million +decline in sales. In January 2007, we acquired all of the outstanding +partnership interests in 44 of our sponsored drilling +partnerships. Since this acquisition, we no longer record oil and gas +sales for the net 423 wells acquired. In total, our natural gas +marketing segment's sales volumes increased by 4% in 2007; however, once the +intercompany volumes are eliminated, the net remaining sales from our natural +gas marketing segment declined. +Our +natural gas marketing segment is composed of our wholly owned subsidiary, +RNG. RNG is a natural gas marketing company that specializes in the +purchase, aggregation and sale of natural gas production in our Eastern +operating areas. RNG markets the natural gas we produce and also +purchases natural gas in the Appalachian Basin from other producers, including +our affiliated partnerships, and resells it to utilities, industrial and +commercial customers as well as other marketers. RNG has established +relationships with many of the natural gas producers in the Appalachian Basin +and has gained significant expertise in the natural gas end-user +market. RNG's sales to end-user customers utilize transportation +services provided by regulated interstate pipeline companies. RNG's +derivative activities are comprised of both physical and cash-settled +derivatives. RNG offers fixed-price derivative contracts for the +purchase or sale of physical gas. RNG also enters into cash-settled +derivative positions with counterparties in order to offset those same physical +positions. RNG does not take speculative positions on commodity +prices. +35 +Table of Contents +The +following table sets forth RNG's derivative positions in effect as of December +31, 2007. +Riley +Natural Gas +Open +Derivative Positions +(dollars +in thousands, except average price data) +Weighted +Total +Quantity +Average +Contract +Commodity +Type +Gas-MMbtu +Price +Amount +Fair +Value +Total +Positions as of December 31, 2007 +Natural +Gas +Cash +Settled Futures/Swaps Purchases +588,950 +$ +7.79 +$ +4,586 +$ +(246 +) +Natural +Gas +Cash +Settled Futures/Swaps Sales +2,085,400 +8.50 +17,722 +1,236 +Natural +Gas +Cash +Settled Basis Swap Purchases +397,500 +0.54 +214 +3 +Natural +Gas +Physical +Purchases +2,085,400 +8.51 +17,748 +(473 +) +Natural +Gas +Physical +Sales +518,951 +8.50 +4,409 +129 +$ +649 +Oil +and Gas Well Drilling Operations +Revenues +from drilling operations for the years ended December 31, 2007 and 2006, are +presented below. +Year +Ended December 31, +Change +2007 +2006 +Amount +Percent +(dollars +in thousands) +Oil +and gas well drilling operations +$ +12,154 +$ +17,917 +$ +(5,763 +) +-32.2 +% +The +decrease in oil and gas well drilling operations revenue was due to our change +from footage-based drilling arrangements to cost-plus drilling arrangements, +which are presented differently for accounting purposes. Beginning +with the last sponsored partnership in 2005 (for which revenue generating +activities began in 2006), our partnership wells have been drilled on a +"cost-plus" basis, which means that we charge the partnerships for the actual +cost of the wells plus an agreed upon mark-up above that cost. Prior +to that partnership, we had conducted most of our third-party drilling +activities on a footage basis, pursuant to which we drilled the wells for a +fixed price per foot drilled with additional chargeable items as provided for in +the drilling agreement. Our services provided under the cost-plus +drilling arrangements are reported net of recovered costs and reflected as +revenue in oil and gas well drilling operations, whereas the revenues under the +footage-based arrangements were recorded gross of related +expenses. For the year ended December 31, 2006, oil and gas well +drilling operations included $5.4 million in revenues related to footage based +arrangements. +Well +Operations and Pipeline Income +Revenues +from well operations and pipeline income for the years ended December 31, 2007 +and 2006 are presented below. +Year +Ended December 31, +Change +2007 +2006 +Amount +Percent +(dollars +in thousands) +Well +operations and pipeline income +$ +9,342 +$ +10,704 +$ +(1,362 +) +-12.7 +% +In +January 2007, we acquired all of the outstanding partnership interests in 44 of +our sponsored drilling partnerships. Having acquired 423 net wells +pursuant to the acquisition, we no longer record income for operating these +wells and related pipelines. This decrease in revenue was offset in +part by an increase in the number of new wells drilled and placed in service and +pipeline systems we operate for our sponsored drilling partnerships as well as +third parties. +36 +Table of Contents +Oil +and Gas Price Risk Management, Net +Oil and +gas price risk management, net for the years ended December 31, 2007 and 2006, +are presented below. +Year +Ended December 31, +Change +2007 +2006 +Amount +Percent +(dollars +in thousands) +Oil +and gas price risk management gain, net +$ +2,756 +$ +9,147 +$ +(6,391 +) +-69.9 +% +In 2007, +we recorded realized gains of $7.2 million and unrealized losses of $4.4 +million, resulting in a net $2.8 million gain for the year. In 2006, +we incurred realized and unrealized gains of $1.9 million and $7.2 million, +respectively, resulting in a $9.1 million gain. The significant +decline in the CIG market during the fall of 2007 resulted in the substantial +realized gains in 2007. When forward prices for oil and natural gas +prices increase, as they did at December 31, 2007, and for the additional +increases we are experiencing in 2008, our derivative portfolio, which includes +floors and swaps, decreases in value, resulting in unrealized loss +positions. +Oil and +gas price risk management, net is comprised of realized and unrealized changes +in the fair value of oil and natural gas derivatives related to our oil and +natural gas production. Oil and gas price risk management, net does +not include commodity based derivative transactions related to transactions from +marketing activities, which are included in sales from and cost of natural gas +marketing activities. +Oil and Natural +Gas Derivative Activities. Because of the +uncertainty surrounding natural gas and oil prices, we have used various +derivative instruments to manage some of the effect of fluctuations in +prices. Through December 2010, we have in place a series of floors +and ceilings, or “collars”, on a portion of the natural gas and oil +production. Under the arrangements, if the applicable index rises +above the ceiling price, we pay the counterparty; however, if the index drops +below the floor, the counterparty pays us. Through February 2011, we +have fixed price swaps in place on a small portion of our natural gas +production. During the three months ended December 31, 2007, our +average monthly natural gas and oil volumes sold were 2.3 Bcf and 81,100 +Bbls. +The +following table sets forth our derivative positions in effect as of December 31, +2007, and includes positions entered into subsequently through March 3, 2008, on +our share of production by area. The table does not include positions +related to RNG or derivative contracts we entered into on behalf of our +affiliated partnerships. +Floors +Ceilings +Swaps +(Fixed Prices) +Monthly +Quantity +Monthly +Monthly +Gas-MMbtu +Contract +Quantity +Contract +Volume +Oil-Bbls +Price +MMbtu +Price +MMbtu/Bbls +Price +Month +Set +Months +Covered +Colorado +Interstate Gas (CIG) Based Hedges (Grand Valley Field, Piceance +Basin) +Dec-06 +Jan +2008 – Mar 2008 +247,700 +$ +5.25 +- +$ +- +- +$ +- +Jan-07 +Jan +2008 – Mar 2008 +247,700 +5.25 +247,700 +9.80 +- +- +Feb-08 +April +2008 – Oct 2008 +- +- +- +- +488,900 +7.05 +Jan-08 +April +2008 – Oct 2008 +- +- +- +- +410,700 +6.54 +Jan-08 +Jan +2008 - Mar 2009 +371,600 +6.50 +371,600 +10.15 +- +- +Feb-08 +Jan +2008 - Mar 2009 +221,650 +7.00 +221,650 +9.70 +- +- +Feb-08 +Jan +2008 - Mar 2009 +- +- +- +- +221,650 +8.18 +Jan-08 +April +2009 - Oct 2009 +371,600 +5.75 +371,600 +8.75 +- +- +Mar-08 +April +2009 - Oct 2009 +365,050 +5.75 +365,050 +9.05 +- +- +NYMEX +Based Hedges - (Appalachian and Michigan Basins) +Dec-06 +Jan +2008 – Mar 2008 +123,100 +7.00 +- +- +- +- +Jan-07 +Jan +2008 – Mar 2008 +123,100 +7.00 +123,100 +13.70 +- +- +Feb-08 +April +2008 – Oct 2008 +- +- +- +- +123,100 +8.33 +Feb-08 +April +2008 – Oct 2008 +- +- +- +- +123,100 +8.58 +Jan-08 +Nov +2008 - Mar 2009 +123,100 +9.00 +123,100 +11.32 +- +- +Feb-08 +Nov +2008 - Mar 2009 +72,400 +8.40 +72,400 +13.05 +- +- +Feb-08 +Nov +2008 - Mar 2009 +- +- +- +- +72,400 +9.62 +Jan-08 +April +2009 - Oct 2009 +123,100 +6.75 +123,100 +12.45 +- +- +Mar-08 +April +2009 - Oct 2009 +123,100 +7.50 +123,100 +13.25 +- +- +Feb-08 +Mar +2008 - Feb 2011 +- +- +- +- +90,000 +8.62 +37 +Table of Contents +Floors +Ceilings +Swaps +(Fixed Prices) +Monthly +Quantity +Monthly +Monthly +Gas-MMbtu +Contract +Quantity +Contract +Volume +Oil-Bbls +Price +MMbtu +Price +MMbtu/Bbls +Price +Month +Set +Months +Covered +Panhandle +Based Hedges (NECO) +Dec-06 +Jan +2008 – Mar 2008 +70,000 +5.75 +- +- +- +- +Jan-07 +Jan +2008 – Mar 2008 +90,000 +6.00 +90,000 +11.25 +- +- +Feb-08 +April +2008 – Oct 2008 +- +- +- +- +180,000 +7.45 +Jan-08 +April +2008 – Oct 2008 +- +- +- +- +120,000 +6.80 +Jan-08 +Nov +2008 - Mar 2009 +110,000 +6.75 +110,000 +10.05 +- +- +Feb-08 +Nov +2008 - Mar 2009 +80,000 +7.25 +80,000 +10.05 +- +- +Feb-08 +Nov +2008 - Mar 2009 +- +- +- +- +80,000 +8.44 +Jan-08 +April +2009 - Oct 2009 +110,000 +6.00 +110,000 +9.70 +- +- +Mar-08 +April +2009 - Oct 2009 +130,000 +6.25 +130,000 +11.75 +- +- +Colorado +Interstate Gas (CIG) Based Hedges (Wattenberg) +Jan-07 +Jan +2008 – Mar 2008 +123,650 +5.25 +123,650 +9.80 +- +- +Feb-08 +April +2008 - Oct 2008 +- +- +- +- +314,750 +7.05 +Jan-08 +April +2008 - Oct 2008 +- +- +- +- +207,350 +6.54 +Jan-08 +Nov +2008 - Mar 2009 +237,350 +6.50 +237,350 +10.15 +- +- +Feb-08 +Nov +2008 - Mar 2009 +131,150 +7.00 +131,150 +9.70 +- +- +Feb-08 +Nov +2008 - Mar 2009 +- +- +- +- +131,150 +8.18 +Jan-08 +April +2009 - Oct 2009 +237,350 +5.75 +237,350 +8.75 +- +- +Mar-08 +April +2009 - Oct 2009 +214,850 +5.75 +214,850 +9.05 +- +- +Oil +– NYMEX Based (Wattenberg/North Dakota) +Oct-07 +Jan +2008 – Dec 2008 +- +- +- +- +25,900 +84.20 +Jan-08 +Jan +2009 - Dec 2009 +- +- +- +- +16,150 +84.90 +Jan-08 +Jan +2009 - Dec 2009 +- +- +- +- +16,150 +85.40 +Jan-08 +Jan +2010 - Dec 2010 +16,150 +70.00 +16,150 +102.25 +- +- +Jan-08 +Jan +2010 - Dec 2010 +16,150 +70.00 +16,150 +103.00 +- +- +We use +oil and natural gas commodity derivative instruments to manage price risk for +ourselves as well as our sponsored drilling partnerships. We set +these instruments for ourselves and the partnerships jointly by area of +operation. As volumes produced change, the mix between PDC and the +partnerships may change. The above table reflects such revisions +necessary to present our positions in effect as of March 3, 2008. +Costs +and Expenses +Oil +and Gas Production and Well Operations Costs +Oil and +gas production and well operations costs for the years ended December 31, 2007 +and 2006, are presented below. +Year +Ended December 31, +Change +2007 +2006 +Amount +Percent +(dollars +in thousands, except per Mcfe) +Oil +and gas production and well operations cost +$ +49,264 +$ +29,021 +$ +20,243 +69.8 +% +Per +Mcfe +$ +1.76 +$ +1.71 +$ +(0.05 +) +2.9 +% +The +increase in oil and gas production and well operations costs for the year was +primarily attributable to the 65% increase in production volumes and the +increased number of wells and pipeline systems we operate as a result of our +2007 and December 2006 acquisitions. Lifting costs per Mcfe increased +8.9% from $1.23 per Mcfe in 2006 to $1.34 per Mcfe in 2007. +In +addition to increased production, the increase in costs is also attributable to +increased production and engineering staff, increased maintenance and operating +cost of the new pipeline and compressor upgrades and improvements, increased +production enhancements and workovers associated +with the December 2006 and the first quarter 2007 acquisitions and general oil +field services inflation pressures. +38 +Table of Contents +Cost +of Natural Gas Marketing Activities +Cost of +natural gas marketing activities for the years ended December 31, 2007 and 2006, +are presented below. +Year +Ended December 31, +Change +2007 +2006 +Amount +Percent +(dollars +in thousands) +Cost +of natural gas marketing activities +$ +100,584 +$ +130,150 +$ +(29,566 +) +-22.7 +% +The +decrease in the costs of natural gas marketing activities in 2007 was primarily +due to a decrease in prices and in volumes purchased, along with a $13.4 million +decrease in unrealized losses on derivative transactions, from an $11.9 million +loss in 2006 to a $1.5 million gain in 2007. In 2007, prices declined +by 5% resulting in a $5.2 million decrease in costs and volumes purchased +decreased 8% resulting in an additional $8 million decrease in +costs. In January 2007, we acquired all of the outstanding +partnership interests in 44 of our sponsored drilling +partnerships. Since this acquisition, we no longer record the natural +gas purchases from the net 423 wells acquired . In total, the natural +gas marketing segment's purchased volumes increased by 5%; however, once the now +proportionately larger inter-company volumes are eliminated, the net remaining +purchases from the natural gas marketing segment declined. +Oil +and Gas Well Drilling Operations +Cost of +oil and gas well drilling operations for the years ended December 31, 2007 and +2006, are presented below. +Year +Ended December 31, +Change +2007 +2006 +Amount +Percent +(dollars +in thousands) +Cost +of oil and gas well drilling operations +$ +2,508 +$ +12,617 +$ +(10,109 +) +-80.1 +% +The +decrease in cost of oil and gas well drilling operations was due to our change +from footage-based drilling arrangements to cost-plus drilling arrangements, +which are presented differently for accounting purposes. Beginning +with the last sponsored partnership in 2005 (for which revenue generating +activities began in 2006), our partnership wells have been drilled on a +"cost-plus" basis, which means that we charge the partnerships for the actual +cost of the wells plus an agreed upon mark-up above that cost. Prior +to that partnership, we had conducted most of our third-party drilling +activities on a footage basis, pursuant to which we drilled the wells for a +fixed price per foot drilled with additional chargeable items as provided for in +the drilling agreement. Our services provided under the cost-plus +drilling arrangements are reported net of recovered costs and reflected as +revenue in oil and gas well drilling operations, whereas the revenues under the +footage-based arrangements were recorded gross of related +expenses. For the year ended December 31, 2006, oil and gas well +drilling operations included $10 million in expenses related to footage based +arrangements. We recorded a $2.1 million loss from footage-based +contracts during the year ended December 31, 2006. +Exploration +Expense +Exploration +expense for the years ended December 31, 2007 and 2006, are presented +below. +Year +Ended December 31, +Change +2007 +2006 +Amount +Percent +(dollars +in thousands) +Exploration +expense +$ +23,551 +$ +8,131 +$ +15,420 +189.6 +% +The +increase in exploration expense for 2007 is primarily due to an exploration +agreement with an unaffiliated party, which we abandoned and for which we +recorded charges for liquidated damages of $2.7 million and $1.1 million related +to the write-off of the carrying value of the related acreage, $4.2 million in +expense related to eight exploratory dry holes, including one which was pending +determination at December 31, 2007, compared to one in 2006, $5.5 million +geological and geophysical costs related to seismic evaluation of various +exploratory prospects, $2.2 million in unproved oil and gas properties +amortization, and increased payroll and payroll related costs and other +exploratory department costs. +39 +Table of Contents +General +and Administrative Expense +General +and administrative expense for the years ended December 31, 2007 and 2006, are +presented below. +Year +Ended December 31, +Change +2007 +2006 +Amount +Percent +(dollars +in thousands, except per Mcfe) +General +and administrative expense +$ +30,968 +$ +19,047 +$ +11,921 +62.6 +% +Per +Mcfe +$ +1.11 +$ +1.12 +$ +(0.01 +) +0.9 +% +The +increase in general and administrative expense for the year was primarily due to +increased costs related to higher payroll and employee benefits costs, including +stock-based compensation for the approximately one-third increase in employees +during 2007. The increase in management personnel is attributable to +the growth we are experiencing, the increase in the cost of recruiting and the +higher compensation required to obtain experienced oil and gas +personnel. +We have +also experienced higher financial statement audit costs related to the late +filing of our 2006 Form 10-K, higher compliance costs with the various +provisions of the Sarbanes-Oxley Act, increased accounting assistance from third +party consulting services and increased legal costs. Although general +and administrative expenses increased $11.9 million from 2006 to 2007, the rate +per Mcfe declined from $1.12 per Mcfe to $1.11 per Mcfe produced. +Depreciation, +Depletion and Amortization +DD&A +expense for the years ended December 31, 2007 and 2006, are presented +below. +Year +Ended December 31, +Change +2007 +2006 +Amount +Percent +(dollars +in thousands, except per Mcfe) +Depreciation, +depletion and amortization +$ +70,844 +$ +33,735 +$ +37,109 +110.0 +% +Per +Mcfe +2.53 +1.99 +0.54 +27.1 +% +The 65% +higher production volumes realized in 2007 resulted in a $20.7 million increase +in DD&A expense in 2007 compared to 2006. The remaining period to +period change is primarily related to the cost of acquisitions of proved mineral +interest and the addition of wells, related equipment and +facilities. These acquisitions have been made at current market +prices, which are higher than our historical cost of property and +reserves. The increasing cost of well drilling, completion and +equipping of new wells along with the higher current costs of the acquisitions +during 2007 is reflected in the DD&A rates for oil and +gas properties as shown in the table below for our significant areas of +operations. +Year +Ended December 31, +2007 +2006 +(per +Mcfe) +Appalachian +Basin +$ +1.32 +$ +1.13 +Michigan +Basin +1.28 +0.83 +Rocky +Mountain Region: +Wattenberg +Field +(1) +2.99 +2.34 +Piceance +Basin +2.27 +1.83 +NECO +1.45 +1.26 +__________ +(1) +This +field contains 89.1% of our oil +production. +The +weighted average DD&A rate for oil and gas properties increased to $2.37 per +Mcfe in 2007 from $1.87 per Mcfe in 2006. DD&A expense for +non-oil and gas properties, which are not included in the above table, increased +to $4.3 million in 2007 from $2 million in 2006. +40 +Table of Contents +The +DD&A rate for oil and gas properties declined from $2.50 per Mcfe from the +third quarter of 2007 to $2.12 per Mcfe in the fourth quarter of +2007. The major reason for the decline was the upward revision in our +new reserve report as of December 31, 2007, compared to 2006 primarily due to an +upward revision in production and higher commodity prices, partially offset by +increased operating costs. The average price for natural gas in the +reserve report was $6.77 per Mcf at December 31, 2007, compared to $4.96 per Mcf +at December 31, 2006, an increase of $1.81 per Mcf or 36.5%. The +average price for oil was $80.67 per barrel at December 31, 2007, compared to +$57.70 per barrel at December 31, 2006, an increase of $22.97 per barrel or +39.8%. +Gain +on Sale of Leaseholds +In July +2006, we entered into a purchase and sale agreement with an unaffiliated party +regarding the sale of our undeveloped leasehold located in the Grand Valley +Field, Garfield County, Colorado, as filed with the Securities and Exchange +Commission, or SEC, as Exhibit 10.3 to the Form 10-Q for the period ended +September 30, 2006. Total proceeds from the sale were $353.6 million, +of which we recognized a $328 million gain on sale of leasehold in the third +quarter of 2006. +In +May 2007, we entered into a letter agreement amending the above +mentioned purchase and sale agreement, relieving us of our obligation, in its +entirety, to either drill 16 wells or pay liquidated damages of $1.6 million per +undrilled well. As a result, we recognized the remaining deferred +gain of $25.6 million in the second quarter of 2007. +In +December 2007, we sold to the same unaffiliated party a portion of our North +Dakota properties for approximately $34.7 million. The properties, +located in Dunn, Williams and McKenzie Counties, North Dakota, include interests +in five producing Bakken wells and approximately 72,000 net undeveloped +acres. We recorded a gain on sale of leaseholds of $7.7 million in +the fourth quarter of 2007. +Non-operating +Income/Expense +Non-operating +income and expense for the years ended December 30, 2007 and 2006, are presented +below. +Year +Ended December 31, +Change +2007 +2006 +Amount +Percent +(dollars +in thousands) +Non-operating +income (expense): +Interest +income +$ +2,662 +$ +8,050 +$ +(5,388 +) +-66.9 +% +Interest +expense +$ +(9,279 +) +$ +(2,443 +) +$ +(6,836 +) +279.8 +% +The +decrease in interest income for the quarter is a result of lower cash balances +earning interest compared to the same period last year, primarily due to the +$353.6 million in cash proceeds from the sale of undeveloped leaseholds in July +2006. The proceeds were reinvested in oil and gas properties by +mid-January 2007. The increase in interest expense in 2007 was due to +significantly higher average outstanding balances of our credit facility, offset +by capitalized construction period interest of $3 million in 2007 compared to +$1.6 million in 2006. We utilize our daily cash balances to reduce +the line of credit, lowering the costs of interest. +Provision +for Income Taxes +The +effective income tax rate for the provision for income taxes for 2007, was +38.7%, relatively unchanged from 38.6% for 2006. The benefit we +received from the 2007 domestic production deduction was offset by +non-deductible income tax and production tax penalties that were expensed during +the year. +Year Ended December 31, +2006, Compared to December 31, 2005 +Management +Overview +Net +Income +Year +Ended December 31, +Change +2006 +2005 +Amount +Percent +(dollars +in thousands, except per share data) +Net +income +$ +237,772 +$ +41,452 +$ +196,320 +473.6 +% +Diluted +earnings per share +$ +15.11 +$ +2.52 +$ +12.59 +499.6 +% +41 +Table of Contents +Revenues +Revenues +for the years ended December 31, 2006 and 2005, are presented +below. +Year +Ended December 31, +Change +2006 +2005 +Amount +Percent +(dollars +in thousands) +Revenues: +Oil +and gas sales +$ +115,189 +$ +102,559 +$ +12,630 +12.3 +% +Sales +from natural gas marketing activities +131,325 +121,104 +10,221 +8.4 +% +Oil +and gas well drilling operations +17,917 +99,963 +(82,046 +) +-82.1 +% +Well +operations and pipeline income +10,704 +8,760 +1,944 +22.2 +% +Oil +and gas price risk management gain (loss) net +9,147 +(9,368 +) +18,515 +-197.6 +% +Other +2,221 +2,180 +41 +1.9 +% +Total +revenues +$ +286,503 +$ +325,198 +$ +(38,695 +) +-11.9 +% +The +decrease in revenues was primarily attributable to a decrease in drilling +revenues of $82.1 million partially offset by the increased oil and gas sales +from both gas marketing activities and our share of production for a total of +$22.9 million and the swing from a $9.4 million loss in oil and gas price risk +management for the year ended December 31, 2005, to a gain of $9.1 million for +the year ended December 31, 2006. See Drilling +Operations below for an explanation of the effect the new cost-plus +drilling arrangements and related accounting had on drilling revenues for the +year 2006. +Costs +and Expenses +Costs and +expenses for the years ended December 31, 2006 and 2005, are presented +below. +Year +Ended December 31, +Change +2006 +2005 +Amount +Percent +(dollars +in thousands) +Costs +and expenses: +Oil +and gas production and well operations cost +$ +29,021 +$ +20,400 +$ +8,621 +42.3 +% +Cost +of natural gas marketing activities +130,150 +119,644 +10,506 +8.8 +% +Cost +of oil and gas well drilling operations +12,617 +88,185 +(75,568 +) +-85.7 +% +Exploration +expense +8,131 +11,115 +(2,984 +) +-26.9 +% +General +and administrative expense +19,047 +6,960 +12,087 +173.7 +% +Depreciation, +depletion and amortization +33,735 +21,116 +12,619 +59.8 +% +Total +costs and expenses +$ +232,701 +$ +267,420 +$ +(34,719 +) +-13.0 +% +The +decrease in costs was primarily attributable to decreases in the cost of oil and +gas well drilling operations of $75.6 million and exploration cost of $3 million +offset in part by increases in the cost of gas marketing activities of $10.5 +million, oil and gas production and well operations costs of $8.6 million, +general and administrative expenses of $12.1 million and depreciation, depletion +and amortization of $12.6 million. See Drilling +Operations below for an explanation of the effect of the new cost plus +drilling arrangements and related accounting had on drilling expenses for the +year 2006. +Results +of Operations +Revenues +Oil +and Gas Sales +Revenues +for oil and gas sales for the years ended December 31, 2006 and 2005, are +presented below. +Year +Ended December 31, +Change +2006 +2005 +Amount +Percent +(dollars +in thousands) +Oil +and gas sales +$ +115,189 +$ +102,559 +$ +12,630 +12.3 +% +42 +Table of Contents +The +increase was due to a 24% increase in volumes sold at lower average sales prices +of natural gas and, in part, to higher average sales prices and higher volumes +sold of oil. The volume of natural gas sold for the year ended +December 31, 2006, was 13.2 Bcf at an average price of $5.91 per Mcf compared to +11.0 Bcf at an average sales price of $7.29 per Mcf for the year ended December +31, 2005. Oil sales for the year ended December 31, 2006, were +631,000 barrels at an average sales price of $59.33 per barrel compared to +439,000 barrels at an average sales price of $50.56 per barrel for the year +ended December 31, 2005. The increase in natural gas and oil volumes +was the result of our increased investment in oil and gas properties, primarily +the increase in net wells drilled for our own account, recompletions of existing +wells, and the investment in oil and gas properties we own in drilling program +partnerships. +Oil +and Gas Production +Our oil +and gas production by area of operations along with average sales price +(excluding derivative losses) is presented below: +Year +Ended December 31, +Change +2006 +2005 +Amount +Percent +Natural +Gas (Mcf) +Appalachian +Basin +1,451,729 +1,631,552 +(179,823 +) +-11.0 +% +Michigan +Basin +1,399,852 +1,555,958 +(156,106 +) +-10.0 +% +Rocky +Mountains +10,309,203 +7,843,250 +2,465,953 +31.4 +% +Total +13,160,784 +11,030,760 +2,130,024 +19.3 +% +Average +Sales Price +$ +5.91 +$ +7.29 +$ +(1.38 +) +-18.9 +% +Oil +(Bbls) +Appalachian +Basin +1,837 +3,973 +(2,136 +) +-53.8 +% +Michigan +Basin +4,439 +4,732 +(293 +) +-6.2 +% +Rocky +Mountains +625,119 +430,266 +194,853 +45.3 +% +Total +631,395 +438,971 +192,424 +43.8 +% +Average +Sales Price +$ +59.33 +$ +50.56 +$ +8.77 +17.3 +% +Natural +Gas Equivalents (Mcfe)* +Appalachian +Basin +1,462,751 +1,655,390 +(192,639 +) +-11.6 +% +Michigan +Basin +1,426,486 +1,584,350 +(157,864 +) +-10.0 +% +Rocky +Mountains +14,059,917 +10,424,846 +3,635,071 +34.9 +% +Total +16,949,154 +13,664,586 +3,284,568 +24.0 +% +Average +Sales Price +$ +6.80 +$ +7.51 +$ +(0.71 +) +-9.5 +% +_____________ +*One +Bbl of oil is equal to the energy equivalent of six Mcf of natural +gas. +Sales +from Natural Gas Marketing Activities +Year +Ended December 31, +Change +2006 +2005 +Amount +Percent +(dollars +in thousands) +Sales +from natural gas marketing activities +$ +131,325 +$ +121,104 +$ +10,221 +8.4 +% +The +increase in revenue was the result of a 9% increase in volumes sold at prices +17.2% lower than 2005 levels and significant unrealized gains on derivative +transactions which amounted to approximately $12.3 million for the year ended +December 31, 2006, compared to unrealized losses of $8.5 million for the year +ended December 31, 2005. +43 +Table of Contents +Oil +and Gas Drilling Operations +Revenues +for oil and gas drilling operations for the years ended December 31, 2006 and +2005, are presented below. +Year +Ended December 31, +Change +2006 +2005 +Amount +Percent +(dollars +in thousands) +Oil +and gas well drilling operations +$ +17,917 +$ +99,963 +$ +(82,046 +) +-82.1 +% +During +the first quarter of 2006, we began operating and recognizing revenues for our +cost-plus service arrangements with new partnerships, in addition to our +footage-based drilling arrangements on earlier partnerships. The +cost-plus drilling arrangements became effective with the private program +partnership we funded in December 2005 and continued in the 2006 partnership +funded on September 1, 2006. Drilling revenues for the year ended +December 31, 2006, were $17.9 million, net of $74.6 million of costs related to +drilling arrangements accounted for on the cost-plus basis, compared to $100 +million for the year ended December 31, 2005, a decrease of $82.1 +million. The decrease was primarily due to the change in our drilling +contracts, which resulted in net revenue recognition related to the new +contracts. +Although +we changed to cost-plus drilling arrangements with our two recent partnerships, +prior footage-based contracts continue to be in effect, and realized a loss of +$2.1 million during 2006. This loss contributed to the decrease in +the drilling and development segment gross margin from $11.8 million for the +year ended December 31, 2005, to $5.3 million for the year ended December 31, +2006. This loss was due to some drilling and completion difficulties +incurred and significantly increasing well drilling and completion costs, +particularly the costs of fracturing and rising steel costs for casing and other +well equipment and oil field services. Future partnerships will be +drilled on a “cost-plus basis,” which should reduce these fluctuations in +drilling gross margins. See Note 1 , Summary of Significant Accounting +Policies , to our accompanying consolidated financial +statements. +Well +Operations and Pipeline Income +Revenues +for Well operations and pipeline income for the years ended December 31, 2006 +and 2005, are presented below. +Year +Ended December 31, +Change +2006 +2005 +Amount +Percent +(dollars +in thousands) +Well +operations and pipeline income +$ +10,704 +$ +8,760 +$ +1,944 +22.2 +% +The +increase in revenue was due to an increase in the number of wells and pipeline +systems we operate for drilling partnerships, as well as for third +parties. +Oil +and Gas Price Risk Management Gain (Loss), Net +Oil and +gas price risk management, net for the years ended December 31, 2006 and 2005, +is presented below. +Year +Ended December 31, +Change +2006 +2005 +Amount +Percent +(dollars +in thousands) +Oil +and gas price risk management gain (loss), net +$ +9,147 +$ +(9,368 +) +$ +18,515 +-197.6 +% +For the +year ended December 31, 2006, we recorded realized gains of $1.9 million and +unrealized gains of $7.2 million compared to the year ended December 31, 2005, +which is comprised of unrealized losses of $3 million and realized losses of +$6.4 million. Our strategy is to provide protection in the event of +declining oil and natural gas prices. During 2006, we experienced +decreasing natural gas and rising oil pricing environments. This +trend and the timing, extent and nature of the derivative trades executed caused +us to record gains in our derivative transactions as a result of gains on the +natural gas positions. Oil and gas price risk management gains +(losses), net is comprised of the change in fair value of oil and natural gas +derivatives related to oil and gas production (this line item does not include +commodity-based derivative transactions related to transactions from gas +marketing activities, which are included in the revenues and expenses of the +related purchase and sales transactions). +44 +Table of Contents +Other +Income +Other +income, consisting primarily of management fees associated with +Company-sponsored drilling programs, was relatively unchanged at $2.2 million +for each of the years ended December 31, 2006 and 2005. +Costs +and Expenses +Oil +and Gas Production and Well Operations Costs +Oil and +gas production and well operations costs for the years ended December 31, 2006 +and 2005, are presented below. +Year +Ended December 31, +Change +2006 +2005 +Amount +Percent +(dollars +in thousands, except per Mcfe) +Oil +and gas production and well operations cost +$ +29,021 +$ +20,400 +$ +8,621 +42.3 +% +Per +Mcfe +$ +1.71 +$ +1.49 +$ +0.22 +14.7 +% +The +increase in cost was due to the increased production costs associated with the +24% increase in production volumes, along with the increased number of wells and +pipelines we operate. Lifting costs per Mcfe increased from $1.19 per +Mcfe for the year ended December 31, 2005, to $1.23 per Mcfe for the year ended +December 31, 2006, due to the significant inflation of oil field production +services along with additional well workovers and production enhancements work +performed. +Cost +of Natural Gas Marketing Cost +Cost of +natural gas marketing activities for the years ended December 31, 2006 and 2005, +are presented below. +Year +Ended December 31, +Change +2006 +2005 +Amount +Percent +(dollars +in thousands) +Cost +of natural gas marketing activities +$ +130,150 +$ +119,644 +$ +10,506 +8.8 +% +The +increase in cost was due to higher average volumes of natural gas purchased for +resale and a significant increase in unrealized losses on derivative +transactions, which amounted to approximately $11.9 million for the year ended +December 31, 2006, compared to an unrealized gain of $8.3 million for the year +ended December 31, 2005. Income before income taxes for our natural +gas marketing subsidiary increased from $1.7 million for the year ended December +31, 2005, to $1.8 million for the year ended December 31, 2006. Based +on the nature of our gas marketing activities, derivatives did not have a +significant effect on our net margins from marketing activities during either +period. +Cost +of Oil and Gas Well Drilling Operations +Cost of +oil and gas well drilling operations for +the years ended December 31, 2006 and 2005, are presented below. +Year +Ended December 31, +Change +2006 +2005 +Amount +Percent +(dollars +in thousands) +Cost +of oil and gas well drilling operations +$ +12,617 +$ +88,185 +$ +(75,568 +) +-85.7 +% +The +decrease in costs is primarily attributable to our revenue reporting for our new +cost-plus drilling arrangements, which reduced drilling costs by $74.6 million +for the year as discussed above. +The new +cost-plus drilling arrangement eliminates our risk of loss from the contract +drilling services we provide the partnerships. Our drilling revenues +and corresponding costs are presented net as a one-lined income statement item +representing only the gross profit portion of the drilling +arrangement. The new cost-plus contract affected 2006 by reducing +drilling revenues and drilling costs by $74.6 million as outlined in the table +below (in millions): +45 +Table of Contents +Year +ended December 31, +2006 +2005 +Drilling +Service Revenue/Cost +Direct +Reimbursed Cost +Revenue/Cost +including +reimbursement +from Partnerships +Drilling +Service Revenue/Cost +Oil +and gas well drilling operations +$ +17.9 +$ +74.6 +$ +92.5 +$ +100.0 +Total +revenues +286.5 +74.6 +361.1 +325.2 +Cost +of oil and gas well drilling operations +12.6 +74.6 +87.2 +88.2 +Total +costs and expenses +232.7 +74.6 +307.3 +267.4 +Exploration +Expense +Exploration +expense for the years ended December 31, 2006 and 2005, is presented +below. +Year +Ended December 31, +Change +2006 +2005 +Amount +Percent +(dollars +in thousands) +Exploration +expense +$ +8,131 +$ +11,115 +$ +(2,984 +) +-26.8 +% +The +decrease in expense is primarily attributable to fewer exploratory dry holes +being drilled in 2006. In 2006, exploratory dry hole expenses were +$1.8 million compared to $11.1 million in 2005. In 2006, we recorded +an impairment charge of $1.5 million on our Nesson Field in North Dakota and +incurred geological and geophysical costs of $2.2 million which relate to an +exploratory seismic program initiated on our Northeast Colorado +properties. We anticipate additional geological and geophysical +activities and related costs in 2007. +General +and Administrative Expense +General +and administrative expense for the years ended December 31, 2006 and 2005, is +presented below. +Year +Ended December 31, +Change +2006 +2005 +Amount +Percent +(dollars +in thousands, except per Mcfe) +General +and administrative expense +$ +19,047 +$ +6,960 +$ +12,087 +173.7 +% +Per +Mcfe +$ +1.12 +$ +0.51 +$ +0.61 +119.6 +% +A +substantial portion of the increase was attributable to the costs of our +financial statement restatement and the restatement of our sponsored +partnerships’ financial statements. In addition, we continue to +experience a high level of costs complying with the various provisions of the +Sarbanes-Oxley Act, in particular Section 404 (internal and external costs of +assessing Internal Controls over Financial Reporting). Approximately +$3.2 million of the increase is attributable to the external costs incurred in +connection with restatement of financial statements and compliance with the +provisions of the Sarbanes-Oxley Act. Finally, we added over 39 new +employees in 2006 and experienced increased payroll and payroll-related costs of +$4.3 million. +46 +Table of Contents +Depreciation, +Depletion, and Amortization +DD&A expense for the years ended +December 31, 2006 and 2005, is presented below. +Year +Ended December 31, +Change +2006 +2005 +Amount +Percent +(dollars +in thousands, except per Mcfe) +Depreciation, +depletion and amortization +$ +33,735 +$ +21,116 +$ +12,619 +59.8 +% +Per +Mcfe +$ +1.99 +$ +1.55 +$ +0.44 +28.4 +% +The +increase in cost was due to the 24% increase in production volumes, significant +investments in oil and gas properties by us in 2006, and increased per unit cost +of depreciation, depletion and amortization as a result of rising costs of +drilling, completing and equipping wells. +Gain +on Sale of Leaseholds +Gain on +sale of leaseholds for the year ended December 31, 2006, was $328 million +compared to $7.7 million in 2005, an increase of $320.3 million. The +increase is attributable to the sale of undeveloped leaseholds in Garfield +County, Colorado in the third quarter of 2006, for which a portion of the gain +to be recognized was deferred to future periods. See Note 16 , Sale of Oil and Gas +Properties , to our accompanying consolidated financial +statements. The prior year period included a gain of $6.2 million for +the sale of a portion of one of our undeveloped leases in Garfield County, +Colorado and a gain of $1.5 million for the sale to an unaffiliated party of +some Pennsylvania wells. +Non-Operating +Income/Expense +Year +Ended December 31, +Change +2006 +2005 +Amount +Percent +(dollars +in thousands) +Non-operating +income (expense): +Interest +income +$ +8,050 +$ +898 +$ +7,152 +796.4 +% +Interest +expense +$ +(2,443 +) +$ +(217 +) +$ +(2,226 +) +1025.8 +% +The +increase in interest income was primarily due to the interest on the temporary +investment, in cash equivalents, of cash proceeds of $353.6 million from the +sale of undeveloped leaseholds. The increase in interest expense was +due to rising interest rates on significantly higher average outstanding +balances of the credit facility, offset in part by $1.6 million of capitalized +construction period interest. We utilize our daily cash balances to +reduce our line of credit to lower our cost of borrowing. The average +outstanding debt balance for the year ended December 31, 2006, was $44.2 million +compared to $4.1 million for the year ended December 31, 2005. +Provision +for Income Taxes +The +effective income tax rate for our provision for income taxes increased from +37.3% for the year ended December 31, 2005, to 38.6% for the year ended December +31, 2006, primarily as a result of the gain on sale of leasehold being taxed at +the full federal and state statutory rates because there are no offsetting +permanent deductions, such as percentage depletion, available on such a +sale. In addition, the domestic production activities deduction was +not utilized in 2006 due to our decision, for tax purposes only, to expense the +majority of our intangible drilling costs. +Liquidity +and Capital Resources +Cash flow +from operations and our bank credit facility are our primary sources of +liquidity to meet operating expenses and fund capital expenditures (other than +for certain acquisitions). Recently, as of February 8, 2008, we +completed the issuance and sale of $203 million of 12% senior notes due 2018 for +net proceeds received of approximately $196 million. The completion +of the issuance and sale of our senior notes enabled us to reduce our short term +liquidity risk through the terming out of our existing credit facility of +November 2010 and extending it until February 2018. The repayment of +the amounts outstanding under the credit facility with a portion of the net +proceeds from the senior notes provided $234.1 million of available borrowing +capacity. As of February 29, 2008, we have access to all of the +$234.1 million facility as it was un-drawn. Additionally, we believe +that our continued drilling activities will allow us, through our permitted +borrowing base re-determinations, to increase the borrowing capacity of the +credit facility. See Long Term Debt discussed +below. +47 +Table of Contents +Our 2008 +capital expenditure budget is $255 million: $194 million for drilling and +development; $50 million for exploratory drilling, land acquisitions and seismic +activities; and $11 million for other capital expenditures. We +believe this level of exploration and development activity will be sufficient to +increase our proved oil and natural gas reserves in 2008 and increase our total +production by between 30% and 40% (without regard to any additional acquisitions +that may be completed in 2008). We retain a significant degree of +control over the timing of our capital expenditures, which permits us to defer +or accelerate certain capital expenditures if necessary to address any potential +liquidity issues. In addition, higher drilling and field operating +costs, drilling results that alter planned development schedules, acquisitions +or other factors could cause us to revise our drilling program, which programs +are largely discretionary. We believe that our available cash, cash +provided by operating activities and funds available under our revolving credit +facility will be sufficient to fund our operations, debt service, partnership +drilling obligation, general and administrative expenses, capital budget, and +short-term contractual obligations for the next few years . +Changes +in market prices for oil and natural gas directly affect the level of our cash +flow from operations. While a decline in oil and natural gas prices +would affect the amount of cash flow that would be generated from operations, we +had oil and natural gas hedges in place, as of March 3, 2008, covering 41% of +our expected oil production and 62% of our expected natural gas production in +2008, thereby providing price certainty for a substantial portion of our 2008 +cash flow. Depending on changes in oil and natural gas futures +markets and our view of underlying oil and natural gas supply and demand trends, +we may increase or decrease our current hedging positions. Our oil +and natural gas hedges as of December 31, 2007, are detailed in Item 7A of this +report. +We have +utilized public and private markets, proceeds from bank borrowings and cash flow +from operations for our capital resources and liquidity. To date, our +primary use of capital has been for the acquisition and development of oil and +gas properties. As we pursue growth, we will continually monitor the +capital resources available to meet our future financial obligations and planned +capital expenditures. Our future success in replacing and growing +reserve levels will be highly dependent on the capital resources available and +our success in drilling for or acquiring additional reserves. We +actively review acquisition opportunities on an ongoing basis. If we +were to make significant additional acquisitions for cash, we would need to +borrow additional amounts under our current credit facility, if available, or +obtain additional debt or equity financing. +On +January 7, 2008, we announced that we do not plan to sponsor new drilling +partnerships in 2008 in order to focus our efforts on continuing our growth +through drilling and exploration. In 2008, we expect +to recognize $7.8 million in oil and gas well drilling revenue related to +the 2007 drilling partnership. +Operating +Cash Flows +Net cash +provided by operating activities was $60.3 million in 2007 compared to $67.4 +million in 2006, a decrease of $7.1 million. The decrease in cash +provided by operating activities was due primarily to the +following: +· +Increased +costs from production and well operations related to the 65% increase in +production, as well as the increases in exploration and general and +administrative expenses, partially offset by the increase in oil and gas +sales revenues; +· +Federal +and state taxes payable decreased primarily due to the 2007 payment of +taxes of the non deferred portion of the gain on the sale of the Grand +Valley Field Acreage; +· +The +decrease in accounts payable is primarily due to the timing of payments +related to the purchase of properties and +equipment; +· +Current +restricted cash increased due to the funding in 2007 of an escrow account +for amounts due limited partners as a result of over withholding of +estimated production taxes; +· +Accounts +payable to affiliates decreased for the partnership’s share of unpaid +premiums and unrealized losses related to hedge positions at December 31, +2007; +· +Production +tax liability increased due to the 65% increase in oil and gas production +volumes in 2007; and +· +Advances +for future drilling contracts increased due to the timing of drilling and +development activities on behalf of our 2007 sponsored drilling +partnership. +Net cash +provided by operating activities was $67.4 million in 2006 compared to $112.4 +million in 2005, a decrease of $45 million. +The +decrease in cash provided by operating activities was due primarily to the +following: +· +Increased +costs from production and well operations related to the 24% increase in +production volumes and increased number of +wells; +· +Increase +in general and administrative costs due to the Company’s financial +statement restatement and incremental costs to comply with various +provisions of Sarbanes-Oxley partially offset by; +and +· +The +increase in oil and gas sales revenues due to the 24% increase in +production volumes at lower unit sales +prices. +48 +Table of Contents +Investing +Cash Flows +Net cash +used in investing activities was $267.4 million in 2007 compared to $9.6 million +in 2006, an increase of $257.8 million. +The +increase in cash used in investing activities was due primarily to the +following: +· +An +approximate $93 million increase in capital expenditures is primarily due +to an increase in the number of wells drilled to 349 in 2007 from 231 in +2006 or approximately $72 +million; and +· +Acquisitions +of oil and natural gas properties of approximately $256 +million; +Partially +offset by: +· +The +2006 acquisition of Unioil of approximately $18 million; +and +· +The +net effect of the transfer of the funds from the Like kind exchange, or +LKE, from restricted cash and the proceeds from the 2006 sale of the Grand +Valley Field acreage. +Net cash +used in investing activities was $9.6 million in 2006 compared to $94 million in +2005, a decrease of $84.4 million. The decrease in cash used in +investing activities was due primarily to the following: +· +An +approximate $49 million increase in the capital expenditures; +and +· +Approximately +$192 million increase in restricted/designated cash due to +acquisitions; +Partially +offset by: +· +An +approximate $344 million increase in proceeds from sale of +leasehold/assets due to the sale of the Grand Valley Field acreage in July +2006. +Financing +Cash Flows +Net cash +provided by financing activities was $97.5 million in 2007 compared to $46.5 +million in 2006, an increase of $51 million. The increase in cash +provided by financing activities was due primarily to the +following: +· +A +decrease of treasury stock purchases of approximately $66 million offset +by the net change in short and long term debt from borrowing +activities. +Net cash +provided by financing activities was $46.5 million in 2006 compared to net cash +used in financing activities of $5.3 million in 2005, an increase of $51.8 +million. The increase in cash provided by financing activities was +due primarily to the following: +· +An +approximate $110 million increase in proceeds from the issuance of +long-term and short-term debt, net of retirement of debt, in +2006; +Partially +offset by: +· +An +approximate $59 million of additional treasury stock +purchases. +Working +Capital +Our +working capital usage for 2007 was $50.2 million. At December 31, +2007, we had available borrowing capacity under our bank credit facility of $60 +million. Historically, we have satisfied our working capital needs +through free cash flow and borrowings under our credit facility. We +may need to raise additional capital in the bank, private and public markets to +fund future acquisitions and increases in capital expenditure +levels. We expect to continue to maintain adequate liquidity to meet +our obligations on an ongoing basis. If we are unable to raise +incremental capital, future capital expenditures and acquisitions may be +affected. We used most of the net proceeds of approximately $196 +million from our February 8, 2008, $203 million senior notes offering to repay +the $180 million then drawn under our bank credit facility. Upon the +issuance of our senior notes on February 8, 2008, our activated commitment of +$295 million was mandatorily reduced to $234.1 million. As of +February 29, 2008, our outstanding credit facility was +un-drawn. Based on near-term cash flow projections, the discretionary +nature of our capital program, our bank credit facility capacity and the +demonstrated ability to raise capital in bank, private and public markets, we +believe that we have sufficient liquidity to fund our operations in +2008. +49 +Table of Contents +Long-Term +Debt +We +have a credit facility with JPMorgan Chase Bank, N.A., or JPMorgan, and BNP +Paribas, as amended, dated as of November 4, 2005, with an activated commitment +of $295 million as of December 31, 2007. The credit facility, through +a series of amendments, includes commitments from Wachovia Bank, N.A., Bank of +Oklahoma, Allied Irish Banks p.l.c., Guaranty Bank, BSB, Royal Bank of Canada +and The Royal Bank of Scotland, plc. The maximum allowable commitment +under the current credit facility is $400 million. The credit +facility is subject to and secured by required levels of natural gas and oil and +reserves. The credit facility requires an aggregated security of a +value no less than 80% of the value of the direct interests included in the +borrowing base properties. We are required to pay a commitment fee of +0.25% to 0.375% per annum on the unused portion of the activated credit +facility. Interest accrues at an alternative base rate or adjusted +LIBOR at our discretion. The +alternative base rate is the greater of JPMorgan's prime rate, an adjusted +secondary market rate for a three-month certificate of deposit plus 1% or the +federal funds effective rate plus 0.5%. Alternative base rate +borrowings are assessed an additional margin spread up to 0.375% and adjusted +LIBOR borrowings are assessed an additional margin spread of 1.125% to 1.875%, +based upon the outstanding balance under the credit facility. The +credit agreement requires, among other things, the maintenance of certain +working capital and tangible net worth ratios. No principal payments +are required until the credit agreement expires on November 4, +2010. +Effective +August 9, 2007, the first amendment to our credit facility waived our working +capital covenant until the earlier of (i) a debt or equity transaction resulting +in net proceeds, as defined, to us of at least $200 million or (ii) July 1, +2008, which was further extended to October 1, 2008, effective October 16, +2007. In accordance with the first amendment, the alternative base +rate was increased by 0.375% as long as the waiver of the working capital +covenant was in effect. +On +February 8, 2008, we completed the issuance and sale of $203 million aggregate +principal amount of 12% senior notes due 2018 for net proceeds received of +approximately $196 million; see Note 5 , Long Term Debt , to our +accompanying consolidated financial statements. In accordance with +the senior credit agreement, upon the issuance of any senior notes, the +borrowing base then in effect on our credit facility shall automatically be +reduced by $300 for each $1,000 in stated principal amount of such senior notes +issued by us. Accordingly, effective February 8, 2008, our borrowing +base under the credit facility was reduced from $295 million to $234.1 +million. Further, our senior notes issuance meets the requirements of +a debt transaction described above, and thus, the testing of our working capital +covenant will resume with our quarter ending March 31, 2008. +As of +December 31, 2007, the outstanding balance under our credit facility was $235 +million compared to $117 million, excluding the overline note discussed below, +as of December 31, 2006. The borrowing rate on the outstanding +balance was 7.07% and 7.79% at December 31, 2007, and December 31, 2006, +respectively. Amounts outstanding under the credit facility were +secured by substantially all of our properties. We were in compliance +with all covenants at December 31, 2007, and expect to remain in compliance +throughout 2008. +On +December 19, 2006, we executed, pursuant to our credit facility, an overline +note in the amount of $20 million to be repaid on January 31, +2007. Interest on the overline note accrued at a per annum rate equal +to the alternate base rate plus 0.8% until December 22, 2006, at which time the +rate converted to a Eurodollar borrowing for a one month period and at a per +annum rate equal to an adjusted LIBOR rate plus 2.30%. The overline +note was paid in full in accordance with its terms in January 2007. +Drilling +Programs +In August +2007, we completed our sponsored drilling partnership offering, Rockies Region +2007 Limited Partnership, and received subscriptions of approximately $90 +million. We contributed $38.7 million, which represented 43% of the +$90 million of total subscriptions received, for our general partner capital +contribution. Drilling for the partnership commenced during the third +quarter and continued in the fourth quarter of 2007. From inception +to December 31, 2007, $5.3 million in revenues has been +recognized. On December 28, 2007, the drilling partnership paid to us +$54 million, in accordance with the partnership agreement, to secure intangible +drilling cost tax deductions for the investing partners. This payment is +included in advances for future drilling contracts on our consolidated balance +sheet. In early January 2008, we used this advance to pay down our +credit facility. Drilling and completion operations for the 2007 +drilling program will continue through the first half of 2008. We +expect to recognize additional revenue of approximately $7.8 million in our oil +and gas well drilling operations related to this partnership during +2008. In January 2008, we announced that we do not plan to sponsor +new drilling partnerships in 2008 in order to focus our effort on maximizing the +value of the existing partnerships and our continuing growth through drilling +and exploration. +50 +Table of Contents +Treasury +Share Purchases +On +October 16, 2006, our Board of Directors approved a second 2006 share purchase +program authorizing us to purchase up to 10% of our then outstanding common +stock (1,477,109 shares) through April 2008. Stock purchases under +this program may be made in the open market or in private transactions, at times +and in amounts that we deem appropriate. Shares are generally +purchased at fair market value based on the closing price on the date of +purchase. Total shares purchased in 2007 pursuant to the program were +12,020 common shares at a cost of $0.6 million ($53.78 average price paid per +share), including 5,187 shares from our executive officers at a cost of $0.3 +million ($57.93 price paid per share). Shares purchased pursuant to +the plan were primarily to satisfy the statutory minimum tax withholding +requirement for restricted stock that vested in 2007. All shares were +subsequently retired. At December 31, 2007, the remaining number of +shares that may be purchased under this program is 1,465,089, see Item 5 , Market for Registrant's Common +Equity and Related Stockholders Matters - Issuer Purchases of Equity +Securities , of this report for a reconciliation of +activities. +Pursuant to our senior notes indenture entered on February 8, +2008, any future purchases are limited, see Note 19, Subsequent Events , to our accompanying +consolidated financial statements. +On +February 25, 2008, pursuant to a separation agreement, we purchased 50,000 +shares of our common stock from one of our executive officers at a cost of $3.4 +million, or $67.92 per share. See Note 19 , Subsequent Events , to our +accompanying consolidated financial statements. +Contractual +Obligations and Contingent Commitments +The table +below sets forth our contractual obligations and contingent commitments as of +December 31, 2007: +Payments +due by period +Contractual +Obligations and Contingent Commitments +Total +Less +than +1 +year +1-3 +years +3-5 +years +More +than +5 +years +(in +thousands) +Debt (1) +$ +235,000 +$ +- +$ +235,000 +$ +- +$ +- +Interest +(2) +47,255 +16,613 +30,642 +- +- +Operating +leases +4,460 +1,948 +1,827 +685 +- +Asset +retirement obligations +20,781 +50 +100 +100 +20,531 +Rig +commitments (3) +24,669 +8,810 +15,859 +- +- +Drilling +commitments (4) +3,655 +- +1,155 +- +2,500 +Other +liabilities (5) +8,876 +1,133 +720 +720 +6,303 +Total +$ +344,696 +$ +28,554 +$ +285,303 +$ +1,505 +$ +29,334 +__________ +(1) +Long-term +debt does not include interest. +(2) +Interest +based on balance at December 31, 2007, at an applied rate of +7.07%. +(3) +Drilling rig commitments in +the above table do not include future adjustments to daily rates as +provided for in the agreements as such increases are not predictable and +are only included in the above obligation table upon notification to us by +the contractor of an increase in the +rate . +(4) +Amounts +represent our maximum obligation for potential liquidating damages if we +do not comply with certain drilling and development +agreements. See Note 8, Commitments and Contingencies, to our +accompanying consolidated financial statements. These amounts +do not include advances for future drilling contracts totaling $68.4 +million at December 31, 2007. +(5) +Includes +funds held from revenue distribution to third party investors for plugging +liabilities related to wells we operate and deferred officer compensation. +Further, includes unrecognized tax benefits totaling $0.9 million pursuant +to FIN No. 48. +(6) +Table +does not include maximum annual repurchase obligation of $6.7 million as +of December 31, 2007, see Note 8, Commitments and Contingencies, to our +accompanying consolidated financial +statements. +51 +Table of Contents +Commitments +and Contingencies +As +managing general partner of 33 partnerships (see Item 1. Business – +Drilling and Development +Conducted for Company Sponsored Partnerships , we have liability for any +potential casualty losses in excess of the partnership assets and +insurance. In January 2007, we purchased the remaining working +interests in 44 of 77 partnerships, which we sponsored in the late 1980s and +1990s (see Note +2 , Acquisitions , +to our accompanying consolidated financial statements). We believe +that the casualty insurance coverage we and our subcontractors carry is adequate +to meet this potential liability. +For +information regarding our legal proceedings, see Note 8 , Commitments and Contingencies – +Litigation , to our accompanying consolidated financial statements +included in this report. +From time +to time we are a party to various other legal proceedings in the ordinary course +of business. We are not currently a party to any litigation that we +believe would have a materially adverse affect on our business, financial +condition, results of operations, or liquidity. +Sale +of Undeveloped Leaseholds +In July +2006, we sold to an unaffiliated company a portion of our undeveloped leasehold +located in Grand Valley Field, Garfield County, Colorado. The sale +encompassed 100% of the working interest in approximately 8,700 acres, including +approximately 6,400 acres of the Chevron leasehold and 2,300 acres of the +Puckett Land Company leasehold. We retained approximately 475 +undeveloped locations on 10 acre spacing on the Grand Valley Field leasehold in +addition to all of our producing properties in the field. The +proceeds from the sale were $353.6 million. We recorded a gain on +sale of leaseholds of $328 million and a deferred gain on sale of leaseholds of +$25.6 million. +Pursuant +to the purchase and sale agreement, we were obligated to either drill 16 wells +on specifically identified acreage over the next three years or pay liquidated +damages of $1.6 million per undrilled well for a total contingent obligation of +$25.6 million, which was reflected as a deferred gain on sale of leaseholds on +the balance sheet as of December 31, 2006. In May 2007, we entered +into a letter agreement amending the original purchase and sale +agreement. The letter agreement relieved us of the obligation, in its +entirety, to either drill 16 wells or pay liquidated damages, resulting in the +recognition of the remaining $25.6 million deferred gain on sale of leaseholds +in the second quarter of 2007. Pursuant to the letter agreement, we +were obligated to drill six wells on specifically identified +acreage. As of December 31, 2007, we had drilled all six wells, which +were drilled on the unaffiliated party's leasehold for its benefit and at its +cost. +In +conjunction with the purchase and sale agreement described above, we entered +into a LKE agreement, in accordance with Section 1031 of the Internal Revenue +Code, with a “qualified intermediary.” Proceeds in the amount of $300 +million were transferred directly to the qualified intermediary to be held in +trust pursuant to the terms of the LKE agreement. We had until +mid-January 2007 to close any acquisition of suitable like-kind property, +allowing us to take advantage of the income tax deferral benefits of a LKE +transaction. See below a discussion of the acquisition of suitable +like-kind properties. +In +December 2007, we sold to the same unaffiliated party a portion of our North +Dakota properties for approximately $34.7 million. The properties, +located in Dunn, Williams and McKenzie Counties, North Dakota, include interests +in five producing Bakken wells and leasehold interests in approximately 72,000 +net undeveloped acres. The reduction in our production and proved +reserves as a result of this transaction is not material. We recorded +a gain on sale of leaseholds of $7.7 million in the fourth quarter of +2007. The proceeds from the sale were used to pay down +debt. Following the sale, as it relates to our North Dakota +properties, we retain ownership in three producing wells in Dunn County, ten +producing wells in Burke County and approximately 60,000 acres of undeveloped +leasehold in Burke County. +Acquisition +of Oil and Gas Properties +Acquisition +of Section 1031 – LKE Properties +In +January 2007, we completed our acquisitions of suitable like-kind properties in +accordance with the LKE agreement we entered into in connection with our sale of +undeveloped leaseholds located in Grand Valley Field, Garfield Country, +Colorado, in July 2006. We paid cash consideration for the acquired +oil and gas properties totaling $188.9 million, as described below. +52 +Table of Contents +EXCO +Resources Inc . On +January 5, 2007, we completed our purchase of EXCO Resources Inc.’s producing +properties and remaining undeveloped drilling locations and acreage in the +Wattenberg Field of the DJ Basin, Colorado. The cash consideration +paid for the EXCO properties was $130.2 million. The acquisition +included substantially all of EXCO’s assets in the area and encompassed 144 oil +and gas wells (approximating 25.5 Bcfe, net of royalty interests, proved +developed reserves as of December 31, 2005) and 8,160 acres of leasehold +interests. The wells and leases acquired are located in Weld, Adams, +Larimer, and Broomfield Counties, Colorado. We operate the assets and +hold a majority working interest in the properties. +Company-Sponsored +Partnerships . On +January 10, 2007, we completed the purchase of a majority interest in 44 of our +sponsored partnerships for $56.6 million. This transaction was not +effected pursuant to purchase requests by investor partners (see Note 8 , Commitments and +Contingencies , to our accompanying consolidated financial +statements). The wells are located in the Appalachian Basin, +Michigan, and Colorado. The transaction resulted in an increase of +423 net wells that we currently operate. +Other. We +acquired from unaffiliated parties undeveloped leaseholds in Erath County, Texas +for $2.1 million. +Other +Acquisitions +On +February 22, 2007, we acquired from an unaffiliated party 28 producing wells and +associated undeveloped acreage located in Colorado (Wattenberg Field) for a +purchase price of $12 million. The acquisition encompassed daily +production of approximately 668 Mcfe (520 Mcf of gas and 25 barrels of oil per +day), net to the interests acquired, 100 or more undeveloped drilling locations, +19.1 Bcfe of proved reserves, and an additional 7.5 Bcfe of probable +reserves. +On +October 30, 2007, with an effective date of October 1, 2007, we purchased from +unrelated parties a majority working interest in 762 natural gas wells located +in southwestern Pennsylvania for approximately $54 million. We +estimated that the acquisition included approximately 47 Bcfe of reserves, or 31 +Bcfe of proved reserves and 16 Bcfe of unproved reserves. The +purchase also included associated pipelines, equipment, real estate and +undeveloped acreage. +Critical +Accounting Policies and Estimates +We +have identified the following policies as critical to business operations and +the understanding of our results of operations. This is not a +comprehensive list of all of the accounting policies. In many cases, +the accounting treatment of a particular transaction is specifically dictated by +accounting principles generally accepted in the United States, with no need for +our judgment in the application. There are also areas in which our +judgment in selecting any available alternative would not produce a materially +different result. However, certain of our accounting policies are +particularly important to the portrayal of our financial position and results of +operations and we may use significant judgment in the application; as a result, +they are subject to an inherent degree of uncertainty. In applying +those policies, we use our judgment to determine the appropriate assumptions to +be used in the determination of certain estimates. Those estimates +are based on historical experience, observation of trends in the industry, and +information available from other outside sources, as appropriate. For +a more detailed discussion on the application of these and other accounting +policies, see Note +1 , Summary of +Significant Accounting Policies , to our accompanying consolidated +financial statements. Our critical accounting policies and estimates +are as follows: +Revenue +Recognition +Oil and natural gas +sales . Sales of oil are recognized when persuasive evidence of +a sales arrangement exists, the oil is verified as produced and is delivered to +a purchaser, collection of revenue from the sale is reasonably assured and the +sales price is determinable. We are currently able to sell all the +oil that we can produce under existing sales contracts with petroleum refiners +and marketers. We do not refine any of our oil +production. Our crude oil production is sold to purchasers at or near +our wells under short-term purchase contracts at prices and in accordance with +arrangements that are customary in the oil industry. +Sales of +natural gas are recognized when natural gas has been delivered to a custody +transfer point, persuasive evidence of a sales arrangement exists, the rights +and responsibility of ownership pass to the purchaser upon delivery, collection +of revenue from the sale is reasonably assured and the sales price is fixed or +determinable. Natural gas is sold by us under contracts with terms +ranging from one month to three years. Virtually all of our contract +pricing provisions are tied to a market index, with certain adjustments based +on, among other factors, whether a well delivers to a gathering or transmission +line, quality of natural gas and prevailing supply and demand conditions, so +that the price of the natural gas fluctuates to remain competitive with other +available natural gas supplies. As a result, our revenues from the +sale of natural gas will suffer if market prices decline and benefit if they +increase. We believe that the pricing provisions of our natural gas +contracts are customary in the industry. +53 +Table of Contents +We +currently use the “net-back” method of accounting for transportation +arrangements of natural gas sales. We sell gas at the wellhead and +collect a price and recognize revenues based on the wellhead sales price since +transportation costs downstream of the wellhead are incurred by our customers +and reflected in the wellhead price. +Natural gas marketing +activities . Natural gas marketing is reported on the gross +accounting method, based on the nature of the agreements between RNG, our +suppliers and our customers. RNG, our marketing subsidiary, purchases +gas from many small producers and bundles the gas together to sell in larger +amounts to purchasers of natural gas for a price advantage. RNG has +latitude in establishing price and discretion in supplier and purchaser +selection. Natural gas marketing revenues and expenses reflect the +full cost and revenue of those transactions because RNG takes title to the gas +it purchases from the various producers and bears the risks and rewards of that +ownership. Both the realized and unrealized gains and losses of the +RNG commodity based derivative transactions for natural gas marketing activities +are included in gas sales from marketing activities or cost of gas marketing +activities, as applicable. +Oil and gas well drilling +operations . Our drilling segment recognizes revenue from +drilling contracts with sponsored drilling programs using the percentage of +completion method based upon the percentage of contract costs incurred to date +to the estimated total contract costs for each contract. We utilize +this method since reasonably dependable estimates of the total estimated costs +can be made and recognized revenues are subject to revisions as a contract +progresses, the term of which can range from three to twelve +months. In addition, we offer our drilling services under two types +of contractual arrangements, cost-plus or footage-based service contracts, which +result in differing risk and reward relationships and, consequently, different +revenue reporting policies pursuant to Emerging Issues Task Force, or EITF, +Issue No. 99-19, Reporting +Revenue Gross as a Principal versus Net as an Agent . +The first +cost-plus drilling service arrangement was entered into in late 2005 with +drilling activity commencing in the first quarter of 2006. Due to the +fixed-fee-percentage nature of our revenues from these services, we have +determined that, in substance, we are acting as an agent, without risk of loss +during the performance of the drilling activities. Accordingly, our +services provided under the cost-plus drilling agreements are reported on a net +basis. We entered into our second and third cost-plus drilling +arrangements in September 2006 and August 2007 and commenced drilling +immediately. +Footage-based +contracts provide for the drilling, completion and equipping of wells at footage +rates and are generally completed within nine to twelve months after the +commencement of drilling. We provide geological, engineering, and +drilling supervision on the drilling and completion process and use +subcontractors to perform drilling and completion services at a fixed +footage-based rate and accordingly have the risk of loss in performing services +under these arrangements. Accordingly, we report revenue under these +agreements gross of related expenses. Anticipated losses, if any, on +uncompleted contracts are recorded at the time that the estimated total costs +exceed the estimated total contract revenue. At December 31, 2007 and +2006, the loss contract reserve was $0.2 million and $0.3 million, +respectively. +Well operations and pipeline +income . Well operations and pipeline income are recognized +when persuasive evidence of an arrangement exists, services have been rendered, +collection of revenues is reasonably assured and the sales price is fixed or +determinable. We are paid a monthly operating fee for each well we +operate for outside owners including the limited partnerships we +sponsor. The fee covers monthly operating and accounting costs, +insurance and other recurring costs. We may also receive additional +compensation for special non-recurring activities, such as reworks and +recompletions. +Accounting +for Derivatives Contracts at Fair Value +We use +derivative instruments to manage our commodity and financial market +risks. We currently do not use hedge accounting treatment for our +derivatives. +Derivatives +are reported on our accompanying consolidated balance sheets at fair value on a +gross asset and liability basis. Changes in fair value of derivatives +are recorded in oil and gas price risk management, net, in our accompanying +consolidated statements of income. The measurement of fair value is +based on actively quoted market prices, if available. Otherwise, +validation of a contract's fair value is performed internally and, while we use +common industry practices to develop our valuation techniques, changes in our +pricing methodologies or the underlying assumptions could result in +significantly different fair values. If pricing information from +external sources is not available, measurement involves our judgment and +estimates. These estimates are based on valuation methodologies we +consider appropriate. For individual contracts, the use of different +assumptions could have a material effect on the contract's estimated fair +value. +Oil +and Gas Properties +We +account for our oil and gas properties under the successful efforts method of +accounting. Costs of proved developed producing properties, +successful exploratory wells and development dry hole costs are capitalized and +depreciated or depleted by the unit-of-production method based on estimated +proved developed producing oil and natural gas reserves. Property +acquisition costs are depreciated or depleted on the unit-of-production method +based on estimated proved oil and gas reserves. +54 +Table of Contents +Our +estimates of proved reserves are based on quantities of oil and natural gas that +engineering and geological analysis demonstrates, with reasonable certainty, to +be recoverable from established reservoirs in the future under current operating +and economic conditions. Annually, we engage independent petroleum +engineers to prepare a reserve and economic evaluation of all our properties on +a well-by-well basis as of December 31. Additionally, we adjust our +oil and gas reserves for major acquisitions, new drilling and divestitures +during the year as needed. The process of estimating and evaluating +oil and natural gas reserves is complex, requiring significant decisions in the +evaluation of available geological, geophysical, engineering and economic +data. The data for a given property may also change substantially +over time as a result of numerous factors, including additional development +activity, evolving production history and a continual reassessment of the +viability of production under changing economic conditions. As a +result, revisions in existing reserve estimates occur from time to +time. Although every reasonable effort is made to ensure that reserve +estimates reported represent our most accurate assessments possible, the +subjective decisions and variances in available data for various properties +increase the likelihood of significant changes in these +estimates. Because estimates of reserves significantly affect our +DD&A expense, a change in our estimated reserves could have an effect on our +net income. +Exploration +costs, including geological and geophysical expenses and delay rentals, are +charged to expense as incurred. Exploratory well drilling costs, +including the cost of stratigraphic test wells, are initially capitalized but +charged to expense if the well is determined to be nonproductive. The +status of each in-progress well is reviewed quarterly to determine the proper +accounting treatment under the successful efforts method of +accounting. Exploratory well costs continue to be capitalized as long +as the well has found a sufficient quantity of reserves to justify our +completion as a producing well and we are making sufficient progress assessing +our reserves and economic and operating viability. If an in-progress +exploratory well is found to be unsuccessful (referred to as a dry hole) prior +to the issuance of the financial statements, the costs are expensed to +exploration costs. If we are unable to make a final determination +about the productive status of a well prior to issuance of the financial +statements, the well is classified as “suspended well costs” until we have had +sufficient time to conduct additional completion or testing operations to +evaluate the pertinent geological and engineering data obtained. At +the time when we are able to make a final determination of a well’s productive +status, the well is removed from the suspended well status and the proper +accounting treatment is recorded. At December 31, 2007, suspended +well costs included in oil and gas properties on our accompanying consolidated +financial statements was $2.3 million. +The +acquisition costs of unproved properties are capitalized when incurred, until +such properties are transferred to proved properties or charged to expense when +expired, impaired or amortized. Unproved oil and gas properties with +individually significant acquisition costs are periodically assessed, and any +impairment in value is charged to exploration expense. The amount of +impairment recognized on unproved properties which are not individually +significant is determined by amortizing the costs of such properties within +appropriate fields based on our historical experience, acquisition dates and +average lease terms. The valuation of unproved properties is +subjective and requires us to make estimates and assumptions which, with the +passage of time, may prove to be materially different from actual realizable +values. +In +accordance with SFAS No. 144, Accounting for the Impairment or +Disposal of Long-Lived Assets , we assess our oil and gas properties for +possible impairment by comparing net capitalized costs to estimated undiscounted +future net cash flows on a field-by-field basis using estimated production based +upon prices at which we reasonably estimate the commodity to be +sold. The estimates of future prices may differ from current market +prices of oil and natural gas. Any downward revisions in estimates to +our reserve quantities, expectations of falling commodity prices or rising +operating costs could result in a reduction in undiscounted future net cash +flows and an impairment of our oil and gas properties. Although our +cash flow estimates are based on the relevant information available at the time +the estimates are made, estimates of future cash flows are, by nature, highly +uncertain and may very significantly from actual results. +Deferred +Income Tax Asset Valuation Allowance +Deferred +income tax assets are recognized for deductible temporary differences, net +operating loss carry-forwards, and credit carry-forwards if it is more likely +than not that the tax benefits will be realized. To the extent a +deferred tax asset is not expected to be realized under the preceding criteria, +a valuation allowance is established. The factors which we consider +in assessing whether we will realize the value of deferred income tax assets +involve judgments and estimates of both amount and timing, which could differ +from actual results, achieved in future periods. +The +judgments used in applying the above policies are based on our evaluation of the +relevant facts and circumstances as of the date of the financial +statements. Actual results may differ from those +estimates. +Accounting +for Acquisitions Using Purchase Accounting +We +account for acquisitions utilizing the purchase method as prescribed by SFAS No. +141, Business +Combinations . Pursuant to purchase method accounting, the +acquiring company must allocate the cost of the acquisition to assets acquired +and liabilities assumed based on fair values as of the acquisition +date. The purchase price allocations are based on appraisals, +discounted cash flows, quoted market prices and estimates by +management. In addition, when appropriate, we review comparable +purchases and sales of oil and gas properties within the same regions, and use +that data as a basis for fair market value; for example, the amount a willing +buyer and seller would enter into an exchange for such +properties. Any excess of purchase price over amounts assigned to +assets and liabilities is recorded as goodwill. The amount of +goodwill recorded in any particular business combination can vary significantly +depending upon the value attributed to assets acquired and liabilities +assumed. In each of our acquisitions it was finally determined that +the purchase price did not exceed the fair value of the net assets +acquired. Therefore, no goodwill was ultimately +recorded. +55 +Table of Contents +In +estimating the fair values of assets acquired and liabilities assumed we made +various assumptions. The most significant assumptions relate to the +estimated fair values assigned to proved developed producing, proved developed +non-producing, proved undeveloped and unproved oil and gas +properties. To estimate the fair values of these properties, we +prepared estimates of oil and gas reserves. We estimated future +prices to apply to the estimated reserve quantities acquired, and estimated +future operating and development costs, to arrive at estimates of future net +revenues. For estimated proved reserves, the future net revenues were +discounted using a market-based weighted average cost of capital rate determined +appropriate at the time of the acquisition. The market-based weighted +average cost of capital rate was subjected to additional project-specific +risking factors. To compensate for the inherent risk of estimating +and valuing unproved properties, the discounted future net revenues of probable +and possible reserves were reduced by additional risk-weighting +factors. +Deferred +taxes must be recorded for any differences between the assigned values and tax +basis of assets and liabilities. Estimated deferred taxes are based +on available information concerning the tax basis of assets acquired and +liabilities assumed and loss carryforwards at the acquisition date, although +such estimates may change in the future as additional information becomes +known. +Recent +Accounting Standards +See Note 1 , Summary of Significant Accounting +Policies - Recent Accounting Standards , to our accompanying consolidated +financial statements. +ITEM 7A . QUANTITATIVE AND QUALITATIVE DISCLOSURE +ABOUT MARKET RISK. +Market-Sensitive +Instruments and Risk Management +We are +exposed to market risks associated with interest rates, commodity prices and +credit exposure. Management has established risk management processes +to monitor and manage these market risks. +See Item +7, Management’s Discussion and Analysis of Financial Condition and Results of +Operation, Critical +Accounting Policies and Estimates-Accounting for Derivatives Contracts at Fair +Value , for +further discussion of the accounting for derivative contracts. +Interest +Rate Risk +We are +exposed to risk resulting from changes in interest rates primarily as it relates +to interest we earn on our cash, cash equivalents and designated cash and +interest we pay on borrowings under our revolving credit +facility. Interest-bearing cash and cash equivalents includes money +market funds, short-term certificates of deposit and checking and savings +accounts with various banks. The amount of interest-bearing cash and +cash equivalents as of December 31, 2007, is $108.5 million with an average +interest rate of 3.69%. +Based on +a sensitivity analysis of the credit facility borrowings as of +December 31, 2007, it was estimated that if market interest rates average 1% +higher (lower) in 2008 than in 2007, interest expense, net of tax, would +increase (decrease) by approximately $1.5 million. On February 8, +2008, we completed the issuance and sale of $203 million aggregate principal +amount of 12% senior notes due 2018. This fixed-price debt +transaction will lower our sensitivity to interest rate +fluctuations. +Commodity Price +Risk +We are +exposed to the effect of market fluctuations in the prices of oil and natural +gas as they relate to our oil and natural gas sales and marketing +activities. Price risk represents the potential risk of loss from +adverse changes in the market price of oil and natural gas +commodities. We employ established policies and procedures to manage +the risks associated with these market fluctuations using commodity +derivatives. Our policy prohibits the use of oil and natural gas +derivative instruments for speculative purposes. +Validation +of a contract’s fair value is performed internally and while we use common +industry practices to develop our valuation techniques, changes in our pricing +methodologies or the underlying assumptions could result in significantly +different fair values. +56 +Table of Contents +Economic Hedging +Strategies. Our results of operations and operating cash flows +are affected by changes in market prices for oil and natural gas. To +mitigate a portion of the exposure to adverse market changes, we have entered +into various derivative instruments. As of December 31, 2007, our oil +and natural gas derivative instruments were comprised of futures, swaps and +collars. These instruments generally consist of NYMEX-traded natural +gas futures contracts and option contracts for Appalachian and Michigan +production, Panhandle-based contracts for NECO production and CIG-based +contracts for other Colorado production and NYMEX-based swaps for our Colorado +and North Dakota oil production. +· +For +swap instruments, we receive a fixed price for the hedged commodity and +pay a floating market price to the counterparty. The +fixed-price payment and the floating-price payment are netted, resulting +in a net amount due to or from the +counterparty. +· +Collars +contain a fixed floor price (put) and ceiling price (call). If +the market price exceeds the call strike price or falls below the fixed +put strike price, we receive the fixed price and pay the market +price. If the market price is between the call and the put +strike price, no payments are due from either +party. +We +purchase puts and set collars for our own and affiliate partnerships’ production +to protect against price declines in future periods while retaining much of the +benefits of price increases. RNG enters into fixed-price physical +purchase and sale agreements that are derivative contracts. In order +to offset these fixed-price physical derivatives, we enter into financial +derivative instruments that have the effect of locking in the prices we will +receive or pay for the same volumes and period, offsetting the physical +derivative. While these derivatives are structured to reduce our +exposure to changes in price associated with the derivative commodity, they also +limit the benefit we might otherwise have received from price changes in the +physical market. We believe our derivative instruments continue to be +highly effective in achieving the risk management objectives for which they were +intended. +The +following table presents monthly average CIG and NYMEX closing prices for +natural gas and oil in 2007 and 2006, as well as average sales prices we +realized for the respective commodity. +Year +Ended December 31, +2007 +2006 +Average +Index Closing Price +Natural +Gas (per MMbtu) +CIG +$ +3.97 +$ +5.63 +NYMEX +6.89 +7.23 +Oil +(per Barrel) +NYMEX +69.79 +64.73 +Average +Sales Price +Natural +Gas +5.33 +5.91 +Oil +60.65 +59.33 +Based on +a sensitivity analysis as of December 31, 2007, it was estimated that a 10% +increase in oil and natural gas prices over the entire period for which we have +derivatives currently in place would have resulted in an increase in unrealized +losses of $7.3 million and a 10% decrease in oil and natural gas prices would +have resulted in a decrease in unrealized losses of $7.3 million. +See Note 1 , Summary of Significant Accounting +Policies , and Note 15 , Derivative Financial +Instruments , to our consolidated financial statements included in this +report for additional disclosure regarding derivative instruments including, but +not limited to, a summary of the open derivative option and purchase and sales +contracts for us and RNG as of December 31, 2007. +Credit Risk +Credit +risk represents the loss that we would incur if a counterparty fails to perform +under its contractual obligations. To reduce credit exposure, we seek +to enter into netting agreements with counterparties that permit us to offset +receivables and payables with such counterparties. We attempt to +further reduce credit risk by diversifying our counterparty exposure and +entering into transactions with high-quality counterparties. Where +exposed to credit risk, we analyze the counterparties’ financial condition prior +to entering into an agreement, establish credit limits and monitor the +appropriateness of those limits on an ongoing basis. There were no +counterparty defaults during the years ended December 31, 2007, 2006 and +2005. +57 +Table of Contents +Disclosure +of Limitations +Because +the information above included only those exposures that exist at December 31, +2007, it does not consider those exposures or positions which could arise after +that date. As a result, our ultimate realized gain or loss with +respect to interest rate and commodity price fluctuations will depend on the +exposures that arise during the period, our hedging strategies at the time, and +interest rates and commodity prices at the time. +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY +DATA +The +response to this Item is set forth herein in a separate section of this Report, +beginning on Page F-1. +Index to financial +statements. +ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS +ON ACCOUNTING AND FINANCIAL DISCLOSURE. +Previous +Independent Registered Public Accounting Firm +As +previously reported on Form 8-K filed with the SEC on May 31, 2007, the Audit +Committee of our Board of Directors recommended, and the Board of Directors +ratified, the dismissal of KPMG LLP, or KPMG, as our principal accountants on +May 24, 2007. +The audit +reports of KPMG on our consolidated financial statements as of and for the years +ended December 31, 2006 and 2005, contained no adverse opinion or disclaimer of +opinion, nor were such reports qualified or modified as to uncertainty, audit +scope or accounting principles, except as follows: +The audit +report of KPMG on our consolidated financial statements as of December 31, 2006, +and for the year then ended, dated May 22, 2007, indicated that, as described in +Note 1, Summary of Significant +Accounting Policies , to such consolidated financial statements, we +adopted the provisions of Statement of Financial Accounting Standards No. +123(R), Share-Based Payment, +and we changed our method of quantifying errors based on SEC Staff +Accounting Bulletin No. 108, Considering the Effects of Prior +Year Misstatements when Quantifying Misstatements in Current Year Financial +Statements , in 2006. +The audit +reports of KPMG on management's assessment of the effectiveness of internal +control over financial reporting and the effectiveness of internal control over +financial reporting as of December 31, 2006 and 2005, did not contain any +adverse opinion or disclaimer of opinion, nor were they qualified or modified as +to uncertainty, audit scope, or accounting principles, except that: +(1) +KPMG's report as of December 31, +2006, includes an explanatory paragraph stating that “The Company acquired +Unioil on December 6, 2006, and management excluded from its assessment of +the effectiveness of the Company's internal control over financial +reporting as of December 31, 2006, Unioil’s internal control over +financial reporting associated with total assets of $26.1 million and +total revenues of $0.3 million included in the consolidated financial +statements of the Company as of and for the year ended December 31, +2006. Our audit of internal control over financial reporting of +the Company also excluded an evaluation of the internal control over +financial reporting of +Unioil.” +(2) +KPMG’s reports indicate that we +did not maintain effective internal control over financial reporting as of +December 31, 2006 and 2005, because of the effect of material weaknesses +on the achievement of the objectives of the control criteria as described +below: +Material Weaknesses as of +December 31, 2006 +· +The +Company did not have effective policies and procedures to ensure the +timely reconciliation, review and adjustment of significant balance sheet +and income statement accounts. As a result, material +misstatements were identified during the Company's closing process in +certain significant balance sheet and income statement accounts of the +Company’s 2006 consolidated financial statements. This +deficiency resulted in a more than remote likelihood that a material +misstatement of the Company’s annual or interim financial statements would +not be prevented or detected. +58 +Table of Contents +· +The +Company did not have effective policies and procedures, or personnel with +sufficient technical expertise to ensure proper accounting for derivative +instruments. Specifically, the Company’s internal control +processes did not ensure the completeness of all derivative contracts +related to oil and gas sales, and also did not ensure the determination of +the fair value of certain derivatives. As a result, +misstatements were identified in the fair value of derivatives and related +income statement accounts of the Company’s 2006 consolidated financial +statements. This deficiency resulted in a more than remote +likelihood that a material misstatement of the Company’s annual or interim +financial statements would not be prevented or +detected. +· +The +Company did not have effective policies and procedures to ensure proper +accounting for oil and gas properties. Specifically, the +Company’s review procedures were not sufficient to ensure that the +calculations of depreciation and depletion were performed accurately and +that the capitalization of costs was performed in accordance with the +applicable authoritative accounting guidance. As a result, +misstatements were identified in 2006 in depreciation, depletion and +amortization expense of the Company’s consolidated financial +statements. This deficiency resulted in a more than remote +likelihood that a material misstatement of the Company’s annual or interim +financial statements would not be prevented or +detected. +Material Weaknesses as of +December 31, 2005 +We did +not have effective policies and procedures, and were not adequately staffed with +accounting personnel possessing an appropriate level of technical expertise in +U.S. generally accepted accounting principles, as further described +below: +· +The +Company did not have effective policies and procedures, or personnel with +sufficient technical expertise, to properly account for derivative +transactions in accordance with generally accepted accounting principles. +Specifically, the Company's policies and procedures relating to +derivatives transactions were not designed effectively to ensure that each +of the requirements for hedge accounting was evaluated appropriately with +respect to the Company's commodity based +derivatives. Additionally, the Company's policies and +procedures relating to the derivative transactions entered into on behalf +of affiliated partnerships were not adequate to ensure these transactions +were recorded properly in the financial statements. As a +result, a misstatement was identified in the fair value of derivatives and +the oil and gas price risk management loss accounts that was corrected +prior to the issuance of the Company's 2005 consolidated financial +statements. This deficiency results in more than a remote +likelihood that a material misstatement of the Company's annual or interim +consolidated financial statements would not be prevented or +detected. +· +The +Company did not have effective policies and procedures, or personnel with +sufficient technical expertise, to ensure compliance with appropriate +accounting principles for its oil and gas +properties. Specifically, the Company's policies and procedures +were not designed effectively to ensure that the calculation of +depreciation and depletion and the determintion of impairments were +performed in accordance with the applicable authoritative accounting +guidance. As a result, misstatements were identified in the +accumulated depreciation, depletion and amortization and the depreciation, +depletion and amortization expense accounts that was corrected prior to +the issuance of the Company's 2005 consolidated financial +statements. This deficiency results in more than a remote +likelihood that a material misstatement of the Company's annual or interim +consolidated financial statements would not be prevented or +detected. +· +The +Company did not have effective policies and procedures, or personnel with +sufficient technical expertise, to ensure proper accounting and disclosure +for income taxes. Specifically, the Company's policies and +procedures did not provide for appropriate control documentation or +supervisory review of permanent and temporary differences, or assessment +of tax reserves to ensure that they were properly reflected and disclosed +in the Company's financial statements. As a result, +misstatements were identified in the deferred income tax liability and +income tax expense accounts in the Company's preliminary 2005 consolidated +financial statements. This deficiency results in more than a +remote likelihood that a material misstatement of the Company's annual or +interim consolidated financial statements would not be prevented or +detected. +59 +Table of Contents +· +The +Company did not have effective policies and procedures, or personnel with +sufficient technical expertise, to ensure that its accounting for asset +retirement obligations complied with generally accepted accounting +principles. Specifically, the Company's policies and procedures regarding +the estimate of the fair value of the asset retirement obligations were +not designed effectively to ensure that it was estimated in accordance +with FAS No. 143, Asset +Retirement Obligations . This deficiency results in more +than a remote likelihood that a material misstatement of the Company's +annual or interim consolidated financial statements would not be prevented +or detected. +· +The +Company did not have effective policies and procedures, or personnel with +sufficient technical expertise, to provide for adequate monitoring and +assessment of the application of accounting principles, standards or rules +as it relates to proportionate consolidation in a timely +manner. As a result of this control deficiency, the Company did +not appropriately eliminate its proportionate share of transactions with +the Company sponsored limited partnerships, which resulted in the +restatement of the Company's financial statements for the first three +quarters of 2005, the years ended December 31, 2004, 2003, 2002, and 2001 +and each of the quarters in 2004 and +2003. +During +the two years ended December 31, 2006, and the subsequent interim period through +May 24, 2007, there were no: 1) disagreements with KPMG on any matter of +accounting principles or practices, financial statement disclosure, or auditing +scope or procedure that, if not resolved to KPMG’s satisfaction, would have +caused KPMG to make reference to the subject matter of the disagreement in +connection with its audit reports on our financial statements for such years, or +2) reportable events, except for the material weaknesses described +above. +KPMG has +been authorized to respond fully to the inquiries of the successor independent +registered public accounting firm concerning the subject matter of the +foregoing. +We +provided KPMG with a copy of the foregoing statements and requested that KPMG +furnish us with a letter addressed to the Securities and Exchange Commission +stating whether KPMG agreed with the foregoing statements, and, if not, stating +the respects in which KPMG did not agree. The letter from KPMG is +attached as Exhibit 16 to our Form 8-K filed with the SEC on May 31, +2007. +New +Independent Registered Public Accounting Firm +As +previously reported on Form 8-K filed with the SEC on May 31, 2007, the Audit +Committee of our Board of Directors recommended and the Board of Directors +ratified the engagement of PricewaterhouseCoopers LLP, or PwC, as our +independent registered public accounting firm the fiscal year ending December +31, 2007. +During +our two most recent fiscal years ended December 31, 2006 and 2005, and through +May 24, 2007, we did not consult with PwC regarding either (i) the application +of accounting principles to a specified transaction, either completed or +proposed, or the type of audit opinion that might be rendered on our financial +statements, and neither a written report was provided to us nor oral advice was +provided that PwC concluded was an important factor considered by us in reaching +a decision as to any of the accounting, auditing or financial reporting issues; +or (ii) any matter that was either the subject of a disagreement, as that term +is defined in paragraph 304(a)(1)(iv) of Regulation S-K, or a reportable event +required to be reported under paragraph 304(a)(1)(v) of Regulation +S-K. +ITEM 9A . CONTROLS AND PROCEDURES +Evaluation +of Disclosure Controls and Procedures +As of +December 31, 2007, we carried out an evaluation, under the supervision and with +the participation of our management, including our Chief Executive Officer and +Chief Financial Officer, of the effectiveness of the design and operation of our +disclosure controls and procedures pursuant to Securities Exchange Act Rule +13a-15(e). Based upon that evaluation, our Chief Executive Officer +and Chief Financial Officer concluded that our disclosure controls and +procedures were not effective as of December 31, 2007, to ensure that the +information required to be disclosed by the Company in the reports that we file +or submit under the Exchange Act is recorded, processed, summarized and +reported, within the time periods specified in the SEC rules and forms, and that +the information is accumulated and communicated to our management, including our +Chief Executive Officer and Chief Financial Officer, as appropriate to all +timely decisions regarding required disclosure, due to the existence of material +weaknesses described in Management’s Report on Internal +Control Over Financial Reporting included in Item 8 of this +report. +60 +Table of Contents +Changes +in Internal Control over Financial Reporting +We have +made the following changes in our internal control over financial reporting (as +such term is defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange +Act of 1934) during the quarter ended December 31, 2007, that have materially +affected or are reasonably likely to materially affect our internal control over +financial reporting. +· +Installed +new software supporting our derivative valuation process. The +new system enhanced the existing internal controls framework over +reporting more accurate information by automating a previously manual +control. +During +the third quarter of 2007, and continuing through the filing of this report, we +made the following changes in our internal control over financial reporting that +has materially affected, or is reasonably likely to materially affect our +internal controls over financial reporting: +· +Installed +new software supporting our accounts payable process as part of a broader +financial reporting system implementation. The new system +enhanced the existing internal control framework over accounts payable and +cash distribution process by automating several of the previously manual +controls. +Additionally, +during the first quarter of 2007, and continuing through the filing of this +report, we implemented the following changes in internal control over financial +reporting: +· +Reinforced +reconciliation procedures to ensure the timely reconciliation, review and +adjustments to significant balance sheet and income statement +accounts; +· +Developed +and approved extensive policies and procedures concerning the controls +over financial reporting for +derivatives; +· +Provided +additional training regarding derivatives for key personnel; +and +· +Developed +a review process to ensure proper accounting for oil and gas properties, +specifically the capitalization of costs and calculation of depreciation +and depletion. +We +continue to evaluate the ongoing effectiveness and sustainability of the changes +we have made in internal control, and, as a result of the ongoing evaluation, +may identify additional changes to improve internal control over financial +reporting. +ITEM 9B. OTHER INFORMATION +None. +PART +III +ITEM +10. DIRECTORS , EXECUTIVE OFFICERS AND CORPORATE +GOVERNANCE +The +information called for by Item 10 is incorporated by reference from information +under the captions entitled Corporate Governance , Section 16(a) Beneficial Ownership +Reporting Compliance , Election of Directors and +Executive Compensation +and other relevant portions of our definitive proxy statement to be filed +pursuant to Regulation 14A no later than 120 days after the close of our fiscal +year. +ITEM 11. EXECUTIVE COMPENSATION +The information called for by Item 11 +is incorporated by reference from information under the caption entitled Executive Compensation and +other relevant portions of our definitive proxy statement to be filed pursuant +to Regulation 14A no later than 120 days after the close of our fiscal +year. +ITEM 12 . SECURITY OWNERSHIP OF CERTAIN BENEFICIAL +OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +The +information called for by Item 12 is incorporated by reference from information +under the caption entitled Security Ownership of Certain +Beneficial Owners and Management and Related Stockholder Matters and +other relevant portions of our definitive proxy statement to be filed pursuant +to Regulation 14A no later than 120 days after the close of our fiscal +year. +61 +Table of Contents +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED +TRANSACTIONS AND DIRECTOR INDEPENDENCE +The +information called for by Item 13 is incorporated by reference from information +under the captions entitled Certain Relationships and Related +Transactions and +Director Independence in our definitive proxy statement to be +filed pursuant to Regulation 14A no later than 120 days after the close of our +fiscal year. +ITEM 14. PRINCIPAL ACCOUNTANT FEES AND +SERVICES +The +information called for by Item 14 is incorporated by reference from information +under caption entitled Principal Accountant Fees and +Services and other relevant portions of our definitive proxy +statement to be filed pursuant to Regulation 14A no later than 120 days after +the close of our fiscal year. +62 +Table of Contents +PART +IV +ITEM 15. EXHIBITS , FINANCIAL STATEMENT +SCHEDULES +(a) +(1) +Financial +Statements: +See +Index to +Financial Statements and Schedules on page +F-1. +(2) +Financial +Statement Schedules: +See +Index to +Financial Statements and Schedules on page +F-1. +Schedules +and Financial Statements Omitted +All other +financial statement schedules are omitted because they are not required, +inapplicable, or the information +is included in the Financial Statements or Notes thereto. +(3) +Exhibits: +See Exhibits Index on +page 67. +63 +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. +PETROLEUM +DEVELOPMENT CORPORATION +By +/s/ +Steven R. Williams +Steven +R. Williams, +Chairman +and Chief Executive Officer +March +20, 2008 +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/ Steven R. +Williams +Chairman, +Chief Executive Officer and Director +Steven +R. Williams +(principal +executive officer) +March +20, 2008 +/s/ Richard W. +McCullough +President, +Chief Financial Officer and Director +March +20, 2008 +Richard +W. McCullough +(principal +financial officer) +/s/ Darwin L. +Stump +Chief +Accounting Officer +March +20, 2008 +Darwin +L. Stump +(principal +accounting officer) +/s/ Daniel W. +Amidon +Daniel +W. Amidon +General +Counsel, Corporate Secretary +March +20, 2008 +/s/ Jeffrey C. +Swoveland +Jeffrey +C. Swoveland +Director +March +20, 2008 +/s/ Vincent F. +D'Annunzio +Vincent +F. D'Annunzio +Director +March +20, 2008 +/s/ Kimberly Luff +Wakim +Kimberly +Luff Wakim +Director +March +20, 2008 +/s/ David C. +Parke +David +C. Parke +Director +March +20, 2008 +/s/ Anthony +J. Crisafio +Anthony +J. Crisafio +Director +March +20, 2008 +/s/ Joseph +E. Casabona +Joseph +E. Casabona +Director +March +20, 2008 +/s/ Larry +F. Mazza +Larry +F. Mazza +Director +March +20, 2008 +64 +Table of Contents +GLOSSARY OF OIL AND NATURAL GAS TERMS +The +following are abbreviations and definitions of terms commonly used in the oil +and gas industry and this Form 10-K. +Bbl +- One barrel or 42 U.S. gallons of liquid volume. +Bcf +- One billion cubic feet. +Bcfe +- One billion cubic feet of natural gas equivalents. +Completion +- The installation of permanent equipment for the production of oil or +gas. +DD&A - Refers to depreciation, +depletion and amortization of our property and equipment. +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 hydrocarbons in +sufficient quantities to justify completion as an oil or gas +well. +Exploratory +well - A well drilled to find and produce oil or natural gas reserves not +classified as proved, to find a new productive reservoir in a field previously +found to be productive of oil or natural gas in another reservoir or to extend a +known reservoir. +Extensions and discoveries - +As to any period, the increases to proved reserves from all sources other than +the acquisition of proved properties or revisions of previous +estimates. +Gross +acres or wells - Refers to the total acres or wells in which we have a +working interest. +Horizontal +drilling - A drilling technique that permits the operator to contact and +intersect a larger portion of the producing horizon than conventional vertical +drilling techniques and may, depending on the horizon, result in increased +production rates and greater ultimate recoveries of +hydrocarbons. +MBbls - One thousand +barrels. +Mcf - One thousand cubic +feet. +Mcfe - One thousand cubic feet +of natural gas equivalents, based on a ratio of 6 Mcf for each barrel of oil, +which reflects the relative energy content. +MMbtu - One million British +thermal units. One British thermal unit is the heat required to raise +the temperature of a one-pound mass of water from 58.5 to 59.5 degrees +Fahrenheit. +MMcf +- One million cubic feet. +MMcfe - One million cubic feet of +natural gas equivalents. +Natural +gas liquids - Liquid hydrocarbons that have been extracted from natural +gas, such as ethane, propane, butane and natural gasoline. +Net acres +or wells - Refers to gross acres or wells multiplied, in each case, by +the percentage working interest we own. +Net +production - Oil and gas production that we own, less royalties and +production due others. +NYMEX +- New York Mercantile Exchange, the exchange on which commodities, including +crude oil and natural gas futures contracts, are traded. +Oil +- Crude oil or condensate. +Operator +- The individual or company responsible for the exploration, development and +production of an oil or gas well or lease. +65 +Table of Contents +Present value of proved +reserves - The present value of estimated future revenues, discounted at +10% annually, to be generated from the production of proved reserves determined +in accordance with Securities and Exchange Commission guidelines, net of +estimated production and future development costs, using prices and costs as of +the date of estimation without future escalation, without giving effect to (i) +estimated future abandonment costs, net of the estimated salvage value of +related equipment, (ii) non-property related expenses such as general and +administrative expenses, debt service and future income tax expense, or (iii) +depreciation, depletion and amortization. +Proved developed non-producing +reserves - Reserves that consist of (i) proved reserves from wells which +have been completed and tested but are not producing due to lack of market or +minor completion problems which are expected to be corrected and (ii) proved +reserves currently behind the pipe in existing wells and which are expected to +be productive due to both the well log characteristics and analogous production +in the immediate vicinity of the wells. +Proved developed producing +reserves - +Proved reserves that can be expected to be recovered from currently +producing zones under the continuation of present operating +methods. +Proved +developed reserves - +The combination of proved developed producing and proved developed +non-producing reserves. +Proved +reserves - 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, i.e., prices and costs as of +the date the estimate is made. Prices include consideration of +changes in existing prices provided only by contractual arrangements, but not on +escalations based upon future conditions. +Proved +undeveloped reserves , or +PUD - Proved 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 +- A recompletion occurs when we reenter a well to complete (i.e., perforate) a +new formation different from that in which a well has previously been +completed. +Refrac, +or refracture – A refrac is when we stimulate the present producing zone +of a well to increase production, using hydraulic, acid, gravel, etc. fracture +techniques. +Reserve +replacement - Calculated by dividing the sum of reserve additions fro all +sources (revisions, extensions, discoveries and other additions and +acquisitions) by the actual production for the corresponding +period. The values used for reserve additions are derived directly +from the proved reserves table located in Note 20 , Supplemental Oil and Gas +information , to our consolidated financial statements included in this +report. We use the reserve replacement ratio as an indicator of our +ability to replenish annual production volumes and grow our reserves, thereby +providing some information on the sources of future production. It +should be noted that the reserve replacement ratio is a statistical indicator +that has limitations. As an annual measure, the ratio limited because +it typically varies widely based on the extent and timing of new discoveries and +property acquisitions. Its predictive and comparative value is also +limited for the same reasons. In addition, since the ratio does not +imbed the cost or timing of future production of new reserves, it cannot be used +as a measure of value creation. +Royalty +- An interest in an oil and gas lease that gives the owner of the interest the +right to receive a portion of the production from the leased acreage (or of the +proceeds of the sale thereof), but generally does not require the owner to pay +any portion of the costs of drilling or operating the wells on the leased +acreage. Royalties may be either landowner’s royalties, which are +reserved by the owner of the leased acreage at the time the lease is granted, or +overriding royalties, which are usually reserved by an owner of the leasehold in +connection with a transfer to a subsequent owner. +Standardized +measure of discounted future net cash flows - Present value of proved +reserves, as adjusted to give effect to (i) estimated future abandonment costs, +net of the estimated salvage value of related equipment, and (ii) estimated +future income taxes. +Undeveloped +acreage - Leased 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 proved +reserves. +Working +interest - An interest in an oil and gas lease that gives the owner of +the interest the right to drill for and produce oil and gas on the leased +acreage and requires the owner to pay a share of the costs of drilling and +production operations. The share of production to which a working +interest is entitled will be smaller than the share of costs that the working +interest owner is required to bear to the extent of any royalty +burden. +Workover +- Operations on a producing well to restore or increase +production. +66 +Table of Contents +Exhibits +Index +Exhibit +No. +Description +3.1 +Amended +and Restated Certificate of Incorporation of Petroleum Development +Corporation, filed herewith. +3.2 +Bylaws +of Petroleum Development Corporation, amended and restated effective +October 11, 2007, incorporated by reference to Exhibit 3.2 to Form 8-K +filed on October 17, 2007. +4.1 +Rights +Agreement by and between Petroleum Development Corporation and Transfer +Online, Inc., as Rights Agent, dated as of September 11, 2007, including +the forms of Rights Certificates and Summary of Stockholder Rights Plan +attached thereto as Exhibits A and B, incorporated by reference to Exhibit +4.1 to Form 8-K filed September 14, 2007. +4.2 +Indenture +dated as of February 8, 2008, by and among Petroleum Development +Corporation and The Bank of New York, incorporated by reference to Exhibit +4.1 to Form 8-K filed on February 12, 2008. +4.3 +First +Supplemental Indenture dated as of February 8, 2008, by and among +Petroleum Development Corporation and the Bank of New York, incorporated +by reference to Exhibit 4.2 to Form 8-K filed on February 12, +2008. +4.4 +Form +of 12% Senior Note due 2018, incorporated by reference to Exhibit 4.2 to +Form 8-K filed on February 12, 2008. +10.1 +Amended +and Restated Credit Agreement, dated as of November 4, 2005, Petroleum +Development Corporation, as borrower and JPMorgan Chase Bank, N.A and BNP +Paribas, as lenders, incorporated by reference to Exhibit 10.2 to Form 8-K +dated November 4, 2005. +10.2 +First +Amendment to Amended and Restated Credit Agreement, dated as of August 9, +2007, by an among Petroleum Development Corporation, certain of its +subsidiaries, JPMorgan Chase Bank, N.A., BNP Paribas and Wachovia Bank, +N.A., incorporated by reference to Exhibit 10.1 to Form 8-K filed August +15, 2007. +10.3 +Second +Amendment to Amended and Restated Credit Agreement, dated as of October +16, 2007, by and among Petroleum Development Corporation, certain of its +subsidiaries, JPMorgan Chase Bank, N.A., BNP Paribas, Wachovia Bank, N.A., +Guaranty Bank, FSB, Bank of Oklahoma and Morgan Stanley Bank, incorporated +by reference to Exhibit 10.1 to Form 8-K filed October 22, +2007. +10.4 +Limited +Consent and Waiver, Borrowing Base Increase and Aggregate Revolving +Commitment Increase relating to the Amended and Restated Credit Agreement, +dated as of November 21, 2007, by and among Petroleum Development +Corporation, certain of its subsidiaries, JPMorgan Chase Bank, N.A., BNP +Paribas, Wachovia Bank, N.A., Guaranty Bank, FSB, Bank of Oklahoma and +Morgan Stanley Bank, incorporated by reference to Exhibit 10.1 to Form 8-K +filed November 28, 2007. +10.5 +Employment +Agreement with Steven R. Williams, Chief Executive Officer and Chairman, +dated as of March 7, 2003 and amended December 29, 2005, incorporated by +reference in Exhibit 10.2 to Form 10-K filed on March 7, 2003 +and Exhibit 99.1 to Form 8-K filed January 4, 2006. +10.6 +Employment +Agreement with Darwin L. Stump, Chief Accounting Officer, dated as of +January 5, 2004 and amended December 29, 2005, incorporated by reference +to Exhibit 99.4 Form 10-K dated January 5, 2004, and Exhibit 99.4 to Form +8-K filed January 4, 2006. +10.7 +Employment +Agreement with Thomas E. Riley, President, dated as of January 5, 2004, +and amended December 29, 2005, incorporated by reference to Exhibit 99.6 +Form 10-K dated January 5, 2004, and Exhibit 99.2 to Form 8-K filed +January 4, 2006. +10.8 +Employment +Agreement with Eric R. Stearns, Executive Vice President, dated as of +January 5, 2004, and amended December 29, 2005, incorporated by reference +to Exhibit 99.5 Form 10-K dated January 5, 2004, and Exhibit 99.3 to Form +8-K filed January 4, 2006. +67 +Table of Contents +10.9 +Employment +Agreement with Richard W. McCullough, Chief Financial Officer, dated as of +November 13, 2006, incorporated by reference to Exhibit 10.6 to Form 10-K +filed on May 23, 2007. +10.10 +The +Petroleum Development Corporation 401(k) & Profit Sharing Plan, +incorporated by reference to Exhibit 4.1 to Form S-8, SEC File No. +333-137836. +10.11 +2007 +Compensation Arrangements with Executive Officers, incorporated by +reference to Form 8-K dated February 20, 2007. +10.12 +2007 +Long-Term Incentive Program, incorporated by reference to Exhibit 10.1 to +Form 8-K dated February 20, 2007 +10.13 +2007 +Short-Term Incentive Program, incorporated by reference to Form 8-K dated +April 2, 2007. +10.14 +2005 +Non-Employee Director Restricted Stock Plan, incorporated by reference to +Exhibit 99.1 to Form S-8, SEC File No. 333-126444 filed on July 7, +2005. +10.15 +2004 +Long-Term Equity Compensation Plan, incorporated by reference to Exhibit +99.1 to Form S-8, SEC File No. 333-118215, filed on August 13, +2004. +10.16 +Non-Employee +Director Deferred Compensation Plan, incorporated by reference Exhibit +99.1 to Form S-8, SEC File No. 333-118222, filed on August 13, +2004. +10.17 +1999 +Incentive Stock Option and Non-Qualified Stock, incorporated by reference +to Exhibit 99.1 to Form S-8, SEC File No. 333-111825, filed on January 9, +2004. +10.18 +Indemnification +Agreement with Directors and Officers, incorporated by reference to +Exhibit 10.1 to Form 10-Q filed August 9, 2007. +10.19 +2007 +Long-Term Incentive Program, incorporated by reference to Exhibit 10.1 to +Form 8-K filed on April 13, 2007. +10.20 +2006 +Long-Term Equity Compensation Grants to Executive Officers, incorporated +by reference to Form 8-K filed on April 10, 2007. +10.21 +Purchase +and Sale Agreement by and between Petroleum Development Corporation and +Marathon Oil Company dated July 20, 2006, incorporated by reference to +Exhibit 10.1 to Form 10-Q filed on August 8, 2006. +10.22 +Purchase +and Sale Agreement between EXCO Resources, Inc., as Seller, and Petroleum +Development Corporation, as Buyer, dated effective October 1, 2006, +incorporated by reference to Exhibit 10.1 to Form 8-K filed on January 11, +2007. +10.23 +Purchase +Agreement dated as of February 1, 2008, by and among Petroleum Development +Corporation and the Initial Purchasers of 12% senior notes due 2018 named +therein, incorporated by reference to Exhibit 10.1 to Form 8-K filed on +February 7, 2008 +10.24 +Registration +Rights Agreement dated as of February 8, 2008, by and among Petroleum +Development Corporation and the Initial Purchasers of 12% senior notes due +2018 named therein, incorporated by reference to Exhibit 10-1 to Form 8-K +filed on February 12, 2008. +14.1 +Code +of Business Conduct and Ethics, incorporated by reference to Exhibit 3.1 +to Form 10-K for the year ended December 31, 2002, SEC File No. 0-07246 +filed on March 7, 2003. +21.1 +Subsidiaries, +filed herewith. +23.1 +Consent +of PricewaterhouseCoopers LLP, filed herewith. +23.2 +Consent +of KPMG LLP, filed herewith. +23.3 +Consent +of Wright & Company, Inc., Petroleum Consultants, filed +herewith. +23.4 +Consent +of Ryder Scott Company, L.P., Petroleum Consultants, filed +herewith. +68 +Table of Contents +31.1 +Certification +by Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the +Exchange Act Rules, as adopted pursuant to Section 302 of the +Sarbanes-Oxley Act of 2002, filed herewith. +31.2 +Certification +by Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the +Exchange Act Rules, as adopted pursuant to Section 302 of the +Sarbanes-Oxley Act of 2002, filed herewith. +32.1 +Certifications +by Chief Executive Officer and Chief Financial Officer pursuant to Title +18 U.S.C. Section 1350, as adopted pursuant to Section 906 of +Sarbanes-Oxley Act of 2002, filed +herewith. +69 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +Index +to Consolidated Financial Statements and Financial Statement +Schedule +Management's Report on Internal Control Over +Financial Reporting +F-2 +Financial +Statements: +Reports of Independent Registered Public +Accounting Firms +F-3 +Consolidated Balance Sheets - December 31, 2007 +and 2006 +F-5 +Consolidated Statements of Income - Years Ended +December 31, 2007, 2006 and 2005 +F-6 +Consolidated Statements of Shareholders' Equity - +Years Ended December 31, 2007, 2006 and 2005 +F-7 +Consolidated Statements of Cash Flows - Years +Ended December 31, 2007, 2006 and 2005 +F-8 +Notes to Consolidated Financial +Statements +F-9 +Financial +Statement Schedule: +Schedule +II – Valuation and Qualifying Accounts and +Reserves +F-46 +F-1 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +Management's Report on +Internal Control Over Financial Reporting +Management +is responsible for establishing and maintaining adequate internal control over +financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) of +the Exchange Act. 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. 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 policies +or procedures may deteriorate. +Management +has assessed the effectiveness of the Company’s internal control over financial +reporting as of December 31, 2007, based upon the criteria established in +“Internal Control – Integrated Framework” issued by the Committee of Sponsoring +Organizations of the Treadway Commission (“COSO”). Based on this +evaluation, management concluded that the Company did not maintain effective +internal control over financial reporting as of December 31, 2007 because of the +material weaknesses discussed below. A material weakness is a +deficiency, or a combination of deficiencies, in internal control over financial +reporting, such that there is a reasonable possibility that a material +misstatement of the Company's annual or interim financial statements will not be +prevented or detected on a timely basis. The Company’s assessment, as +of December 31, 2007, identified the following material weaknesses: +· +The +Company did not maintain effective controls to ensure the completeness, +accuracy, validity and restricted access of certain key financial +statement spreadsheets that support all significant balance sheet and +income statement accounts. Specifically, the Company has +inadequate controls over: 1) the security and integrity of the data used +in the various spreadsheets, 2) access to the spreadsheets, 3) changes to +spreadsheet functionality and the related approval process and +documentation, and 4) management's review of the +spreadsheets. These spreadsheets are used in the financial +close and reporting process to perform calculations, generate financial +data supporting all significant processes and key manual controls, and to +compile information to post entries into the general ledger +system. This control deficiency resulted in an audit adjustment +to the Company's consolidated financial statements for the year ended +December 31, 2007. This control deficiency could result in a +misstatement of any of our financial statement accounts and disclosures +that would result in a material misstatement of the annual or interim +financial statements that would not be prevented or detected in a timely +manner. +· +The +Company did not have effective policies and procedures, or personnel with +sufficient technical expertise to record derivative activities in +accordance with generally accepted accounting +principles. Specifically, the Company’s internal control +processes did not ensure the completeness and accuracy of the derivative +activities in the fourth quarter. The lack of documented +policies and procedures, and the turnover in key personnel, including +ineffective management review process, resulted in an audit adjustment to +the Company's consolidated financial statements for the year ended +December 31, 2007. This control deficiency could result in a +misstatement of any of our derivative financial statement accounts and +disclosures that would result in a material misstatement of the annual or +interim financial statements that would not be prevented or detected in a +timely manner. +The +effectiveness of Petroleum Development Corporation's internal control over +financial reporting as of December 31, 2007, has been audited by +PricewaterhouseCoopers LLP, an independent registered public accounting firm, as +stated in their report which appears herein. +PETROLEUM +DEVELOPMENT CORPORATION +/s/ +Steven R. Williams +Steven +R. Williams +Chairman +and Chief Executive Officer +/s/ +Richard W. McCullough +Richard +W. McCullough +President +and Chief Financial Officer +F-2 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +Report of Independent +Registered Public Accounting Firm +To the +Board of Directors and Shareholders +of +Petroleum Development Corporation +In our +opinion, the consolidated financial statements listed in the accompanying index +present fairly, in all material respects, the financial position of Petroleum +Development Corporation and its subsidiaries at December 31, 2007, and the +results of their operations and their cash flows for the year then ended +December 31, 2007 in conformity with accounting principles generally accepted in +the United States of America. In addition, in our opinion, the +financial statement schedule listed in the accompanying index presents fairly, +in all material respects, the information set forth therein when read in +conjunction with the related consolidated financial statements. Also +in our opinion, the Company did not maintain, in all material respects, +effective internal control over financial reporting 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 (COSO) +because material weaknesses in internal control over financial reporting related +to spreadsheets used in the financial reporting process and accounting for +derivative activities existed as of that date. A material weakness is +a deficiency, or a combination of deficiencies, in internal control over +financial reporting, such that there is a reasonable possibility that a material +misstatement of the annual or interim financial statements will not be prevented +or detected on a timely basis. The material weaknesses referred to above are +described in the accompanying Management's Report on Internal Control Over +Financial Reporting. We considered these material weaknesses in +determining the nature, timing, and extent of audit tests applied in our audit +of the 2007 consolidated financial statements, and our opinion regarding the +effectiveness of the Company’s internal control over financial reporting does +not affect our opinion on those consolidated financial +statements. The Company's management is responsible for these +financial statements and financial statement schedule, for maintaining effective +internal control over financial reporting and for its assessment of the +effectiveness of internal control over financial reporting included in +management's report referred to above. Our responsibility is to +express opinions on these financial statements, on the financial statement +schedule, and on the Company's internal control over financial reporting based +on our integrated 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 and whether effective internal control over financial +reporting was maintained in all material respects. Our audit of the +financial statements included examining, on a test basis, evidence supporting +the amounts and disclosures in the financial statements, assessing the +accounting principles used and significant estimates made by management, and +evaluating the overall financial statement presentation. Our audit of +internal control over financial reporting included obtaining an understanding of +internal control over financial reporting, assessing the risk that a material +weakness exists, and testing and evaluating the design and operating +effectiveness of internal control based on the assessed risk. Our +audit also included performing such other procedures as we considered necessary +in the circumstances. We believe that our audit provides a reasonable basis for +our opinions. +As +discussed in Note 6 to the consolidated financial statements, the Company +changed the manner in which it accounts for uncertain tax positions in +2007. +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 (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 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. +/s/ +PricewaterhouseCoopers LLP +Pittsburgh, +Pennsylvania +March 20, +2008 +F-3 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +Report of Independent +Registered Public Accounting Firm +The Board +of Directors and Shareholders +Petroleum +Development Corporation: +We have +audited the accompanying consolidated balance sheet of Petroleum Development +Corporation and subsidiaries as of December 31, 2006, and the related +consolidated statements of income, shareholders' equity, and cash flows for each +of the years in the two-year period ended December 31, 2006. In connection with +our audits of the consolidated financial statements, we also have audited the +related financial statement schedule. These consolidated financial statements +and financial statement schedule are the responsibility of the Company's +management. Our responsibility is to express an opinion on these consolidated +financial statements and financial statement schedule 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, the consolidated financial statements referred to above present fairly, +in all material respects, the financial position of Petroleum Development +Corporation and subsidiaries as of December 31, 2006, and the results of their +operations and their cash flows for each of the years in the two-year period +ended December 31, 2006, in conformity with U. S. generally accepted accounting +principles. Also in our opinion, the related financial statement schedule, when +considered in relation to the basic consolidated financial statements taken as a +whole, presents fairly, in all material respects, the information set forth +therein. +As +discussed in Note 1 to the consolidated financial statements, the Company +adopted the provisions of Statement of Financial Accounting Standards No. +123(R), (“Share-Based Payment”), in 2006. +As +discussed in Note 1 to the consolidated financial statements, the Company +changed its method of quantifying errors based on SEC Staff Accounting Bulletin +No. 108 (“Considering the Effects of Prior Year Misstatements when Quantifying +Misstatements in Current Year Financial Statements”) in 2006. +KPMG +LLP +Pittsburgh, +Pennsylvania +May 22, +2007 +F-4 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +Consolidated +Balance Sheets +(in +thousands, except share and per share data) +December +31, +2007 +2006 +Assets +Current +assets: +Cash +and cash equivalents +$ +84,751 +$ +194,326 +Restricted +cash - current +14,773 +519 +Accounts +receivable, net +60,024 +42,600 +Accounts +receivable - affiliates +11,537 +9,235 +Inventories +2,248 +3,345 +Fair +value of derivatives +4,817 +15,012 +Other +current assets +13,643 +5,977 +Total +current assets +191,793 +271,014 +Properties +and equipment, net +845,864 +394,217 +Restricted +cash - long term +1,294 +192,451 +Goodwill +- +6,783 +Other +assets +11,528 +19,822 +Total +Assets +$ +1,050,479 +$ +884,287 +Liabilities +and Shareholders' Equity +Current +liabilities: +Accounts +payable +$ +88,502 +$ +67,675 +Accounts +payable - affiliates +3,828 +7,595 +Short +term debt +- +20,000 +Production +tax liability +21,330 +11,497 +Other +accrued expenses +12,913 +9,685 +Deferred +gain on sale of leaseholds +- +8,000 +Federal +and state income taxes payable +901 +28,698 +Fair +value of derivatives +6,291 +2,545 +Advances +for future drilling contracts +68,417 +54,772 +Funds +held for distribution +39,823 +31,367 +Total +current liabilities +242,005 +241,834 +Long-term +debt +235,000 +117,000 +Deferred +gain on sale of leaseholds +- +17,600 +Other +liabilities +19,968 +19,400 +Deferred +income taxes +136,490 +116,393 +Asset +retirement obligation +20,731 +11,916 +Total +liabilities +654,194 +524,143 +Commitments +and contingent liabilities +Minority +interest in consolidated limited liability company +759 +- +Shareholders' +equity: +Common +shares, par value $.01 per share; authorized 50,000,000 shares; issued +14,907,679 in 2007 and 14,834,871 in 2006 +149 +148 +Additional +paid-in capital +2,559 +64 +Retained +earnings +393,044 +360,102 +Treasury +shares at cost, 5,894 shares in 2007 and 4,706 in 2006 +(226 +) +(170 +) +Total +shareholders' equity +395,526 +360,144 +Total +Liabilities and Shareholders' Equity +$ +1,050,479 +$ +884,287 +See accompanying Notes to +Consolidated Financial Statements . +F-5 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +Consolidated +Statements of Income +(in +thousands, except per share data) +Year +Ended December 31, +2007 +2006 +2005 +Revenues: +Oil +and gas sales +$ +175,187 +$ +115,189 +$ +102,559 +Sales +from natural gas marketing activities +103,624 +131,325 +121,104 +Oil +and gas well drilling operations +12,154 +17,917 +99,963 +Well +operations and pipeline income +9,342 +10,704 +8,760 +Oil +and gas price risk management gain (loss), net +2,756 +9,147 +(9,368 +) +Other +2,172 +2,221 +2,180 +Total +revenues +305,235 +286,503 +325,198 +Costs +and expenses: +Oil +and gas production and well operations cost +49,264 +29,021 +20,400 +Cost +of natural gas marketing activities +100,584 +130,150 +119,644 +Cost +of oil and gas well drilling operations +2,508 +12,617 +88,185 +Exploration +expense +23,551 +8,131 +11,115 +General +and administrative expense +30,968 +19,047 +6,960 +Depreciation, +depletion, and amortization +70,844 +33,735 +21,116 +Total +costs and expenses +277,719 +232,701 +267,420 +Gain +on sale of leaseholds +33,291 +328,000 +7,669 +Income +from operations +60,807 +381,802 +65,447 +Interest +income +2,662 +8,050 +898 +Interest +expense +(9,279 +) +(2,443 +) +(217 +) +Income +before income taxes +54,190 +387,409 +66,128 +Provision +for income taxes +20,981 +149,637 +24,676 +Net +income +$ +33,209 +$ +237,772 +$ +41,452 +Basic +earnings per common share +$ +2.25 +$ +15.18 +$ +2.53 +Diluted +earnings per common share +$ +2.24 +$ +15.11 +$ +2.52 +See accompanying Notes to +Consolidated Financial Statements . +F-6 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +Consolidated +Statements of Shareholders' Equity +(in +thousands, except per share data) +Year +Ended December 31, +2007 +2006 +2005 +Common +stock, par value $.01 per share - shares issued: +Shares +at beginning of year +14,834,871 +16,281,923 +16,589,824 +Adjust +prior conversion of predecessor shares +- +59,546 +- +Exercise +of stock options +38,000 +8,000 +3,000 +Issuance +of stock awards, net of forfeitures +46,828 +112,902 +20,895 +Retirement +of treasury shares +(12,020 +) +(1,627,500 +) +(331,796 +) +Shares +at end of year +14,907,679 +14,834,871 +16,281,923 +Treasury +stock: +Shares +at beginning of year +(4,706 +) +- +- +Purchase +of treasury shares +(12,020 +) +(1,627,500 +) +(331,796 +) +Retirement +of treasury shares +12,020 +1,627,500 +331,796 +Non-employee +directors' deferred compensation plan +(1,188 +) +(4,706 +) +- +Shares +at end of year +(5,894 +) +(4,706 +) +- +Common +shares outstanding +14,901,785 +14,830,165 +16,281,923 +Common +stock, $.01 par: +Balance +at beginning of year +$ +148 +$ +163 +$ +166 +Exercise +of stock options +- +- +- +Issuance +of stock awards, net of forfeitures +1 +1 +- +Retirement +of treasury shares +- +(16 +) +(3 +) +Balance +at end of year +149 +148 +163 +Additional +paid-in capital: +Balance +at beginning of year +64 +30,423 +37,684 +Reclassification +of unearned compensation pursuant to the adoption of SFAS No. +123(R) +- +(825 +) +- +Exercise +of stock options +183 +31 +12 +Issuance +of stock awards, net of forfeitures +(1 +) +(1 +) +- +Stock +based compensation expense +2,286 +1,516 +603 +Retirement +of treasury shares +(646 +) +(31,150 +) +(7,876 +) +Excess +tax benefit of stock based compensation +673 +70 +- +Balance +at end of year +2,559 +64 +30,423 +Retained +earnings: +Balance +at beginning of year +360,102 +158,504 +117,052 +Cumulative +effect adjustment for the adoption of SAB 108, net of tax +- +(1,021 +) +- +FIN +48 adoption +(267 +) +- +- +Retirement +of treasury shares +- +(35,153 +) +- +Net +income +33,209 +237,772 +41,452 +Balance +at end of year +393,044 +360,102 +158,504 +Unamortized +stock award +Balance +at beginning of year +- +(825 +) +(882 +) +Issuance +of stock awards +- +- +(603 +) +Amortization +of stock awards +- +- +660 +Reclassification +of unearned compensation pursuant to the adoption of SFAS No. +123(R) +- +825 +- +Balance +at end of year +- +- +(825 +) +Treasury +stock, at cost: +Balance +at beginning of year +(170 +) +- +- +Purchase +of treasury shares +(646 +) +(66,319 +) +(7,879 +) +Retirement +of treasury shares +646 +66,319 +7,879 +Non-employee +directors' deferred compensation plan +(56 +) +(170 +) +- +Balance +at end of year +(226 +) +(170 +) +- +Total +shareholders' equity +$ +395,526 +$ +360,144 +$ +188,265 +See accompanying Notes to +Consolidated Financial Statements . +F-7 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +Consolidated +Statements of Cash Flows +(in +thousands) +Year +Ended December 31, +2007 +2006 +2005 +Cash +flows from operating activities: +Net +income +$ +33,209 +$ +237,772 +$ +41,452 +Adjustments +to net income to reconcile to net cash provided by operating +activities: +Deferred +income taxes +12,201 +86,431 +3,351 +Depreciation, +depletion and amortization +70,844 +33,735 +21,116 +Amortization +of debt issuance costs +394 +- +- +Impairment +of oil and gas properties +1,485 +1,519 +- +Accretion +of asset retirement obligation +999 +515 +465 +Exploratory +dry hole costs +1,775 +1,790 +11,115 +Gain +from sale of leaseholds +(33,291 +) +(328,000 +) +(7,669 +) +(Gain) +loss from sale of assets +(31 +) +9 +(207 +) +Expired +and abandoned leases +1,786 +2,169 +48 +Stock +based compensation +2,286 +1,516 +660 +Unrealized +losses (gains) on derivative transactions +4,642 +(7,620 +) +3,226 +Excess +tax benefits from stock-based compensation +(673 +) +(70 +) +- +Changes +in current assets and liabilities: +(Increase) +decrease in restricted cash +(14,254 +) +982 +(836 +) +(Increase) +in accounts receivable +(16,456 +) +(9,935 +) +(11,811 +) +(Increase) +in accounts receivable - affiliates +(2,302 +) +(194 +) +(5,319 +) +Decrease +(increase) in inventories +1,285 +1,987 +(3,398 +) +Decrease +(increase) in other current assets +4,839 +(2,106 +) +3,482 +Increase +(decrease) in production tax liability +10,802 +(261 +) +3,317 +(Decrease) +increase in accounts payable and accrued expenses +(10,869 +) +13,010 +19,440 +(Decrease) +increase in accounts payable - affiliates +(3,099 +) +6,116 +112 +Increase +in advances for future drilling contracts +13,645 +4,773 +7,502 +(Decrease) +increase in federal and state income taxes payable +(27,124 +) +19,950 +8,473 +Increase +(decrease) in funds held for future distribution +7,488 +(575 +) +18,505 +Other +723 +3,877 +(652 +) +Net +cash provided by operating activities +60,304 +67,390 +112,372 +Cash +flows from investing activities: +Capital +expenditures +(238,988 +) +(146,180 +) +(97,390 +) +Acquisition +of oil and gas properties, net of cash acquired +(255,661 +) +(18,512 +) +- +Investment +in drilling partnerships +- +(7,151 +) +(7,160 +) +Exploration +costs +- +(765 +) +(1,918 +) +Decrease +(increase) in restricted/designated cash +191,156 +(192,416 +) +- +Proceeds +from sale of leases to partnerships +1,371 +1,798 +2,829 +Proceeds +from sale of leaseholds/assets +34,701 +353,600 +9,597 +Net +cash used in investing activities +(267,421 +) +(9,626 +) +(94,042 +) +Cash +flows from financing activities: +Proceeds +from debt +352,000 +302,000 +91,000 +Proceeds +from short-term debt +- +20,000 +- +Payment +of long-term debt +(254,000 +) +(209,000 +) +(88,000 +) +Payment +of debt issuance costs +(1,468 +) +(160 +) +(423 +) +Proceeds +from issuance of stock +183 +31 +12 +Excess +tax benefits from stock-based compensation +673 +70 +- +Minority +interest investment +800 +- +- +Purchase +of treasury stock +(646 +) +(66,489 +) +(7,879 +) +Net +cash provided by (used in) financing activities +97,542 +46,452 +(5,290 +) +Net +(decrease) increase in cash and cash equivalents +(109,575 +) +104,216 +13,040 +Cash +and cash equivalents, beginning of period +194,326 +90,110 +77,070 +Cash +and cash equivalents, end of period +$ +84,751 +$ +194,326 +$ +90,110 +See accompanying Notes to +Consolidated Financial Statements . +Supplemental +Cash Flow information See Note 18 . +F-8 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS +NOTE +1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +General +Petroleum +Development Corporation ("PDC," "we," "us" or "the Company") is an independent +energy company engaged primarily in the drilling and development, production and +marketing of natural gas and oil. Since we began oil and gas +operations in 1969, we have grown primarily through drilling and development +activities, the acquisition of producing natural gas and oil wells and the +expansion of our natural gas marketing activities. As of December 31, +2007, we operate approximately 4,354 wells located in the Appalachian Basin, +Michigan Basin, and the Rocky Mountain Region. All of our oil and gas +wells are located in West Virginia, Tennessee, Pennsylvania, Michigan, North +Dakota, Colorado, Kansas, Texas and Wyoming. Our operations are +divided into four business segments: oil and gas sales, natural gas marketing, +oil and gas well drilling operations and well operations and pipeline +income. See Note 17 . +Principles of +Consolidation +The +consolidated financial statements of PDC include the accounts of our wholly +owned subsidiaries and WWWV, LLC, an entity in which we have a controlling +financial interest. All material intercompany accounts and +transactions have been eliminated in consolidation. We account for +our investment in interests in oil and gas limited partnerships under the +proportionate consolidation method. Under this method, our +consolidated financial statements include our investments in the partnerships +recorded by our working interest in each well thereby accumulating our pro rata +share of assets, liabilities and revenues and expenses respectively of the +limited partnerships in which we participate. Our proportionate share +of all significant transactions between us and the limited partnerships is +eliminated. +Cash +Equivalents +For +purposes of the statement of cash flows, we consider all highly liquid debt +instruments with original maturities of three months or less to be cash +equivalents. +Restricted +and Designated Cash +In July +2006, we established a trust in the amount of $300 million with a qualified +intermediary in conjunction with our sale of undeveloped leaseholds and +corresponding "like-kind exchange" agreement. As of December 31, +2006, $300 million remained in the trust, with $109 million reflected in cash +and cash equivalents as a current asset in our consolidated balance sheet and +the remaining $191 million reflected as designated cash – property acquisitions, +a non-current asset. The $191 million represented the amounts paid in +January 2007 for the acquisition of oil and gas properties qualifying for +"like-kind exchange" treatment. Interest earned on the trust account +in 2006 of $5.5 million along with the $109 million not utilized for "like-kind +exchange" purchases, is reflected in cash and cash equivalents, a current asset, +at December 31, 2006, which was available to us for operating purposes in +January 2007 and is no longer subject to a "like-kind exchange." We +terminated the trust in January 2007 following the acquisitions of suitable +like-kind properties, see Note 2 . +In +December 2006, we had paid a deposit of $0.5 million, reflected in our +consolidated balance sheet as designated cash, a non-current asset, for the +acquisition of oil and gas properties subsequently closed in January +2007. +In June +2007, we funded an escrow account in the amount of $14.1 million for amounts due +to the limited partners of our sponsored drilling partnerships as a result of us +over withholding estimated production taxes in years prior to 2007, which is +included, along with interest earned of $0.4 million, in restricted cash, +current, in our consolidated balance sheet as of December 31, 2007. +We are +required to maintain margin deposits with brokers for outstanding derivative +contracts. As of December 31, 2007 and 2006, cash in the amount of +$0.3 million and $0.5 million, respectively, was on deposit and reflected in our +consolidated balance sheets as restricted cash, a current asset. +We are +required by various government agencies or joint venture agreements to maintain +a bond or cash account for the plugging and abandonment of wells. As +of December 31, 2007 and 2006, we had bonds in the form of certificates of +deposit for plugging and abandonment of wells totaling $1.3 million and $1 +million, respectively, which are reflected in restricted/designated cash, a +non-current asset. +F-9 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Inventories +Materials, +supplies and commodity inventories are stated at the lower of average cost or +market and removed at carrying value. +Derivative +Financial Instruments +We +account for derivative financial instruments in accordance with Statement of +Financial Accounting Standards ("SFAS") No. 133, Accounting for Derivative +Instruments and Certain Hedging Activities , as amended. +During +2007, 2006 and 2005, none of our derivative instruments qualified for use of +hedge accounting under the terms of SFAS No. 133. Accordingly, we +recognize all derivative instruments as either assets or liabilities on our +consolidated balance sheets at fair value, and changes in the derivatives' fair +values are recorded in our consolidated statements of income in oil and gas +price risk management, net for our oil and gas commodities (derivatives related +to our production only), in gas sales from marketing activities for RNG’s gas +sales, in cost of gas marketing activities for RNG’s gas +purchases. See Note 15 . +In our +consolidated balance sheets, we record the fair value of derivatives entered +into on behalf of the affiliated partnerships and records an offsetting +receivable from or payable to the partnerships. See Note 15 . +Properties +and Equipment +Oil +and Gas Properties. +We +account for our oil and gas properties under the successful efforts method of +accounting. Costs of proved developed producing properties, +successful exploratory wells and development dry hole costs are capitalized and +depreciated or depleted by the unit-of-production method based on estimated +proved developed producing oil and natural gas reserves. Property +acquisition costs are depreciated or depleted on the unit-of-production method +based on estimated proved oil and gas reserves. +Our +estimates of proved reserves are based on quantities of oil and natural gas that +engineering and geological analysis demonstrates, with reasonable certainty, to +be recoverable from established reservoirs in the future under current operating +and economic conditions. Annually, we engage independent petroleum +engineers to prepare a reserve and economic evaluation of all our properties on +a well-by-well basis as of December 31. Additionally, we adjust our +oil and gas reserves for major acquisitions, new drilling and divestitures +during the year as needed. The process of estimating and evaluating +oil and natural gas reserves is complex, requiring significant decisions in the +evaluation of available geological, geophysical, engineering and economic +data. The data for a given property may also change substantially +over time as a result of numerous factors, including additional development +activity, evolving production history and a continual reassessment of the +viability of production under changing economic conditions. As a +result, revisions in existing reserve estimates occur from time to +time. Although every reasonable effort is made to ensure that reserve +estimates reported represent our most accurate assessments possible, the +subjective decisions and variances in available data for various properties +increase the likelihood of significant changes in these +estimates. Because estimates of reserves significantly affect our +depreciation, depletion and amortization ("DD&A") expense, a change in our +estimated reserves could have an effect on our net income. +Exploration +costs, including geological and geophysical expenses and delay rentals, are +charged to expense as incurred. Exploratory well drilling costs, +including the cost of stratigraphic test wells, are initially capitalized but +charged to expense if the well is determined to be nonproductive. The +status of each in-progress well is reviewed quarterly to determine the proper +accounting treatment under the successful efforts method of +accounting. Exploratory well costs continue to be capitalized as long +as the well has found a sufficient quantity of reserves to justify our +completion as a producing well and we are making sufficient progress assessing +our reserves and economic and operating viability. If an in-progress +exploratory well is found to be unsuccessful (referred to as a dry hole) prior +to the issuance of the financial statements, the costs are expensed to +exploration costs. If we are unable to make a final determination +about the productive status of a well prior to issuance of the financial +statements, the well is classified as “suspended well costs” until we have had +sufficient time to conduct additional completion or testing operations to +evaluate the pertinent geological and engineering data obtained. At +the time when we are able to make a final determination of a well’s productive +status, the well is removed from the suspended well status and the proper +accounting treatment is recorded. At December 31, 2007, suspended +well costs included in oil and gas properties on our accompanying consolidated +financial statements was $2.3 million. See Note 4 . +F-10 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +The +acquisition costs of unproved properties are capitalized when incurred, until +such properties are transferred to proved properties or charged to expense when +expired, impaired or amortized. Unproved oil and gas properties with +individually significant acquisition costs are periodically assessed, and any +impairment in value is charged to exploratory expense. The amount of +impairment recognized on unproved properties which are not individually +significant is determined by amortizing the costs of such properties within +appropriate fields based on our historical experience, acquisition dates and +average lease terms. In 2007, the aggregate impairment resulting from +individually significant unproved properties and insignificant unproved +properties was $1.5 million (which includes the liquidated damages of $1.1 +million related to the abandonment of an exploration agreement with an +unaffiliated party) and $1.8 million, respectively. In 2006, the +impairment resulting from individually significant unproved properties and +insignificant unproved properties was $0.5 million and $0.2 million, +respectively. In 2005, impairment charges for individually +significant and insignificant unproved properties were +immaterial. These impairment costs are included in the statements of +income as a component of exploration cost. The valuation of unproved +properties is subjective and requires us to make estimates and assumptions +which, with the passage of time, may prove to be materially different from +actual realizable values. +In +accordance with SFAS No. 144, Accounting for the Impairment or +Disposal of Long-Lived Assets , we assess our oil and gas properties for +possible impairment quarterly by comparing net capitalized costs to estimated +undiscounted future net cash flows on a field-by-field basis using estimated +production based upon prices at which we reasonably estimate the commodity to be +sold. The estimates of future prices may differ from current market +prices of oil and natural gas. Any downward revisions in estimates to +our reserve quantities, expectations of falling commodity prices or rising +operating costs could result in a reduction in undiscounted future net cash +flows and an impairment of our oil and gas properties. If net +capitalized costs exceed undiscounted future net cash flows, the measurement of +impairment is based on estimated fair value which would consider future +discounted cash flows. We recognized impairment losses on proved oil +and gas properties of $1.5 million in 2006 in our Nesson Field in North Dakota, +which is included in the statements of income as a component of exploration +cost. No impairments were recorded in 2007 or 2005. +Upon sale +or retirement of significant portions of or complete fields of depreciable or +depletable property, the net book value thereof, less proceeds or salvage value, +is credited or charged to income. Upon sale of individual wells, the +proceeds are credited to property costs. +Other +Property and Equipment. +Transportation Equipment, Pipelines +and Other Equipment . Transportation equipment, pipelines and +other equipment are carried at cost. Depreciation is provided +principally on the straight-line method over the assets estimated useful +lives. In accordance with SFAS No. 144 , Accounting for the Impairment or +Disposal of Long-Lived Assets , long-lived assets, such as property, plant +and equipment, are reviewed for impairment whenever events or changes in +circumstances indicate that the carrying amount of an asset may not be +recoverable. Recoverability of assets to be held and used is measured +by a comparison of the carrying amount of an asset to estimated undiscounted +future cash flows expected to be generated by the asset. If the +carrying amount of an asset exceeds our estimated future cash flows, an +impairment charge is recognized in the amount by which the carrying amount of +the asset exceeds the fair value of the asset. No impairments were +recorded in 2007, 2006, or 2005. +Maintenance +and repairs are charged to expense as incurred. Major renewals and +improvements are capitalized. Upon the sale or other disposition of +assets, the cost and related accumulated depreciation, depletion and +amortization are removed from the accounts, the proceeds are applied thereto and +any resulting gain or loss is reflected in income. +Buildings. Buildings +are carried at cost and depreciated on the straight-line method over their +estimated useful lives. +The +following table sets forth the estimated useful lives of our other property and +equipment. +Pipelines +and related facilities +10 +- 17 years +Transportation +and other equipment +3 - +20 years +Buildings +30 +- 40 years +Total +depreciation expense related to other property and equipment was $4.3 million, +$2 million and $2 million in 2007, 2006 and 2005, respectively. +F-11 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Capitalized +Interest +Interest +costs are capitalized as part of the historical cost of acquiring +assets. Oil and gas investments in unproved properties and major +development projects, on which DD&A expense is not currently recorded and on +which exploration or development activities are in progress, qualify for +capitalization of interest. Major construction projects also qualify +for interest capitalization until the asset is ready for +service. Capitalized interest is calculated by multiplying our +weighted-average interest rate on our debt by the qualifying +costs. Interest capitalized may not exceed gross interest expense for +the period. As the qualifying asset is moved to the DD&A pool, +the related capitalized interest is also transferred and is amortized over the +useful life of the asset. Interest costs of $3 million and $1.6 +million were capitalized for the year 2007 and 2006, respectively. No +interest costs were capitalized during 2005. +Production +Tax Liability +Production +tax liability represents estimated taxes, primarily severance and property, to +be paid to the states and counties in which we produce oil and +gas. Our share of these taxes is expensed to oil and gas production +and well operations cost. +Advances +for Future Drilling Contracts +Advances +for future drilling contracts represent funds received from our sponsored +drilling partnerships for drilling activities which have not been completed, a +portion of which will be recognized as revenue in accordance with our revenue +recognition policies. +Income +Taxes +We +account for income taxes under the asset and liability method. We +recognize deferred tax assets and liabilities for the future tax consequences +attributable to differences between the financial statement carrying amounts of +existing assets and liabilities and their respective tax +bases. Deferred tax assets and liabilities are measured using enacted +tax rates expected to apply to taxable income in the years in which those +temporary differences are expected to be recovered or settled. The +effect on deferred tax assets and liabilities of a change in tax rates is +recognized in income in the period that includes the enactment +date. If we determine that it is more likely than not that some +portion or all of the deferred tax assets will not be realized, we record a +valuation allowance thereby reducing the deferred tax assets to what we consider +realizable. No valuation allowance was recorded at December 31, 2007 +or 2006. +Asset +Retirement Obligations +We +account for asset retirement obligations by recording the fair value of our +plugging and abandonment obligations when incurred, which is at the time the +well is completely drilled. Upon initial recognition of an asset +retirement obligation, we increase the carrying amount of the long-lived asset +by the same amount as the liability. Over time, the liabilities are +accreted for the change in their present value, through charges to oil and gas +production and well operations costs. The initial capitalized costs +are depleted over the useful lives of the related assets, through charges to +depreciation, depletion and amortization. If the fair value of the +estimated asset retirement obligation changes, an adjustment is recorded to both +the asset retirement obligation and the asset retirement +cost. Revisions in estimated liabilities can result from revisions of +estimated inflation rates, escalating retirement costs and changes in the +estimated timing of settling asset retirement obligations. See Note 7 for a +reconciliation of asset retirement obligation activity. +Minority +Interest in Consolidated Limited Liability Company +In May +2007, we contributed $0.8 million for a 50% interest in WWWV, LLC ("LLC"), a +limited liability company for which we serve as the managing +member. One-sixth of the entity is owned by the Chief Executive +Officer of our Company, who paid the same unit price for his interest as was +paid by us and unrelated third parties for such interests in the +LLC. The LLC's only asset is an aircraft and the LLC was formed for +the purpose of owning and operating the aircraft. +The +minority interest portion of pre-tax expense incurred by and belonging to the +minority interest holders of the consolidated limited liability company is not +material and included in our consolidated statement of income as an offset to +DD&A expense. +F-12 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Retirement +of Treasury Shares +We +have historically retired all treasury share purchases, with the exception of +shares purchased in accordance with our non-employee deferred compensation plan +for non-employee directors, see Note 9 . As +treasury shares are retired, we charge any excess of cost over the par value +entirely to additional paid-in-capital, to the extent we have amounts in +paid-in-capital, with any remaining excess cost being charged to retained +earnings. +Revenue +Recognition +Oil and natural gas +sales . Sales of oil are recognized when persuasive evidence of +a sales arrangement exists, the oil is verified as produced and is delivered to +a purchaser, collection of revenue from the sale is reasonably assured and the +sales price is determinable. We are currently able to sell all the +oil that we can produce under existing sales contracts with petroleum refiners +and marketers. We do not refine any of our oil +production. Our crude oil production is sold to purchasers at or near +our wells under short-term purchase contracts at prices and in accordance with +arrangements that are customary in the oil industry. +Sales of +natural gas are recognized when natural gas has been delivered to a custody +transfer point, persuasive evidence of a sales arrangement exists, the rights +and responsibility of ownership pass to the purchaser upon delivery, collection +of revenue from the sale is reasonably assured and the sales price is fixed or +determinable. Natural gas is sold by us under contracts with terms +ranging from one month to three years. Virtually all of our contract +pricing provisions are tied to a market index, with certain adjustments based +on, among other factors, whether a well delivers to a gathering or transmission +line, quality of natural gas and prevailing supply and demand conditions, so +that the price of the natural gas fluctuates to remain competitive with other +available natural gas supplies. As a result, our revenues from the +sale of natural gas will suffer if market prices decline and benefit if they +increase. We believe that the pricing provisions of our natural gas +contracts are customary in the industry. +We +currently use the "net-back" method of accounting for transportation +arrangements of our natural gas sales. We sell gas at the wellhead +and collect a price and recognize revenues based on the wellhead sales price +since transportation costs downstream of the wellhead are incurred by the +customers and reflected in the wellhead price. +Natural gas marketing +activities . Natural gas marketing is reported on the gross +accounting method, based on the nature of the agreements between RNG, our +suppliers and our customers. RNG, our marketing subsidiary, purchases +gas from many small producers and bundles the gas together to sell in larger +amounts to purchasers of natural gas for a price advantage. RNG has +latitude in establishing price and discretion in supplier and purchaser +selection. Natural gas marketing revenues and expenses reflect the +full cost and revenue of those transactions because RNG takes title to the gas +it purchases from the various producers and bears the risks and rewards of that +ownership. Both the realized and unrealized gains and losses of the +RNG commodity based derivative transactions for natural gas marketing activities +are included in gas sales from marketing activities or cost of gas marketing +activities, as applicable. +Oil and gas well drilling +operations . Our drilling segment recognizes revenue from +drilling contracts with sponsored drilling programs using the percentage of +completion method based upon the percentage of contract costs incurred to date +to the estimated total contract costs for each contract. We utilize +this method since reasonably dependable estimates of the total estimated costs +can be made and recognized revenues are subject to revisions as a contract +progresses, the term of which can range from three to twelve +months. In addition, we offer our drilling services under two types +of contractual arrangements, cost-plus or footage-based service contracts, which +result in differing risk and reward relationships, and consequently, different +revenue reporting policies pursuant to Emerging Issues Task Force ("EITF") Issue +No. 99-19, Reporting Revenue +Gross as a Principal versus Net as an Agent . +The first +cost-plus drilling service arrangement was entered into in late 2005 with +drilling activity commencing in the first quarter of 2006. Due to the +fixed-fee-percentage nature of our revenues from these services, we have +determined that, in substance, we are acting as an agent, without risk of loss +during the performance of the drilling activities. Accordingly, our +services provided under the cost-plus drilling agreements are reported on a net +basis. We entered into our second and third cost-plus drilling +arrangements in September 2006 and August 2007 and commenced drilling +immediately. +Footage-based +contracts provide for the drilling, completion and equipping of wells at footage +rates and are generally completed within nine to twelve months after the +commencement of drilling. We provide geological, engineering, and +drilling supervision on the drilling and completion process and use +subcontractors to perform drilling and completion services and accordingly has +the risk of loss in performing services under these +arrangements. Accordingly, we report revenue under these agreements +gross of related expenses. Anticipated losses, if any, on uncompleted +contracts are recorded at the time that the estimated total costs exceed the +estimated total contract revenue. At December 31, 2007 and 2006, the +loss contract reserve was $0.2 million and $0.3 million, +respectively. +F-13 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Well operations and pipeline +income . Well operations and pipeline income are recognized +when persuasive evidence of an arrangement exists, services have been rendered, +collection of revenues is reasonably assured and the sales price is fixed or +determinable. We are paid a monthly operating fee for each well we +operate for outside owners including the limited partnerships we +sponsored. The fee covers monthly operating and accounting costs, +insurance and other recurring costs. We may also receive additional +compensation for special non-recurring activities, such as reworks and +recompletions. +Stock-Based +Compensation +Effective +January 1, 2006, we adopted SFAS No. 123R, Share-Based Payment (revised +2004) . We elected the modified prospective method of adoption, +and accordingly, prior period financial statements have not been +restated. Pursuant to SFAS No. 123R we are required to recognize in +our financial statements, based on fair value, compensation expense for all +unvested stock options and other equity-based awards as of January 1, +2006. For all unvested options outstanding as of January 1, 2006 the +previously measured but unrecognized compensation expense, based on the fair +value at the original grant date, will be recognized in the financial statements +over the remaining requisite service period for each separately vesting +portion. For equity-based compensation awards granted or modified +subsequent to January 1, 2006, compensation expense, based on the fair value on +the date of grant or modification, will be recognized in the financial +statements on a straight-line basis over the vesting period for the entire +award. To the extent compensation cost relates to employees directly +involved in oil and natural gas acquisition, exploration and development +activities, such amounts are capitalized to properties and +equipment. Amounts not capitalized to properties and equipment are +recognized in the appropriate cost and expense line item in the statement of +income. For the year ended December 31, 2007 and 2006, we recognized +stock-based compensation expense of $2.3 million and $1.5 million related to +stock awards, respectively. Compensation capitalized as part of +properties and equipment was immaterial in 2007 and 2006. +For +periods prior to the adoption of SFAS No. 123(R), we accounted for +our share-based compensation awards using the intrinsic value based method as +prescribed by Accounting Principles Board Opinion ("APB") No. 25, Accounting for Stock Issued to +Employees , and related interpretations. Under the intrinsic +value based method, compensation expense for option awards was recorded on the +date of grant only if the then-current market price of the underlying stock +exceeded the exercise price. The following table illustrates the +effect on net income and earnings per share had we applied the fair value +recognition provisions of SFAS No. 123(R), as amended, to stock-based employee +compensation during 2005 (in thousands, except per share data): +Year +ended December 31, 2005 +(in thousands, except +per share data) +Net +income, as reported: +$ +41,452 +Stock-based +compensation expense included in reported net income, net of +tax +414 +Total +stock-based compensation expense determined under fair value method +for all awards, net of tax +(509 +) +Pro +forma net income +$ +41,357 +Earnings +per share: +Basic +earnings per share, as reported and pro forma +$ +2.53 +Diluted +earnings per share, as reported and pro forma +$ +2.52 +Earnings +Per Share +Our basic +earnings per share ("EPS") amounts have been computed based on the average +number of shares of common stock outstanding for the period. Diluted +EPS amounts include the effect of our outstanding stock options, unamortized +portion of restricted stock and shares held pursuant to our non-employee +director deferred compensation plan using the treasury stock method if including +such potential shares of common stock is dilutive. See Note 12 . +F-14 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Use +of Estimates +The +preparation of our consolidated financial statements in accordance with +generally accepted accounting principles in the United States of America +requires us to make estimates and assumptions that affect the amounts reported +in our consolidated financial statements and accompanying +notes. Actual results could differ from those +estimates. Estimates which are particularly significant to our +consolidated financial statements include estimates of oil and gas reserves, +future cash flows from oil and gas properties, valuation of derivative +instruments and valuation of deferred income tax assets. +Fair +Value of Financial Instruments +The +carrying values of our receivables, payables and debt obligations approximate +fair value as of December 31, 2007 and 2006, due to the short-term maturity of +these instruments. +Recent +Accounting Standards +Recently Adopted Accounting +Standards +In +December 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS No. +123(R), Share-Based +Payment . In March 2005, the Securities and Exchange Commission +(“SEC”) issued Staff Accounting Bulletin (“SAB”) No. 107, Share-Based Payment , +regarding the interaction between SFAS No. 123(R) and certain SEC rules and +regulations. Effective January 1, 2006, we adopted SFAS No. 123(R). +We elected to use the modified prospective method for adoption, which requires +compensation expense to be recognized in the statement of income for all +unvested stock options and other equity-based compensation beginning in the +first quarter of adoption. Prior to the adoption of SFAS No. 123(R), +we followed the intrinsic value method in accordance with APB No. 25 (as +amended) to account for employee stock-based compensation. The +adoption of SFAS No. 123(R) required the unamortized stock award recorded under +APB No. 25 related to stock-based compensation awards as of January 1, 2006, in +the amount of $0.8 million to be eliminated against additional +paid-in-capital. See Stock-Based Compensation policy above and Note 9 +for further discussion of the Company's accounting for share-based compensation +awards. +In +September 2006, the SEC issued SAB No. 108, Considering the Effects of Prior +Year Misstatements when Quantifying Misstatements in Current Year Financial +Statements . SAB No. 108 provides guidance on how the effects +of prior year misstatements should be considered in quantifying misstatements in +the current year financial statements. SAB No. 108 requires +registrants to quantify misstatements using both the income statement +(“rollover”) and balance sheet (“iron curtain”) approach and evaluate whether +either approach results in a misstatement that, when all relevant quantitative +and qualitative factors are considered, is material. Historically, we +evaluated uncorrected misstatements using the “rollover” method which resulted +in an accumulation of quantitatively and qualitatively immaterial misstatements +to our consolidated financial statements. SAB No. 108 provides for a +one time transitional adjustment to retained earnings for errors which were not +deemed material to prior year financial statements, but which is material under +guidance of SAB No. 108. We adopted SAB No. 108 during the fourth +quarter of 2006 and recorded a one time adjustment to reduce retained earnings +by $1.0 million. +In June +2006, the FASB issued EITF No. 06-3, How Taxes Collected from Customers +and Remitted to Governmental Authorities Should be Presented in the Income +Statement (That Is, Gross versus Net Presentation) . EITF 06-3 +addresses the income statement presentation of any tax collected from customers +and remitted to a government authority and concludes that the presentation of +taxes on either a gross basis or a net basis is an accounting policy decision +that should be disclosed pursuant to APB No. 22, Disclosures of Accounting +Policies . For taxes that are reported on a gross basis +(included in revenues and costs), EITF 06-3 requires disclosure of the amounts +of those taxes in interim and annual financial statements, if those amounts are +significant. EITF 06-3 became effective for interim and annual +reporting periods beginning after December 15, 2006. The adoption of +the standard, effective January 1, 2007, did not have a significant effect on +our consolidated financial statements. Our existing accounting +policy, which was not changed upon the adoption of EITF 06-3, is to present +taxes within the scope of EITF 06-3 on a net basis. +In July +2006, the FASB issued FASB Interpretation ("FIN") No. 48, Accounting for Uncertainty in Income +Taxes - an Interpretation of FASB Statement 109 , which prescribes a +comprehensive model for accounting for uncertainty in tax +positions. FIN No. 48 provides that the tax effects from an uncertain +tax position can be recognized in the financial statements, only if the position +is more likely than not of being sustained on audit by the Internal Revenue +Service ("IRS"), based on the technical merits of the position. The +provisions of FIN No. 48 became effective for us on January 1, +2007. The cumulative effect of applying the provisions of FIN No. 48 +has been accounted for as an adjustment to retained earnings in the first +quarter of 2007. The adoption of FIN No. 48 resulted in a $0.3 +million cumulative effect adjustment (see Note 6 for further +discussion). +F-15 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +In May +2007, the FASB issued FASB Staff Position FIN No. 48-1, Definition of Settlement in FASB +Interpretation No. 48 ("FIN No. 48-1"). FIN No. 48-1 amends +FIN No. 48 to provide guidance on how an entity should determine whether a tax +position is effectively settled for the purpose of recognizing previously +unrecognized tax benefits. The term "effectively settled" replaces +the term "ultimately settled" when used to describe recognition, and the terms +"settlement" or "settled" replace the terms "ultimate settlement" or "ultimately +settled" when used to describe measurement of a tax position under FIN No. +48. FIN No. 48-1 clarifies that a tax position can be effectively +settled upon the completion of an examination by a taxing authority without +being legally extinguished. For tax positions considered effectively +settled, an entity would recognize the full amount of tax benefit, even if the +tax position is not considered more likely than not to be sustained based solely +on the basis of its technical merits and the statute of limitations remains +open. The adoption of FIN No. 48-1, effective January 1, 2007, did +not have an incremental effect on our consolidated financial +statements. +Recently Issued Accounting +Standards +In +September 2006, the FASB issued SFAS No. 157, Accounting for Fair Value +Measurements . SFAS No. 157 defines fair value, establishes a +framework for measuring fair value within generally accepted accounting +principles and expands required disclosure about fair value +measurements. SFAS No. 157 does not expand the use of fair value in +any new circumstances. SFAS No. 157 is effective for financial +statements issued for fiscal years beginning after November 15, +2007. However, on February 12, 2008, the FASB issued FASB Staff +Position ("FSP") FAS 157-2, Effective Date of FASB Statement No. +157 , which delayed the effective date of SFAS No. 157 for all +nonfinancial assets and nonfinancial liabilities, except those that are +recognized or disclosed at fair value in the financial statements on a recurring +basis (at least annually). This FSP partially defers the effective +date of SFAS No. 157 to fiscal years beginning after November 15, 2008, and +interim periods within those fiscal years for items within the scope of this +FSP. Effective January 1, 2008, we will adopt SFAS No. 157 except as +it applies to those nonfinancial assets and nonfinancial liabilities as noted in +FSP FAS 157-b. We are evaluating the effect that these new standards +will have, if any, on our consolidated financial statements when +adopted. +In +February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial +Assets and Financial Liabilities . SFAS No. 159 permits +entities to choose to measure, at fair value, many financial instruments and +certain other items that are not currently required to be measured at fair +value. The objective is to improve financial reporting by providing +entities with the opportunity to mitigate volatility in reported earnings caused +by measuring related assets and liabilities differently without having to apply +complex hedge accounting provisions. SFAS No. 159 establishes +presentation and disclosure requirements designed to facilitate comparisons +between entities that choose different measurement attributes for similar types +of assets and liabilities. The statement will be effective as of the +beginning of an entity's first fiscal year beginning after November 15, +2007. We are evaluating the effect that SFAS No. 159 will have, if +any, in our consolidated financial statements when it is adopted in +2008. +In April +2007, the FASB issued FSP FIN No. 39-1, Amendment of FASB Interpretation No. +39 ("FIN No. 39-1'), to amend certain portions of Interpretation +39. FIN No. 39-1 replaces the terms "conditional contracts" and +"exchange contracts" in Interpretation 39 with the term "derivative instruments" +as defined in Statement 133. FIN No. 39-1 also amends Interpretation +39 to allow for the offsetting of fair value amounts for the right to reclaim +cash collateral or receivable, or the obligation to return cash collateral or +payable, arising from the same master netting arrangement as the derivative +instruments. FIN No. 39-1 applies to fiscal years beginning after +November 15, 2007, with early adoption permitted. We are evaluating +the effect that FIN No. 39-1 will have, if any, on our consolidated financial +statements when adopted in 2008. +In +December 2007, FASB issued SFAS No. 141 (revised 2007), Business Combinations ("SFAS +No. 141R"), which replaces FASB Statement No. 141. SFAS No. 141R +establishes principles and requirements for how an acquirer recognizes and +measures in its financial statements the identifiable assets acquired, the +liabilities assumed, any non-controlling interest in the acquiree and the +goodwill acquired. This statement also establishes disclosure +requirements which will enable users to evaluate the nature and financial +effects of the business combination. SFAS No. 141R is effective as of +the beginning of an entity’s fiscal year beginning after December 15, +2008. We are evaluating the potential effect that the adoption of +SFAS No. 141R will have, if any, on our consolidated financial statements when +adopted in 2008. +In +December 2007, the FASB issued SFAS No. 160, Non-controlling Interests in +Consolidated Financial Statement—An Amendments of ARB No. 51 ("SFAS No. +160"). SFAS No. 160 states that accounting and reporting for minority +interests will be recharacterized as non-controlling interests and classified as +a component of equity. Additionally, SFAS No. 160 establishes +reporting requirements that provide sufficient disclosures which clearly +identify and distinguish between the interests of the parent and the interests +of the non-controlling owners. SFAS No. 160 is effective as of the +beginning of an entity’s first fiscal year beginning after December 15, +2008. We are currently evaluating the potential effect that the +adoption of SFAS No. 160 will have, if any, on our consolidated financial +statements. +F-16 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +NOTE +2 – ACQUISITIONS +2007 +Acquisitions +Acquisition +of Internal Revenue Code Section 1031 – Like-Kind Exchange +Properties +During +the first quarter of 2007, we completed the acquisition of suitable like-kind +properties in accordance with the like-kind exchange ("LKE") agreement we +entered into in connection with our sale of undeveloped leaseholds located in +Grand Valley Field, Garfield County, Colorado in July 2006. We +acquired, for cash, qualifying oil and gas properties totaling $188.9 million, +including costs of acquisition, as described below. +EXCO +Properties. On January 5, 2007, we completed the purchase of +producing properties and undeveloped drilling locations and acreage in the +Wattenberg Field of the DJ Basin, Colorado from EXCO Resources Inc., an +unaffiliated party. The acquisition included substantially all of +EXCO’s assets in the area and encompassed 144 oil and natural gas wells +(approximating 25.5 Bcfe proved developed reserves as of December 31, 2005) and +8,160 acres of leasehold interests. The wells and leases acquired are +located in Weld, Adams, Larimer, and Broomfield Counties, +Colorado. We operate the assets and hold a majority working interest +in the properties . +Company Sponsored +Partnerships . On January 10, 2007, we completed the purchase +of the remaining working interests in 44 of our sponsored +partnerships. The transaction resulted in an increase in our +ownership in 718 gross (423 net) wells that we currently operate. The +wells are located primarily in the Appalachian Basin and Michigan. +The +following table presents the adjusted purchase price for the like-kind exchange +property acquisitions described above as of December 31, 2007. +EXCO +Partnerships +(in +thousands) +Cash +consideration paid +$ +128,672 +$ +57,776 +Plus: +direct costs of acquisition +1,662 +1,664 +Less: +acquisition cost adjustments +(119 +) +(2,792 +) +Total acquisition +cost +$ +130,215 +$ +56,648 +The +following table presents, as of the respective date of acquisition, the final +allocations of the purchase prices based on estimates of fair +value. +EXCO +Partnerships +(in +thousands) +Current +assets acquired +$ +91 +$ +- +Proved +oil and gas properties +117,099 +45,813 +Unproved +oil and gas properties +14,960 +13,268 +Asset +retirement obligation +(422 +) +(2,433 +) +Other +liabilities assumed +(1,513 +) +- +Preliminary +acquisition cost +$ +130,215 +$ +56,648 +The +assessment of fair value of proved oil and gas properties acquired was based +primarily on projections of expected discounted future cash flows of acquired +oil and natural gas reserves. To compensate for the inherent risk of +estimating and valuing unproved properties, the discounted future net revenues +of probable reserves were reduced by additional risk-weighting factors in that +valuation. +Other. In January +2007, we acquired from unaffiliated parties other like-kind undeveloped +leaseholds in Erath County, Texas for $2.1 million, including costs of +acquisition. Acreage in this area is prospective for development of +oil and natural gas reserves in the Barnett Shale. +F-17 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Other +Acquisitions +On +February 22, 2007, we acquired, from an unaffiliated party, 28 producing wells +and associated undeveloped acreage located in Colorado (Wattenberg Field) for a +purchase price of $12 million, which was allocated to oil and gas +properties. +On +October 30, 2007, with an effective date of October 1, 2007, we purchased from +unrelated parties, Castle Gas Company, et.al., a majority working interest in +762 natural gas wells located in southwestern Pennsylvania for approximately $54 +million. We estimated that the acquisition included approximately 47 +Bcfe of reserves, or 31 Bcfe of proved reserves and 16 Bcfe of unproved +reserves. The purchase also included associated pipelines, equipment, +real estate and undeveloped acreage. +The +following table presents the adjusted purchase price for the Castle acquisition +described above as of December 31, 2007. +(in +thousands) +Cash +consideration paid +$ +53,041 +Plus: +direct costs of acquisition +443 +Plus: +acquisition cost adjustments +583 +Total acquisition +cost +$ +54,067 +The +following table presents, as of the respective date of acquisition, the final +preliminary allocation of the purchase price based on estimates of fair +value. +(in +thousands) +Current +assets acquired +$ +185 +Proved +oil and gas properties +55,778 +Unproved +oil and gas properties +217 +Real +estate and equipment, and other assets +2,115 +Non +current assets +783 +Asset +retirement obligation +(4,043 +) +Other +liabilities assumed +(968 +) +Preliminary +acquisition cost +$ +54,067 +The +assessment of fair value of proved oil and gas properties acquired was based +primarily on projections of expected discounted future cash flows of acquired +oil and natural gas reserves. To compensate for the inherent risk of +estimating and valuing unproved properties, the discounted future net revenues +of probable reserves were reduced by additional risk-weighting factors in that +valuation. +Pro +Forma Financial Information +The +results of operations for all of the above acquisitions have been included in +our consolidated financial statements from the dates of +acquisition. The pro forma effect of the inclusion in our +consolidated statement of income for the year ended December 31, 2007, of the +results of operations for the January and February 2007 acquisitions described +above, individually and in the aggregate, was not material. +The +following unaudited pro forma financial information presents a summary of our +consolidated results of operations for the years ended December 31, 2007 and +2006, assuming the acquisitions of the EXCO properties, our sponsored +partnerships and the Castle properties had been completed as of January 1, 2006, +including adjustments to reflect the allocation of the purchase price to the +acquired net assets. The pro forma effect of the inclusion of the +results of operations for all of the other acquisitions described above, +individually and in the aggregate, was not material. +F-18 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Year +Ended December 31, +2007 +2006 +(in +thousands, except per share data) +Total +revenues +$ +310,351 +$ +315,492 +Net +income +34,571 +243,105 +Earnings +per common share: +Basic +$ +2.34 +$ +15.52 +Diluted +$ +2.33 +$ +15.44 +The pro +forma results of operations are not necessarily indicative of what our results +of operations would have been had the EXCO properties, our sponsored +partnerships and the Castle properties been acquired at the beginning of the +periods indicated, nor does it purport to represent our results of operations +for any future periods. +2006 +Acquisitions +On +December 6, 2006, we completed our cash tender offer and purchased approximately +95.5% or 9,112,750 shares of the outstanding common stock of Unioil, an +independent energy company with properties in northern Colorado and southern +Wyoming. The acquisition of more than 90% of the outstanding shares +of common stock allowed us to effect a short-form merger of Unioil and one of +our wholly owned subsidiaries, resulting in the acquisition of the remaining +428,719 shares of Unioil. Each share of Unioil common stock not +tendered through the offer was converted into the right to receive $1.91 in +cash, the same consideration paid for shares in the tender offer. The +total price paid for 100% of Unioil’s outstanding common stock was $18.6 +million, including $0.4 million in direct costs of the acquisition. The +preliminary acquisition cost allocation included $6.8 million goodwill, in +which was re-allocated to properties and equipment in the first quarter of 2007 +as part of our process of finalizing the allocation of the preliminary purchase +price. Further, as a result of this reclass, the deferred tax liabilities +increased and thus increased property and equipment. +The +following table presents the adjusted purchase price for the Unioil acquisition +described above as of December 31, 2007. +(in +thousands) +Cash +consideration paid +$ +18,224 +Plus: +direct costs of acquisition +382 +Total acquisition +cost +$ +18,606 +The +following table presents the final allocations of the purchase price based on +estimates of fair value. +(in +thousands) +Current +assets acquired +$ +660 +Properties +and equipment acquired +25,839 +Deferred +tax liability +(6,783 +) +Other +liabilities assumed +(968 +) +Preliminary +acquisition cost +$ +18,748 +NOTE 3 – ACCOUNTS +RECEIVABLE +Accounts +receivable is presented on our consolidated balance sheets net of allowance for +doubtful accounts. Accounts receivable are reviewed to determine +which are doubtful of collection. In making the determination of the +appropriate allowance for doubtful accounts, we consider our historical +write-offs, relationships and overall credit worthiness of our customers, +additional consideration is given to well production data for receivables +related to well operations. The allowance as reflected in the +accompanying balance sheets is our best estimate of the amount of probable +credit losses in our existing accounts receivable. Our allowance for +doubtful accounts as of December 31, 2007 and 2006, was $0.4 million and $0.4 +million, respectively. +F-19 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +The +nature of the independent oil and gas industry involves a concentration of oil +and gas sales to a few customers. We sell oil and natural gas to +various public utilities, gas marketers and industrial customers. The +following table identifies significant customers as a percent of total oil and +gas sales and total revenues for each of the years presented. +Oil +and Gas Sales +Total +Revenue +Year +Ended December 31, +Year +Ended December 31, +2007 +2006 +2005 +2007 +2006 +2005 +Customer +Tepco +Crude Oil, LLC +14.8 +% +14.9 +% +10.5 +% +13.5 +% +12.9 +% +6.9 +% +Williams +Production RMT Company +14.1 +% +8.7 +% +4.7 +% +12.9 +% +7.5 +% +3.1 +% +DCP +Midstream, LP +7.8 +% +10.6 +% +10.6 +% +7.1 +% +9.1 +% +6.9 +% +Integrys +(formerly WPS, Energy) +6.9 +% +9.4 +% +12.9 +% +6.3 +% +8.1 +% +8.4 +% +Sempra +Energy Trading +6.0 +% +10.3 +% +15.2 +% +5.5 +% +8.9 +% +9.9 +% +NOTE +4 – PROPERTIES AND EQUIPMENT +December +31, +December +31, +2007 +2006 +(in +thousands) +Properties +and equipment, net: +Oil +and gas properties (successful efforts method of +accounting) +Proved +$ +953,904 +$ +473,451 +Unproved +41,023 +27,055 +Total +oil and gas properties +994,927 +500,506 +Pipelines +and related facilities +22,408 +12,673 +Transportation +and other equipment +23,669 +7,870 +Land +and buildings +11,303 +11,620 +Construction +in progress (1) +2,929 +4,801 +1,055,236 +537,470 +Accumulated +depreciation, depletion and amortization ("DD&A") +(209,372 +) +(143,253 +) +$ +845,864 +$ +394,217 +(1) +At +December 31, 2007, includes cost primarily related to a new integrated oil and +gas financial software system. +Suspended +Well Costs +The +following table sets forth the capitalized exploratory well costs, which are +pending the determination of proved reserves, included in oil and gas +properties. +2007 +2006 +2005 +(in +thousands) +Beginning +balance at January 1 +$ +765 +$ +1,918 +$ +4,170 +Additions +to capitalized exploratory well costs pending the determination of proved +reserves +3,953 +12,016 +6,441 +Reclassifications +to wells, facilities and equipment based on the determination of proved +reserves +(878 +) +(13,169 +) +(4,523 +) +Capitalized +exploratory well costs charged to expense +(1,540 +) +- +(4,170 +) +Ending +balance at December 31 +$ +2,300 +$ +765 +$ +1,918 +As of +December 31, 2007, the three wells awaiting the determination of proved reserves +have not been capitalized for a period greater than one year. +F-20 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +NOTE +5 - LONG-TERM DEBT +We have a +credit facility with JPMorgan Chase Bank, N.A. ("JPMorgan") and BNP Paribas, as +amended, dated as of November 4, 2005, with an activated commitment of $295 +million as of December 31, 2007. The credit facility, through a +series of amendments, includes commitments from Wachovia Bank, N.A., Bank of +Oklahoma, Allied Irish Banks p.l.c., Guaranty Bank, BSB, Royal Bank of Canada +and The Royal Bank of Scotland, plc. The maximum allowable commitment +under the current credit facility is $400 million. The credit +facility is subject to and secured by required levels of oil and natural gas +reserves. The credit facility requires an aggregated security of a +value no less than 80% of the value of the direct interests included in the +borrowing base properties. We are required to pay a commitment fee of +0.25% to 0.375% per annum on the unused portion of the activated credit +facility. Interest accrues at an alternative base rate ("ABR") or +adjusted LIBOR at our discretion. The ABR is the greater of +JPMorgan's prime rate, an adjusted secondary market rate for a three-month +certificate of deposit plus 1% or the federal funds effective rate plus +0.5%. ABR borrowings are assessed an additional margin spread up to +0.375% and adjusted LIBOR borrowings are assessed an additional margin spread of +1.125% to 1.875%, based upon the outstanding balance under the credit +facility. The credit agreement requires, among other things, the +maintenance of certain working capital and tangible net worth +ratios. No principal payments are required until the credit agreement +expires on November 4, 2010. +The +credit facility contains covenants customary for agreements of this type, +including, but not limited to, limitations on our ability to: (a) incur +additional indebtedness and guarantees, (b) create liens and other encumbrances +on our assets, (c) consolidate, merge or sell assets, (d) pay dividends and +other distributions, (e) make certain investments, loans and advances, (f) enter +into sale/leaseback transactions, (g) enter into transactions with our +affiliates, (h) change the character of our business, (i) engage in hedging +activities unless certain requirements are satisfied, (j) issue certain types of +stock, and (k) make certain amendments to our organizational +documents. The credit facility also requires us to execute and +deliver specified mortgages and other evidences of security and to deliver +specified opinions of counsel and other evidences of title. In +addition, we are required to comply with certain financial tests and maintain +certain financial ratios. The financial tests and ratios include requirements +to: (a) maintain a minimum ratio of consolidated current assets to consolidated +current liabilities, or working capital ratio, and (b) not to exceed a maximum +leverage ratio. +Effective +August 9, 2007, the first amendment to our credit facility waived our working +capital covenant until the earlier of (i) a debt or equity transaction resulting +in net proceeds, as defined, to us of at least $200 million or (ii) July 1, +2008, which was further extended to October 1, 2008, effective October 16, +2007. In accordance with the first amendment, the ABR rate was +increased by 0.375% as long as the waiver of the working capital covenant is in +effect. +On +February 8, 2008, we completed the issuance and sale of $203 million aggregate +principal amount of 12% senior notes due 2018 for net proceeds received of +approximately $196 million (see Note +19 ). In accordance with the senior credit agreement, upon the +issuance of any senior notes, the borrowing base then in effect on our credit +facility will automatically be reduced by $300 for each $1,000 in stated +principal amount of such senior notes issued by us. Accordingly, +effective February 8, 2008, our borrowing base under the credit facility was +reduced from $295 million to $234.1 million. Further, our notes +issuance meets the requirements of a debt transaction described above, and thus, +the testing of our working capital covenant will resume with our quarter ending +March 31, 2008. +The +indenture governing our senior notes contains covenants that, among other +things, limit our ability and the ability of our restricted subsidiaries to +incur additional debt; make certain investments or pay dividends or +distributions on our capital stock or purchase or redeem or retire capital +stock; sell assets, including capital stock of our restricted subsidiaries; +restrict dividends or other payments by restricted subsidiaries; create liens +that secure debt; enter into transactions with affiliates; and merge or +consolidate with another company. +As of +December 31, 2007, the outstanding balance under our credit facility was $235 +million compared to $117 million, excluding the overline note discussed below, +as of December 31, 2006. The borrowing rate on the outstanding +balance was 7.07% and 7.79% at December 31, 2007, and December 31, 2006, +respectively. Amounts outstanding under the credit facility were +secured by substantially all of our properties. We were in compliance +with all covenants at December 31, 2007. +On +December 19, 2006, we executed, pursuant to our credit facility, an overline +note in the amount of $20 million to be repaid on January 31, +2007. Interest on the overline note accrued at a per annum rate equal +to the alternate base rate plus 0.8% until December 22, 2006, at which time the +rate converted to a Eurodollar borrowing for a one month period and at a per +annum rate equal to an adjusted LIBOR rate plus 2.30%. The overline +note was paid in full in accordance with its terms in January 2007. +F-21 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +NOTE +6 - INCOME TAXES +In +both 2007 and 2006, we utilized our tax election to currently expense +approximately $44 million and $55 million, respectively, of intangible drilling +costs ("IDC"). This election substantially reduced our current tax +expense but resulted in a correspondingly higher deferred tax expense as shown +below. Additionally, in 2006, we had a substantial taxable gain from +the sale of undeveloped oil and gas properties (see Note +16 ). We have chosen to use the favorable deferral aspects of +the Internal Revenue Code ("IRC") Section 1031, LKE to defer the tax +liability on a portion of the gain utilized by purchasing replacement properties +(see Note +2 ). Accordingly, our current and deferred provision for income +taxes increased proportionately in 2006 due to the current and deferred tax +associated with this large taxable gain. The components of our tax +expense consisted of the following: +2007 +2006 +2005 +(in +thousands) +Current: +Federal +$ +7,579 +$ +54,467 +$ +17,894 +State +1,201 +8,739 +3,431 +Total +current income taxes +8,780 +63,206 +21,325 +Deferred: +Federal +11,074 +74,003 +2,834 +State +1,127 +12,428 +517 +Total +deferred income taxes +12,201 +86,431 +3,351 +Total +income taxes +$ +20,981 +$ +149,637 +$ +24,676 +Income +tax expense differed from the amounts computed by applying the U.S. federal +income tax rate of 35%. +2007 +2006 +2005 +(in +thousands) +Computed +"expected" tax +$ +18,966 +$ +135,594 +$ +23,145 +State +income tax (net) +1,907 +13,744 +2,566 +Percentage +depletion +(624 +) +(545 +) +(771 +) +Domestic +production activities deduction +(374 +) +- +(399 +) +Other +1,106 +844 +135 +$ +20,981 +$ +149,637 +$ +24,676 +In order +to reduce current income taxes payable, we elected to expense, for income tax +purposes, a large amount of IDC in 2007, our domestic production activities +deduction, which in 2007 was statutorily equal to six percent of our qualified +production activity income (QPAI), was $1.1 million. In 2006, due to +our decision to expense $55 million of IDC, our domestic production deduction, +which in 2006 was statutorily equal to three percent of QPAI, was +zero. In addition, the amount in "Other" for 2007, was primarily +nondeductible tax penalties. +The +Internal Revenue Service ("IRS") examination of our federal tax returns for the +2003 and 2004 tax years was concluded on July 31, 2007. There was no +significant affect on 2007 tax expense from the conclusion of this examination +as most of the tax adjustments had been previously agreed to and accrued for at +December 31, 2006. We have received notice from the IRS that they +will be beginning the examination of our 2005 and 2006 returns in the near +future. +The tax +effects of temporary differences that give rise to significant portions of the +deferred tax assets and deferred tax liabilities at December 31, 2007 and 2006, +are presented below. +F-22 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +2007 +2006 +(in +thousands) +Deferred +tax assets: +Allowance +for doubtful accounts +$ +138 +$ +161 +Drilling +notes +31 +46 +Allowance +for lease impairment +912 +- +Litigation +allowance +578 +- +Deferred +revenue related to cash withheld for future plugging cost +1,011 +929 +Deferred +compensation +2,058 +2,105 +Asset +retirement obligations +7,782 +4,428 +Unrealized +loss - Derivatives +703 +- +Employee +benefits +456 +798 +Other +16 +- +Total +gross deferred tax assets +13,685 +8,467 +Less +valuation allowance +- +- +Deferred +tax assets +13,685 +8,467 +Deferred +tax liabilities: +Properties +and equipment, principally due to differences in depreciation and +amortization +(75,663 +) +(58,790 +) +Like +kind exchange - deferred gain +(69,836 +) +(63,783 +) +Unrealized +gains - derivatives +(55 +) +(1,203 +) +Total +gross deferred tax liabilities +(145,554 +) +(123,776 +) +Net +deferred tax liability +$ +(131,869 +) +$ +(115,309 +) +Classification +in the Consolidated Balance Sheets: +Net +current deferred tax assets* +$ +4,621 +$ +1,084 +Net +non-current deferred tax liability +(136,490 +) +(116,393 +) +Net +deferred tax liability +$ +(131,869 +) +$ +(115,309 +) +*included +in other current assets +As noted +above, deferred tax liabilities for properties and equipment increased in 2007 +and 2006 primarily as a result of our election to expense $44 million and $55 +million of IDC for income tax purposes. Deferred tax liabilities also +increased substantially in 2006 due to our utilization of the like-kind exchange +tax deferral for a portion of the taxable gain on the undeveloped land sale +( Note +16 ). In addition, approximately $9.8 million of the deferred +liability for properties and equipment is due to the Unioil +acquisition. +In +assessing whether a valuation allowance for the deferred tax assets should be +recorded, we consider whether it is more likely than not that some portion or +all of the deferred tax assets will not be realized. The ultimate +realization of deferred tax assets is dependent upon the generation of future +taxable income during the periods in which those temporary differences become +deductible. Based upon the level of historical taxable income and +projections for future taxable income over the periods in which the deferred tax +assets are deductible, we believe it is more likely than not that we will +realize the benefits of these deductible differences. The amount of +the deferred tax asset considered realizable, however, could be reduced in the +near term if estimates of future taxable income during the carryforward period +are reduced. +We +adopted the provisions of FIN No. 48 on January 1, 2007. As a result +of adoption, retained earnings decreased by $0.3 million, deferred income taxes +payable decreased by $0.9 million, current income taxes payable increased by +$0.2 million and the liability for unrecognized tax benefit increased by $1.0 +million. +F-23 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +The +following table sets forth a reconciliation of the total amounts of unrecognized +tax benefits for 2007: +(in +thousands) +Balance, +January 1, 2007 +$ +952 +Gross +increases for tax positions of prior years +819 +Gross +decrease for tax positions of prior years +(883 +) +Settlements +- +Lapses +of applicable statute of limitation +- +Unrecognized +tax benefits at Balance, December 31, 2007 +$ +888 +Interest +and penalties related to uncertain tax positions are recognized in income tax +expense. As of January 1, 2007, and December 31, 2007 we have +approximately $0.3 million and $0.1 million of accrued interest related to +uncertain tax positions, respectively. In addition, at December 31, +2007, $0.2 million of income tax penalties were accrued while no income tax +penalties were accrued at January 1, 2007. The total amount of +unrecognized tax benefits that would affect the effective tax rate, if +recognized, is $0.4 million as of December 31, 2007 and zero as of January 1, +2007. We expect the unrecognized tax benefit at December 31, 2007, to +decrease in the next twelve months because of the IRS examination of our 2005 +and 2006 tax years that will be conducted in 2008. It is currently +estimated that the decrease in our unrecognized tax benefits will be between +$0.4 million and $0.9 million primarily due to settlements. +The +statute of limitations for tax years 2003-2006 remains open for both federal and +state taxing jurisdictions for the tax years 2003-2006. However, due +to the recent July 31, 2007 completion date of the federal examination of our +2003 and 2004 tax years, we believe that certain tax positions related to these +tax years have been “effectively settled” for federal tax purposes. +Our +subsidiary, Unioil Inc., which was acquired on December 6, 2006, filed separate +tax returns for years prior to the acquisition date. Unioil’s +2003-2006 tax returns remain open to examination at December 31, +2007. Any unrecognized tax benefit associated with Unioil's tax +returns is included in the above table amount. +NOTE +7 - ASSET RETIREMENT OBLIGATIONS +Changes +in carrying amounts of the asset retirement obligations associated with our +working interest in oil and gas properties are as follows: +2007 +2006 +(in +thousands) +Balance +at beginning of year +$ +11,966 +$ +8,333 +Obligations +assumed with development activities and acquisitions +7,909 +1,264 +Obligations +discharged with disposed properties and asset retirements +(93 +) +(115 +) +Accretion +expense +999 +515 +Revisions +to estimated cash flows +- +1,969 +Balance +at end of year +$ +20,781 +$ +11,966 +If the +fair value of the estimated asset retirement obligation changes, an adjustment +is recorded to both the asset retirement obligation and the asset retirement +cost. Approximately $0.1 million of the asset retirement obligations +were classified as short-term and included in other accrued expenses as of +December 31, 2007 and 2006. +F-24 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +NOTE +8 - COMMITMENTS AND CONTINGENCIES +Drilling and Development +Agreements . We are a party to a pipeline expansion agreement +with an unrelated third party, which is also currently the purchaser of the +majority of our Wattenberg Field natural gas production. Pursuant to +the agreement, we have agreed to invest a minimum of $65 million to develop +specified acreage in the Wattenberg Field, during a three-year period ending +December 31, 2009. Such capital spending will include costs to drill +new wells and the cost to recomplete existing wells in this +area. Should we not meet the minimum commitment by December 31, 2009, +we will be required to pay liquidated damages of $2 million, prorated based on +our actual capital investment made to date. As of December 31, 2007, +our total capital expenditures pursuant to the agreement were $27.5 million, +resulting in a maximum potential obligation of $1.2 million. +In +connection with the sale of undeveloped leaseholds in July 2006, we were +obligated to either drill 16 wells on specifically identified acreage over the +next three years or pay liquidated damages of $1.6 million per undrilled well +for a total contingent obligation of $25.6 million, which was reflected as a +deferred gain on sale of leaseholds in our consolidated balance sheet at +December 31, 2006. On May 31, 2007, we entered into a letter +agreement amending the original purchase and sale agreement. The +letter agreement relieved us of the obligation, in its entirety, to either drill +16 wells or pay liquidated damages, resulting in the recognition of the +remaining $25.6 million deferred gain on sale of leaseholds in the quarter ended +June 30, 2007. +Pursuant +to the above letter agreement, we are obligated to drill six wells on +specifically identified acreage. These wells will be drilled on the +unaffiliated party's leasehold for its benefit and at its cost. In +addition, the unaffiliated party will return 160 acres of leasehold property +acquired from us pursuant to the purchase and sale agreement. As of +the date of this report, we have drilled the six wells and received the 160 +acres of leasehold property. +In +connection with the acquisition of oil and gas properties in October 2007, we +are obligated to drill 100 wells in the Appalachian Basin by January +2016. We will retain a majority interest in each well +drilled. For each well we fail to drill, we are obligated to pay to +the seller liquidated damages of $25,000 per undrilled well for a total +contingent obligation of $2.5 million or reassign to the seller the interest +acquired in the number of undrilled well locations. As of December +31, 2007, no wells had been drilled pursuant to this agreement. +Partnership Repurchase +Provision . Substantially all of our drilling programs contain +a repurchase provision where investing partners may request that we purchase +their partnership units at any time beginning with the third anniversary of the +first cash distribution. The provision provides that we are obligated +to purchase an aggregate of 10% of the initial subscriptions per calendar year +(at a minimum price of four times the most recent 12 months' cash +distributions), if repurchase is requested by investors, and subject to our +financial ability to do so. The maximum annual repurchase obligation +as of December 31, 2007, was approximately $6.7 million. We have +adequate liquidity to meet this obligation. During 2007 and 2006, we +paid $1.6 million and $0.8 million, respectively, under this provision for the +repurchase of partnership units. As of December 31, 2007, outstanding +repurchase offers to investing partners totaled $0.5 million, principally all of +which were consummated in 2008 prior to expiration. +Performance +Supplements . Our drilling programs formed from 1996 through +the second quarter of 2005 contain a performance supplement that provides for +changes in the distribution of partnership profits if certain levels of +performance are not met. The terms of this provision in the +partnership agreements are not a guarantee of a rate of return on an investment +in the partnership. Under those specific conditions, such changes can +result in our share of an affected partnership’s profits being reduced by up to +one half of the amount to which we otherwise would be entitled in the affected +period. In no event would we be obligated to assume a +disproportionate share of losses in such partnerships; should the partnerships +which contain this provision in the partnership agreements incur a loss, our +share of such losses would be unaffected by the terms of this +provision. In accordance with these provisions, our share of +partnership profits was reduced by an aggregate of $0.6 million, $1 million and +$0.7 million during 2007, 2006 and 2005, respectively. As of December +31, 2007 and 2006, based on production through December 31 of the corresponding +year, we had accrued $0.2 million and $0.4 million, respectively. +Partnership Casualty +Losses. As Managing General Partner of 33 partnerships, we +have liability for any potential casualty losses in excess of the partnership +assets and insurance. We believe the casualty insurance coverage that +we and our subcontractors carry is adequate to meet this potential +liability. +F-25 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Drilling Rig +Contracts. In order to secure the services for drilling rigs, +we made commitments to the drilling contractors, which call for a minimum +commitment of $12,500 daily for a specified amount of time if we cease to use +the drilling rigs, an event that is not anticipated to occur, and a maximum +commitment of $40,680 daily for a specified amount of time for daily use of the +drilling rigs. As of December 31, 2007, commitments for these two +separate contracts expire in August 2009 and July 2010. As +of December 31, 2007, we have an outstanding minimum commitment for $6.4 million +and an outstanding maximum commitment for $24.7 million. +Litigation . We are +involved in various legal proceedings that we consider normal to our +business. Although the results cannot be known with certainty, we +believe that we have properly accrued reserves and that the ultimate results of +such proceedings, will not have a material adverse effect on our financial +position or results of operations. +On May +29, 2007, Glen Droegemueller, individually and as representative plaintiff on +behalf of all others similarly situated, filed a class action complaint against +the Company in the District Court, Weld County, Colorado alleging that we +underpaid royalties on natural gas produced from wells operated by us in the +State of Colorado (the "Droegemueller Action"). The plaintiff seeks +declaratory relief and to recover an unspecified amount of compensation for +underpayment of royalties paid by us pursuant to leases. We removed +the case to Federal Court on June 28, 2007, and on July 10, 2007, we filed its +answer and affirmative defenses. A second similar Colorado class +action suit was filed against the Company in the U.S. District Court for the +District of Colorado on December 3, 2007, by Ted Amsbaugh et al. On +December 31, 2007, plaintiff in this second action filed a motion to consolidate +the case with the Droegemueller Action above. On January 28, 2008, +the Court granted plaintiff’s motion to consolidate the action with the +Droegemueller Action. On February 29, 2008, the court approved a 90 +day stay in proceedings while the parties pursue mediation of the +matter. Given the preliminary stage of this proceeding and the +inherent uncertainty in litigation, we are unable to predict the ultimate +outcome of this suit at this time. We believe that the ultimate +outcome of the proceedings will not have a material adverse effect on our +financial condition or results of operations. +Litigation +similar to the preceding actions has recently been commenced against several +other companies in other jurisdictions where we conduct +business. While our business model differs from that of the parties +involved in such other litigation, and although the Company has not been named +as a party in such other litigation, there can be no assurance that the Company +will not be named as a party to such other litigation in the +future. +Employment Agreements with Executive +Officers . We have employment agreements with our Chief +Executive Officer, Chief Financial Officer, Chief Accounting Officer and other +executive officers. The employment agreements provide for base annual +base salaries, eligibility for performance bonus compensation, and other various +benefits, including retirement and termination benefits. +In the +event of termination without cause or if an executive officer terminates +employment for good reason, the executive officer is entitled to receive a +payment in the amount of three times the sum of his highest base salary during +the previous two years of employment immediately preceding the termination date +and his highest bonus received during the same two year period. The +executive officer is also entitled to (i) vesting of any unvested equity +compensation, (ii) reimbursement for any unpaid expenses, (iii) retirement +benefits earned under the current and/or previous agreements, (iv) continued +coverage under our medical plan for up to 18 months, and (v) payment of any +earned and unpaid bonus amounts. In addition, the executive officer +is entitled to receive any benefits that he would have otherwise been entitle to +receive under our 401(k) and profit sharing plan, although those benefits are +not increased or accelerated. See Note 19 for a +discussion regarding the departure of our President for good +reason. +In the +event that an executive officer is terminated for just cause, we are required to +pay the executive officer his base salary through the termination date plus any +bonus (only for periods completed and accrued, but not paid), incentive, +deferred, retirement or other compensation, and to provide any other benefits, +which have been earned or become payable as of the termination date but which +have not yet been paid or provided. +In the +event that an executive officer voluntarily terminates his employment for other +than good reason, he is entitled to receive (i) his base salary, bonus and +incremental retirement payment prorated for the portion of the year that the +executive officer is employed, (ii) any incentive, deferred or other +compensation which has been earned or has become payable, but which has not yet +been paid under the schedule originally contemplated in the agreement under +which they were granted or in full without discount within 60 days of the +termination date at our discretion, (iii) any unpaid expense reimbursement upon +presentation by the executive officer of an accounting of such expenses in +accordance with our normal practices, and (iv) any other payments for benefits +earned under the employment agreement or our plans. +F-26 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Derivative +Contracts . We would be exposed to oil and natural gas price +fluctuations on underlying purchase and sale contracts should the counterparties +to our derivative instruments or the counterparties to our gas marketing +contracts not perform. Nonperformance is not +anticipated. There were no counterparty default losses in 2007, 2006 +or 2005. +NOTE +9 - COMMON STOCK +Stock-Based +Compensation Plans +As +approved by the shareholders in June 2004, we maintain a long-term equity +compensation plan for officers and certain key employees of (the "2004 +Plan"). In accordance with the plan, awards may be issued in the form +of stock options, stock appreciation rights, restricted stock or performance +shares. A total of 750,000 new shares of common stock have been +reserved for issuance. Awards pursuant to the plan vest over periods +set at the discretion of the Compensation Committee of our Board of Directors +(“Board”) and have a maximum exercisable period of ten years. As of +December 31, 2007, 468,984 common shares remain available for future +awards. +As +approved by the shareholders in June 2005, we also maintain a restricted stock +plan for non-employee directors. A total of 40,000 new shares of +common stock have been reserved for issuance under the plan. During +2007, 2006 and 2005, 12,710, 6,551 and 6,895 common shares, respectively, +were awarded in accordance with the plan. Compensation expense for +each of the years ended December 31, 2007, 2006 and 2005, related to these +restricted shares was $0.2 million, $0.1 million and $0.1 million, +respectively. As of December 31, 2007, 13,844 common shares remain +available for future awards. +In August +1999, the shareholders approved the 1999 Incentive Stock Option and +Non-Qualified Stock Option Plan. A total of 500,000 shares of our +common stock were reserved for issuance upon the exercise of stock +options. All shares authorized to be awarded pursuant to this plan +were awarded in years prior to 2002. At December 31, 2007, options +for 11,000 common shares remain outstanding and exercisable through 2011, at +which time the options will expire. +The +following table provides a summary of the effect of our stock based compensation +plans on the results of operations for the periods presented. Prior +to the adoption of SFAS No. 123R, we did not recognize stock based compensation +expense in our financial statements. +Year +Ended December 31, +2007 +2006 +(in +thousands) +Total +stock based compensation expense +$ +2,286 +$ +1,516 +Income +tax benefit +(882 +) +(585 +) +Net +income impact +$ +1,404 +$ +931 +Stock Option +Awards. We granted stock options in previous years under +several stock compensation plans. Outstanding options expire ten +years from the date of grant and become exercisable ratably over a four year +period. We did not grant any stock option awards in 2007 or +2006. The fair values of stock options granted during the year ended +December 31, 2006, were estimated at the date of grant using a Black-Scholes +option-pricing model assuming no dividends and the following weighed average +assumptions: +2006 +Expected +volatility +40.4 +% +Expected +term (in years) +6.0 +Risk-free +interest rate +4.2 +% +Weighted-average +grant date fair +value per share +$ +20.30 +F-27 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Expected +volatilities are based on our historical volatility. The expected +life of an award is estimated using historical exercise behavior +data. The risk-free interest rate is based on the U.S. Treasury +yields in effect at the time of grant and extrapolated to approximate the +expected life of the award. We do not expect to pay dividends, nor do +we expect to declare dividends in the foreseeable future. +The +following table provides a summary of our stock option award activity for the +year ended December 31, 2007: +Weighted +Weighted +Average +Number +of +Average +Remaining +Shares +Exercise +Contractual +Underlying +Price +Term +Options +Per +Share +(years) +Outstanding +at December 31, 2006 +89,567 +$ +21.36 +5.6 +Exercised +(38,000 +) +4.81 +Outstanding +at December 31, 2007 +51,567 +33.55 +6.4 +Vested +and expected to vest at December 31, 2007 +46,340 +32.51 +6.2 +Exercisable +at December 31, 2007 +29,582 +26.30 +5.1 +Year +Ended December 31, +(in +millions) +2007 +2006 +2005 +Total +intrinsic value of options exercised +$ +1.7 +$ +0.3 +$ +0.1 +Total +intrinsic value of options outstanding +1.3 +2.0 +1.6 +Total +intrinsic value of options exercisable +1.0 +1.9 +1.6 +The +intrinsic value of options exercised represents the amount by which the market +value of our stock at date of exercise exceeds the exercise price of the +option. The intrinsic values of the options outstanding and +exercisable represent the amount by which the closing market price of our common +stock at the last trading day of the year exceeds the exercise price of the +options. +Total +unrecognized compensation cost related to stock options granted under the 2004 +Plan was $0.2 million as of December 31, 2007. This cost is expected +to be recognized over a weighted average period of 2.2 years. +Restricted +Stock Awards +We began +issuing shares of restricted common stock to employees in 2004. Our +restricted stock awards have been awarded with vesting conditions that are +either time-based or market-based. +Time-Based +Awards . The fair value +of the time-based awards is amortized ratably over the requisite service period, +primarily over four years. +The +following table sets forth the changes in non-vested time-based awards for the +year ended December 31, 2007: +Shares +Weighted +Average Grant-Date Fair Value +Non-vested +at December 31, 2006 +131,730 +$ +39.87 +Granted +79,595 +48.09 +Vested +(37,341 +) +36.63 +Forfeited +(2,139 +) +40.07 +Non-vested +at December 31, 2007 +171,845 +$ +44.38 +F-28 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Year +Ended December 31, +(in +millions) +2007 +2006 +2005 +Total +intrinsic value of time-based awards vested +$ +2.2 +$ +0.8 +$ +0.2 +Total +intrinsic value of time-based awards non-vested +10.2 +5.7 +1.3 +The +intrinsic value above is based upon the closing market price of our common stock +on the last trading date of the year, $59.13. +The total +compensation cost related to non-vested time-based awards not yet recognized as +of December 31, 2007, is $5.3 million. This cost is expected to be +recognized over a weighted-average period of 2.7 years. +Market-Based +Awards . The fair value of the market-based awards is amortized +ratably over the requisite service period, primarily over three years for +market-based awards. The market-based shares vest only upon the +achievement of certain per share price thresholds and continuous employment +during the vesting period. All compensation cost related to the +market based-awards will be recognized if the requisite service period is +fulfilled, even if the market condition is not achieved. +The +weighted average grant date fair value of each market-based share was computed +using the Monte Carlo pricing model and the following weighted average +assumptions: +Expected +term of award +3 +years +Risk-free +interest rate +4.7 +% +Volatility +44.0 +% +The +following table sets forth the changes in non-vested marked-based awards for the +year ended December 31, 2007: +Shares +Weighted +Average Grant-Date Fair Value +Non-vested +at December 31, 2006 +- +$ +- +Granted +31,972 +36.07 +Vested +- +- +Forfeited +- +- +Non-vested +at December 31, 2007 +31,972 +$ +36.07 +The +intrinsic value of market-based awards outstanding at December 31, 2007, was +$1.9 million, based upon the closing market price of our common stock on the +last trading date of the year, $59.13. +The total +compensation cost related to non-vested market-based awards not yet recognized +as of December 31, 2007, is $0.4 million. This cost is expected to be +recognized over a weighted-average period of 2 years. +Treasury +Share Purchases +In +January 2006, we announced that our Board authorized the purchase of up to 10% +(1,627,500 shares) of our common stock during 2006. Stock purchases +under this program were made in the open market or in private transactions, at +times and in amounts that we deemed appropriate. In October 2006, we +completed our January 2006 program. Total shares purchased pursuant +to the program were 1,627,500 common shares at a cost of $66.3 million ($40.75 +average price paid per share), including 100,000 shares from one of our +executive officers at a cost of $4.1 million ($40.66 price paid per +share). All shares purchased in accordance with the program have +subsequently been retired. +F-29 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +On +October 16, 2006, our board of directors of approved a second 2006 purchase +program authorizing us to purchase up to 10% (1,477,109 shares) of our then +outstanding common stock through April 2008. Stock purchases under +this program may be made in the open market or in private transactions, at times +and in amounts that we deem appropriate. Shares are generally +purchased at fair market value based on the closing price on the date of +purchase. Total shares purchased in 2007 pursuant to the program were +12,020 common shares at a cost of $0.6 million ($53.78 average price paid per +share), including 5,187 shares from our executive officers at a cost of $0.3 +million ($57.93 price paid per share). Shares purchased pursuant to +the plan were primarily to satisfy the statutory minimum tax withholding +requirement for restricted stock that vested in 2007. All shares were +subsequently retired. +Pursuant to our senior notes indenture entered on February 8, +2008, any future purchases are limited, see Note 19, Subsequent Events , to our accompanying +consolidated financial statements. +On +February 25, 2008, pursuant to a separation agreement, we purchased 50,000 +shares of our common stock from one of our executive officers at a cost of $3.4 +million, or $67.92 per share. See Note 19 , Subsequent Events , to our +consolidated financial statements +NOTE 10 - SHAREHOLDERS' RIGHTS +AGREEMENT +On +September 11, 2007, we entered into a rights agreement, with Transfer Online, +Inc., as rights agent. The rights agreement is designed to improve +the ability of our board of directors to protect the interest of our +shareholders in the event of an unsolicited takeover attempt. Our +board declared a dividend of one right for each outstanding share of our common +stock. The right dividend was paid to shareholders of record on +September 14, 2007. A "distribution date," as defined in the rights +agreement, can occur after any individual shareholder exceeds 15% ownership of +our outstanding common stock. After the occurrence of a "distribution +date," the right entitles each registered holder (other than the acquiring +shareholder who triggered the "distribution date"), to purchase shares of our +common stock (or, in certain circumstances, cash, property or other securities) +having a then-current value equal to two times the exercise price of the right +(i.e., for the $240 exercise price, the rights holder receives $480 worth of +common stock). The exercise price is subject to adjustment for +various corporate actions which affect all shareholders, such as a stock +split. The rights agreement and all rights will expire on September +11, 2017. +NOTE +11 - EMPLOYEE BENEFIT PLANS +We +sponsor a qualified deferred compensation plan covering substantially all of our +employees. The plan consists of a 401(k) retirement plan with a +profit sharing component. The plan enables eligible employees to +contribute a portion of their compensation through payroll deductions in +accordance with specific guidelines. We provide a discretionary +matching contribution based on a percentage of the employees' contributions up +to certain limits. Our contribution to the profit sharing component +is discretionary. Our total combined expense for to both 401(k) and +profit sharing in 2007, 2006 and 2005, were $1.4 million, $3.1 million and $0.9 +million, respectively. +We +provide a supplemental retirement benefit of deferred compensation under terms +of the various employment agreements with certain executive +officers. During 2007, 2006 and 2005, we charged $0.4 million, $0.3 +million and $0.2 million related to this plan to general and administrative +expenses, respectively, and we have recorded a related liability in the amount +$2.2 million and $1.9 million as of December 31, 2007 and 2006, +respectively. +In +addition to the supplemental retirement benefit of deferred compensation, we +offer a supplemental healthcare benefit covering certain executive officers and +their spouses in accordance with each officer's employment +agreement. Expense incurred during 2007 related to this plan was +immaterial. As of December 31, 2007, we had a recorded liability of +$0.6 million. +We +maintain a non-qualified deferred compensation plan for our non-employee +directors. The amount of compensation deferred by each participant is +based on participant elections. The amounts deferred pursuant to the +plan are invested in our common stock, maintained in a rabbi trust and are +classified in the accompanying balance sheet as treasury shares as a component +of shareholders' equity. The plan may be settled in either cash or +shares as requested by the participant. As of December 31, 2007, we +had recorded a long-term liability of $0.3 million, which is included in other +liabilities in our consolidated balance sheet. +F-30 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +NOTE +12 - EARNINGS PER SHARE +The +following is a reconciliation of the numerators and denominators used in the +calculation of basic and diluted earnings per share for the years ended December +31: +2007 +2006 +2005 +(in +thousands, except per share data) +Weighted +average common shares outstanding +14,744 +15,660 +16,362 +Dilutive +effect of share-based compensation: (1) +Unamortized +portion of restricted stock +44 +22 +13 +Stock +options +48 +55 +52 +Non +employee director deferred compensation +5 +4 +- +Weighted +average common and common equivalent shares outstanding +14,841 +15,741 +16,427 +Net +income +$ +33,209 +$ +237,772 +$ +41,452 +Basic +earnings per common share +$ +2.25 +$ +15.18 +$ +2.53 +Diluted +earnings per common share +$ +2.24 +$ +15.11 +$ +2.52 +(1) Excludes the effect of average +anti-dilutive common share equivalents related to out-of-the-money options and +unvested restricted shares of zero and 18,004 in 2007, 23,687 and zero in 2006 +and 16,880 and zero in 2005, respectively. +NOTE +13 - TRANSACTIONS WITH AFFILIATES +Funds +held for future distribution on our consolidated balance sheets represent +amounts owed to affiliated partnerships for production proceeds received by us +on their behalf and undistributed as of December 31, 2007 and 2006. +Amounts +due from/to the affiliated partnership are primarily related to derivative +positions, unbilled well lease operating expenses, and costs resulting from +audit and tax preparation services. +Our +natural gas marketing segment manages the marketing of oil and natural gas for +our affiliated partnerships in the Appalachian Basin. Our sales from +of natural gas marketing activities includes $9.3 million, $17.6 million and +$22.2 million in 2007, 2006 and 2005, respectively, related to the marketing of +oil and natural gas on behalf of our affiliated +partnerships. Included in our cost of natural gas marketing +activities is $9.1 million, $17.3 million and $22.2 million for 2007, 2006 and +2005, respectively, related to these sales . +We +provided oil and gas well drilling services to our affiliated +partnerships. Pursuant to our cost-plus drilling arrangements and our +corresponding net presentation, we performed drilling services for our +affiliated partnerships totaling $68.4 million and $87 million in 2007 and 2006, +for which we recognized $11.4 million and $12.4 million in oil and gas well +drilling operations revenue, respectively. Pursuant to our +footage-based drilling arrangements and our corresponding gross presentation, in +2005, we billed our affiliated partnerships for drilling services and recognized +oil and gas well drilling operations revenue of $100 +million. Further, we provide well operations and pipeline services to +our affiliated partnerships. Substantially all of our revenue and +expenses related to oil and gas well drilling operations and revenues from well +operations and pipeline income are associated with services provided to our +affiliated partnerships. +Revenues +from oil and gas well drilling operations and costs of oil and gas well drilling +operations each include $0.1 million and $0.2 million during 2006 and 2005, +respectively, related to investments made by executive officers for working +interests in wells drilled during the respective years. Amounts +invested by the executive officers during 2007 were immaterial. +Management +fees collected from the affiliated partnerships amounted to $1.3 million in 2007 +and 2006 and $1.7 million in 2005, respectively, which are included in other +income on our consolidated statements of income. +Through +our wholly-owned subsidiary, PDC Securities Incorporated, we act as +Dealer-Manager of the drilling partnerships. PDC Securities receives +the applicable commissions and marketing allowances from the Escrow Agent of the +drilling program and distributes them to the soliciting broker/dealers who sell +the programs. The commissions and marketing allowances received by +PDC Securities are included in other income net of the commissions distributed +to the soliciting broker/dealer. The commissions and marketing +allowances retained by PDC Securities were $0.5 million, $0.6 million and $0.5 +million and those distributed to the soliciting broker/dealers amounted to $8.3 +million, $8.8 million and $11.4 million for the years ended December 31, 2007, +2006 and 2005, respectively. +F-31 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +NOTE +14 - LEASE OBLIGATIONS +We +have entered into operating leases principally for the leasing of natural gas +compressors, our Denver office space, and general office +equipment. The future minimum lease payments under these +non-cancelable operating leases as of December 31, 2007, are as +follows: +Year +(in +thousands) +2008 +$ +1,850 +2009 +1,131 +2010 +534 +2011 +430 +2012 +92 +Thereafter +- +$ +4,037 +Lease +operating expense for the years ended December 31, 2007, 2006 and 2005 was $1.5 +million, $0.4 million and $0.3 million, respectively. +NOTE +15 – DERIVATIVE FINANCIAL INSTRUMENTS +We +are exposed to the effect of market fluctuations in the prices of oil and +natural gas as they relate to our oil and natural gas sales and natural gas +marketing segments. Price risk represents the potential risk of loss +from adverse changes in the market price of oil and natural gas +commodities. We employ established policies and procedures to manage +the risks associated with these market fluctuations using commodity +derivatives. Our policy prohibits the use of oil and natural gas +derivative instruments for speculative purposes. +Validation +of a contract’s fair value is performed internally and while we use common +industry practices to develop our valuation techniques, changes in our pricing +methodologies or the underlying assumptions could result in significantly +different fair values. +Economic Hedging +Strategies . Our results of operations and operating cash flows +are affected by changes in market prices for oil and natural gas. To +mitigate a portion of the exposure to adverse market changes, we have entered +into various derivative instruments. As of December 31, 2007, our oil +and natural gas derivative instruments were comprised of futures, swaps and +collars. These instruments generally consist of New York Mercantile +Exchange ("NYMEX") -traded natural gas futures contracts and option contracts +for Appalachian and Michigan production, Panhandle-based contracts and +NYMEX-traded contracts for NECO production and Colorado Interstate Gas Index +("CIG") -based contracts for other Colorado production and NYMEX-based swaps for +our Colorado and North Dakota oil production. +· +For +swap instruments, we receive a fixed price for the hedged commodity and +pay a floating market price to the counterparty. The +fixed-price payment and the floating-price payment are netted, resulting +in a net amount due to or from the +counterparty. +· +Collars +contain a fixed floor price (put) and ceiling price (call). If +the market price exceeds the call strike price or falls below the fixed +put strike price, we receive the fixed price and pay the market +price. If the market price is between the call and the put +strike price, no payments are due from either +party. +We +purchase puts and set collars and swaps for our own and affiliate partnerships’ +production to protect against price declines in future periods while retaining +much of the benefits of price increases. RNG enters into fixed-price +physical purchase and sale agreements that are derivative +contracts. In order to offset these fixed-price physical derivatives, +we enter into financial derivative instruments that have the effect of locking +in the prices we will receive or pay for the same volumes and period, offsetting +the physical derivative. While these derivatives are structured to +reduce our exposure to changes in price associated with the derivative +commodity, they also limit the benefit we might otherwise have received from +price changes in the physical market. We believe our derivative +instruments continue to be highly effective in achieving the risk management +objectives for which they were intended. +F-32 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +The net +fair value of the commodity based derivatives was $(1.4) million of which $0.2 +million is included in other long term assets at December 31, +2007. The net fair value of the commodity based derivatives was $13.6 +million of which $1.1 million is included in other long term assets at December +31, 2006. We recognized in the statement of income unrealized losses +on commodity based derivatives of $4.6 million in 2007, unrealized gains of $7.6 +million in 2006, and unrealized losses of $3.2 million in 2005. +At +December 31, 2007 and 2006, we had the following open commodity based derivative +instruments designed as an economic hedge for a portion of our oil and natural +gas production for periods after December 2007: +Petroleum +Development Corporation +Open +Derivative Positions +(dollars +in thousands, except average price data) +Quantity +Weighted +Total +Gas-MMbtu +Average +Contract +Commodity +Type +Oil-Barrels +Price +Amount +Fair +Value +Total +Positions as of December 31, 2007 +Natural +Gas +Cash +Settled Option Sales +14,500,000 +$ +10.69 +$ +155,044 +$ +(293 +) +Natural +Gas +Cash +Settled Option Purchases +16,360,000 +5.76 +94,283 +3,366 +Oil +Cash +Settled Futures/Swaps Purchases +585,600 +84.20 +49,308 +(5,097 +) +$ +(2,024 +) +Positions +maturing in 12 months following December 31, 2007 +Natural +Gas +Cash +Settled Option Sales +14,500,000 +$ +10.69 +$ +155,044 +$ +(293 +) +Natural +Gas +Cash +Settled Option Purchases +16,360,000 +5.76 +94,283 +3,366 +Oil +Cash +Settled Futures/Swaps Purchases +585,600 +84.20 +49,308 +(5,097 +) +$ +(2,024 +) +The +maximum term for the derivative contracts listed above is 12 +months. +Total +Positions as of December 31, 2006 +Natural +Gas +Cash +Settled Option Sales +17,390,000 +$ +5.56 +$ +96,613 +$ +12,597 +Natural +Gas +Cash +Settled Option Purchases +2,155,000 +10.34 +22,287 +(14 +) +Oil +Cash +Settled Option Purchases +300,000 +50.00 +15,000 +155 +$ +12,738 +F-33 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Riley +Natural Gas +Open +Derivative Positions +(dollars +in thousands, except average price data) +Weighted +Total +Quantity +Average +Contract +Commodity +Type +Gas-MMbtu +Price +Amount +Fair +Value +Total +Positions as of December 31, 2007 +Natural +Gas +Cash +Settled Futures/Swaps Purchases +588,950 +$ +7.79 +$ +4,586 +$ +(246 +) +Natural +Gas +Cash +Settled Futures/Swaps Sales +2,085,400 +8.50 +17,722 +1,236 +Natural +Gas +Cash +Settled Basis Swap Purchases +397,500 +0.54 +214 +3 +Natural +Gas +Physical +Purchases +2,085,400 +8.51 +17,748 +(473 +) +Natural +Gas +Physical +Sales +518,951 +8.50 +4,409 +129 +$ +649 +Positions +maturing in 12 months following December 31, 2007 +Natural +Gas +Cash +Settled Futures/Swaps Purchases +588,950 +$ +7.79 +$ +4,586 +$ +(246 +) +Natural +Gas +Cash +Settled Futures/Swaps Sales +1,568,400 +8.54 +13,391 +1,318 +Natural +Gas +Cash +Settled Basis Swap Purchases +397,500 +0.54 +214 +3 +Natural +Gas +Physical +Purchases +1,568,400 +8.32 +13,044 +(655 +) +Natural +Gas +Physical +Sales +518,951 +8.50 +4,409 +129 +$ +549 +The +maximum term for the derivative contracts listed above is 48 +months. +Total +Positions as of December 31, 2006 +Natural +Gas +Cash +Settled Futures/Swaps Purchases +246,900 +$ +7.34 +$ +1,811 +$ +(304 +) +Natural +Gas +Cash +Settled Futures/Swaps Sales +1,952,150 +8.42 +16,444 +2,815 +Natural +Gas +Cash +Settled Basis Swap Purchases +90,000 +0.42 +38 +(12 +) +Natural +Gas +Cash +Settled Basis Swap Sales +20,000 +0.50 +10 +4 +Natural +Gas +Cash +Settled Option Purchases +220,000 +5.50 +1,210 +64 +Natural +Gas +Cash +Settled Option Sales +110,000 +10.10 +1,111 +(39 +) +Natural +Gas +Physical +Purchases +1,964,150 +8.27 +16,244 +(1,974 +) +Natural +Gas +Physical +Sales +114,974 +9.62 +1,106 +310 +Natural +Gas +Physical +Basis Purchases +20,000 +0.45 +9 +(3 +) +Natural +Gas +Physical +Basis Sales +90,000 +0.44 +39 +14 +$ +875 +In +addition to including the gross assets and liabilities related to our share of +oil and gas production, the above tables and our consolidated balance sheets +include the gross assets and liabilities related to derivative contracts we +entered into on behalf of the affiliate partnerships as the managing general +partner. Our consolidated balance sheets include the fair value of +derivatives and a corresponding net receivable from the partnerships of $1.5 +million at December 31, 2007, and a corresponding net payable to the +partnerships of $7.5 million as of December 31, 2006. +We are +required to maintain margin deposits with brokers for outstanding futures +contracts. As of December 31, 2007 and 2006, restricted cash in the +amount of $0.3 million and $0.5 million was on deposit. +F-34 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +The +following table identifies the fair value of commodity based derivatives as +classified in our consolidated balance sheets. +December +31, +December +31, +2007 +2006 +(in +thousands) +Classification +in the Condensed Consolidated Balance Sheets: +Fair +value of derivatives - current asset +$ +4,817 +$ +15,012 +Other +assets - long-term asset +193 +1,146 +5,010 +16,158 +Fair +value of derivatives - current liability +6,291 +2,545 +Other +liabilities - long-term liability +93 +- +6,384 +2,545 +Net +fair value of commodity based derivatives - (liability) +asset +$ +(1,374 +) +$ +13,613 +The +following changes in the fair value of commodity based derivatives are reflected +in our consolidated statements of income (in millions): +Twelve +Months Ended December 31, +2007 +2006 +2005 +Statement +of income line item +Realized +Unrealized +Realized +Unrealized +Realized +Unrealized +(in +thousands, gain/(loss)) +Oil +and gas price risk management gain (loss), net +(1) +$ +7,173 +$ +(4,417 +) +$ +1,895 +$ +7,252 +$ +(6,367 +) +$ +(3,001 +) +Sales +from natural gas marketing activities +(2) +3,870 +(1,736 +) +2,592 +12,291 +(5,643 +) +(8,472 +) +Cost +of natural gas marketing activities +(2) +(482 +) +1,511 +(1,908 +) +(11,923 +) +(1,266 +) +8,247 +__________ +(1) +Includes +realized and unrealized gains and losses on commodity based derivative +instruments related to PDC. +(2) +Includes +realized and unrealized gains and losses on commodity based derivatives +instruments related to RNG only. +Pursuant +to SFAS No. 133, at this time our derivatives do not qualify for designation as +cash flow hedges. Changes in the fair value of these non-qualifying +derivatives that occur prior to their maturity (i.e., temporary fluctuations in +value) are reported currently in our consolidated statements of operations as +unrealized gains (losses). Oil and gas price risk management gain +(loss), net includes realized and unrealized gains and losses on commodity based +derivatives related to our oil and gas sales. Gas sales from +marketing activities and cost of gas marketing activities includes realized and +unrealized gains and losses on commodity based derivatives related to the RNG +gas sales and gas purchases, respectively. +NOTE +16 - SALE OF OIL AND GAS PROPERTIES +Grand +Valley Field Properties +In July +2006, we sold to an unaffiliated company a portion of our undeveloped leasehold +located in Grand Valley Field, Garfield County, Colorado. The sale +encompassed 100% of the working interest in approximately 8,700 acres, including +approximately 6,400 acres of the Chevron leasehold and 2,300 acres of the +Puckett Land Company leasehold. We retained approximately 475 +undeveloped locations on 10 acre spacing on the Grand Valley Field leasehold in +addition to all of our producing properties in the field. The +proceeds from the sale were $353.6 million. We recorded a gain on +sale of leaseholds of $328 million and a deferred gain on sale of leaseholds of +$25.6 million. +Pursuant +to the purchase and sale agreement, we were obligated to either drill 16 wells +on specifically identified acreage over the next three years or pay liquidated +damages of $1.6 million per un-drilled well for a total contingent obligation of +$25.6 million, which was reflected as a deferred gain on sale of leaseholds on +the balance sheet as of December 31, 2006. In May 2007, we entered +into a letter agreement amending the original purchase and sale +agreement. The letter agreement relieved us of the obligation, in its +entirety, to either drill 16 wells or pay liquidated damages, resulting in the +recognition of the remaining $25.6 million deferred gain on sale of leaseholds +in the second quarter of 2007. Pursuant to the letter agreement, we +were obligated to drill six wells on specifically identified +acreage. As of December 31, 2007, we had drilled all six wells, which +were drilled on the unaffiliated party's leasehold for its benefit and at its +cost. +F-35 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +In +conjunction with the purchase and sale agreement described above, we entered +into a LKE agreement, in accordance with Section 1031 of the Internal Revenue +Code, with a “qualified intermediary.” Proceeds in the amount of $300 +million were transferred directly to the qualified intermediary to be held in +trust pursuant to the terms of the LKE agreement. We had until +mid-January 2007 to close any acquisition of suitable like-kind property, +allowing us to take advantage of the income tax deferral benefits of a LKE +transaction. +In +December 2007, we sold to the same unaffiliated party above a portion of our +North Dakota properties for approximately $34.7 million. The +properties, located in Dunn, Williams and McKenzie Counties, North Dakota, +include interests in five producing Bakken wells and approximately 72,000 net +undeveloped acres. The reduction in our production and proved +reserves as a result of this transaction is not material. We recorded +a gain on sale of leaseholds of $7.7 million in the fourth quarter of +2007. The proceeds from the sale were used to pay down +debt. Following the sale, we retain ownership in three producing +wells in Dunn County, ten producing wells in Burke County and approximately +60,000 acres of undeveloped leasehold in Burke County. +During +2005, we sold a portion of an undeveloped leasehold in the Grand Valley Field to +an unaffiliated entity. The proceeds of the sale were $6.2 million +and our carrying value of the property was zero. The gain of $6.2 +million was recognized in 2005 and is included in gain on sale of leaseholds in +our consolidated statement of income. +Appalachian +Basin Properties +Additionally, +in 2005, we completed the sale to an unaffiliated party of 111 Pennsylvania +wells we purchased in 1998. We received proceeds of $3.4 million and +recorded a gain of $1.5 million, which is included in gain on sale of leaseholds +in our consolidated statement of income. +NOTE +17 - BUSINESS SEGMENTS +Our +operating activities can be divided into four major segments: oil and gas well +drilling operations, natural gas marketing, oil and gas sales, and well +operations and pipeline income. We drill natural gas wells for +Company-sponsored drilling partnerships and retain an interest in each +well. A wholly-owned subsidiary, Riley Natural Gas, engages in the +marketing of natural gas to commercial and industrial end-users. We +own an interest in approximately 4,354 wells from which we sell our oil and gas +production from our working interests in the wells. We charge +Company-sponsored partnerships and other third parties competitive industry +rates for well operations and gas gathering. All material +inter-company accounts and transactions between segments have been +eliminated. Segment information for the years ended December 31, +2007, 2006 and 2005 is presented below. +Year +Ended December 31, +2007 +2006 +2005 +Revenues: +(in +thousands) +Oil +and gas sales (1) +$ +177,943 +$ +124,336 +$ +93,191 +Natural +gas marketing +103,624 +131,326 +121,114 +Oil +and gas well drilling operations +12,154 +17,917 +99,963 +Well +operations and pipeline income +9,342 +10,704 +8,760 +Unallocated +amounts +2,172 +2,220 +2,170 +Total +$ +305,235 +$ +286,503 +$ +325,198 +Segment +Income Before Income Taxes: +Oil +and gas sales (2) +$ +42,068 +$ +61,868 +$ +46,095 +Natural +gas marketing +3,822 +1,816 +1,737 +Oil +and gas well drilling operations +9,646 +5,300 +11,778 +Well +operations and pipeline income (3) +3,136 +2,823 +3,539 +Unallocated +amounts (4)(5) +(4,482 +) +315,602 +2,979 +Total +$ +54,190 +$ +387,409 +$ +66,128 +F-36 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +As +of December 31, +2007 +2006 +2005 +Segment +Assets: +Oil +& gas sales +$ +862,237 +$ +394,952 +$ +251,897 +Natural +gas marketing +40,269 +39,899 +56,518 +Oil +and gas well drilling operations +4,959 +87,746 +89,030 +Well +operations and pipeline income +26,156 +28,895 +31,407 +Unallocated +amounts (6) +116,858 +332,795 +15,509 +Total +$ +1,050,479 +$ +884,287 +$ +444,361 +Year +ended December 31, +Expenditures +for Segment Long-Lived Assets: +Oil +& gas sales +$ +226,801 +$ +133,401 +$ +92,907 +Natural +gas marketing +- +- +1 +Oil +and gas well drilling operations +- +- +- +Well +operations and pipeline income +6,715 +1,419 +3,949 +Unallocated +amounts +5,472 +12,125 +2,452 +Total +$ +238,988 +$ +146,945 +$ +99,309 +(1) +Includes +oil and gas price risk management gain (loss), +net. +(2) +Includes +$23.6, $8.1 and $11.1 million in exploration costs and $68.1, $31.3 and +$19.3 million in DD&A expense in 2007, 2006 and 2005, +respectively. +(3) +Includes +$1.2, $1.9 and $1.5 million in DD&A expense in 2007, 2006 and 2005, +respectively. +(4) +Includes +interest income for PDC operations, $0.8, $0.6 and $0.3 million in +interest income allocated to natural gas marketing in 2007, 2006 and 2005, +respectively, in addition to partnership management +fees. +(5) +Includes +$1.6, $0.5, and $0.3 million in DD&A expense in 2007, 2006 and 2005 +respectively. +(6) +The +December 31, 2006, amount was expended in early 2007 in LKE transactions; +the assets and liabilities of which have been included in the oil and gas +sales segment. +NOTE 18 – SUPPLEMENTAL CASH +FLOW +Year +Ended December 31, +2007 +2006 +2005 +(in +thousands) +Cash +paid for: +Interest +$ +12,557 +$ +3,011 +$ +101 +Income +taxes +43,785 +46,735 +10,675 +Non-cash +investing activities: +Change +in deferred tax liability resulting from reallocation of acquisition +purchase price +4,188 +- +- +Changes +in accounts payable - affiliates related to acquisition of +partnerships +668 +- +- +Changes +in accounts payable related to purchases of properties and +equipment +32,820 +1,800 +- +Changes +related to investment in drilling partnership +18,712 +(7,151 +) +(7,160 +) +Asset +retirement obligation, with a corresponding increase to oil and gas +properties, net of disposals +7,850 +3,164 +(3 +) +NOTE +19 – SUBSEQUENT EVENTS +Issuance +and Sale of Senior Notes +On +February 8, 2008, we completed the issuance and sale of $203 million aggregate +principal amount of 12% senior notes due 2018. The senior notes were +offered and sold in private transactions pursuant to Rule 144A and Regulation S +under the Securities Act of 1933, as amended. The offer and sale of +the senior notes were not registered under the Securities Act. +The +senior notes accrue interest from February 8, 2008, at a rate of 12% per year +and interest is payable semi-annually in arrears on February 15 and August 15 of +each year, commencing on August 15, 2008. The notes are senior +unsecured obligations and rank, in right of payment, equally with all of our +existing and future senior unsecured indebtedness and senior to any of our +existing and future subordinated indebtedness. The notes are +effectively subordinated to any of our existing or future secured indebtedness +to the extent of the assets securing such indebtedness. +F-37 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +We may, +at our option, redeem all or part of the notes, at any time prior to February +15, 2013, at a make-whole price, and on or after February 15, 2013, at fixed +redemption prices, plus accrued and unpaid interest, if any, to the date of +redemption. +At any +time, which may be more than once, before February 15, 2011, we may redeem up to +35% of the outstanding notes with proceeds from one or more equity offerings at +a redemption price of 112% of the principal amount of the notes redeemed, plus +accrued and unpaid interest, as long as: +· +at +least 65% of the aggregate principal amount of the notes issued on +February 8, 2008, remains outstanding after each such redemption; +and +· +the +redemption occurs within 180 days after the closing of the equity +offering. +The +indenture governing the senior notes contains covenants that, among other +things, limit our ability and the ability of our restricted subsidiaries to +incur additional debt; make certain investments or pay dividends or +distributions on our capital stock or purchase or redeem or retire capital +stock; sell assets, including capital stock of our restricted subsidiaries; +restrict dividends or other payments by restricted subsidiaries; create liens +that secure debt; enter into transactions with affiliates; and merge or +consolidate with another company. +Additionally, +if we experience certain kinds of changes of control, we must give holders of +the notes the opportunity to sell to us their notes at 101% of their principal +amount, plus accrued and unpaid interest. +We used +the net proceeds from the sale of the senior notes to repay debt outstanding +under our revolving credit facility and for general corporate +purposes. +Registration +Rights Agreement +On +February 8, 2008, we entered into a registration rights agreement with the +initial purchasers named therein, pursuant to which we agreed to use our +commercially reasonable efforts to (i) file with the SEC a registration +statement on an appropriate form under the Securities Act relating to a +registered exchange offer for the notes described above under the Securities Act +and (ii) cause the exchange offer registration statement to be declared +effective under the Securities Act within 365 days following February 8, +2008. If we fail to comply with certain obligations under the +registration rights agreement, we will be required to pay liquidated damages to +the holders of our senior notes in accordance with the provisions of the +registration rights agreement. We do not believe it is probable that +we will be required to make such payments; therefore, have not recorded a +liability at this time. +Departure +of Executive Officer +On +February 8, 2008, we accepted the resignation for good reason of Thomas E. Riley +as our President and Director. In accordance with the provisions of +his employment agreement, Mr. Riley will receive a single lump sum cash payment +of $1,877,343 as separation compensation and retirement compensation equal to +$37,500 per year for ten years beginning January 1, +2009. Additionally, a separation agreement executed on February 8, +2008, provides for the of vesting 16,123 shares of restricted stock and stock +options to purchase 4,678 shares of our common stock. We will +recognize expense of approximately $3.2 million in the first quarter of 2008 in +connection with the resignation of Mr. Riley. +F-38 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +NOTE +20 – SUPPLEMENTAL OIL AND GAS INFORMATION - UNAUDITED +Costs +Incurred in Oil and Gas Property Acquisition, Exploration and Development +Activities (Unaudited) +We +incurred costs in oil and gas property acquisition, exploration and development +are presented below. +Year +Ended December 31, +2007 +2006 +2005 +(in +thousands) +Acquisition +of properties: +Proved +properties +$ +257,330 +$ +802 +$ +1,608 +Unproved +properties +13,701 +11,926 +16,910 +Development +costs +194,031 +114,487 +68,605 +Exploration +costs: +Exploratory +drilling +12,972 +18,660 +12,943 +Geological +and Geophysical +6,299 +2,234 +- +Total +costs incurred +$ +484,333 +$ +148,109 +$ +100,066 +The +proved reserves attributable to the development costs in the above table were +216,383 MMcf and 3,700 MBbls for 2007, 64,126 MMcf and 2,955 MBbls for +2006 and 76,669 MMcf and 1,576 MBbls for 2005. Of the above +development costs incurred for the years ended December 31, 2007, 2006 and 2005, +the amounts of $37.1 million, $20.1 million and $23.8 million, respectively, +were incurred to develop proved undeveloped properties from the prior year +end. +Property +acquisition costs include costs incurred to purchase, lease or otherwise acquire +a property. Development costs include costs incurred to gain access +to and prepare development well locations for drilling, to drill and equip +development wells, recompletions and to provide facilities to extract, treat, +gather and store oil and gas. Exploration costs include costs +incurred in identifying areas that may warrant examination and in examining +specific areas that are considered to have prospects of containing oil and gas +reserves. +Capitalized +Oil and Gas Costs (Unaudited) +Aggregate +capitalized costs for related to oil and gas exploration and production +activities with applicable accumulated depreciation, depletion and amortization +are presented below: +December +31, +2007 +2006 +(in +thousands) +Proved +oil and gas properties +$ +953,904 +$ +473,451 +Unproved +oil and gas properties +41,023 +27,055 +994,927 +500,506 +Less +accumulated depreciation, depletion and amortization +196,310 +133,172 +$ +798,617 +$ +367,334 +F-39 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Results +of Operations for Oil and Gas Producing Activities (Unaudited) +The +results of operations for oil and gas producing activities (excluding marketing) +are presented below. +Year +Ended December 31, +2007 +2006 +2005 +(in +thousands) +Revenue: +Oil +and gas sales +$ +175,187 +$ +115,189 +$ +102,559 +Oil +and gas price risk management gain (loss), net +2,756 +9,147 +(9,368 +) +177,943 +124,336 +93,191 +Expenses: +Production +costs +44,238 +20,855 +16,194 +Depreciation, +depletion and amortization +68,086 +30,988 +19,322 +Exploration +costs +23,551 +8,131 +11,115 +135,875 +59,974 +46,631 +Results +of operations for oil and gas producing activities before provision for +income taxes +42,068 +64,362 +46,560 +Provision +for income taxes +16,280 +24,818 +18,112 +Results +of operations for oil and gas producing activities (excluding corporate +overhead and interest costs) +$ +25,788 +$ +39,544 +$ +28,448 +Production +costs include those costs incurred to operate and maintain productive wells and +related equipment, including costs such as labor, repairs, maintenance, +materials, supplies, fuel consumed, insurance and production and severance +taxes. In addition, production costs include administrative expenses +and depreciation applicable to support equipment associated with these +activities. Depreciation, depletion and amortization expense includes those +costs associated with capitalized acquisition, exploration and development +costs, but does not include the depreciation applicable to support +equipment. The provision for income taxes is computed +using effective tax rates. +Net +Proved Oil and Gas Reserves (Unaudited) +Our +proved oil and natural gas reserves have been estimated by independent petroleum +engineers. Wright & Company prepared for us reserve reports +estimating our proved reserves at December 31, 2007 and 2006, in the Appalachian +and Michigan Basins. Ryder Scott Company, L.P. prepared for us +reserve reports estimating our proved reserves at December 31, 2007 and 2006, in +the Rocky Mountain Region. Wright & Company prepared reserve +reports for us estimating all of our reserves at December 31, 2005, with the +exception of our North Dakota wells, which were prepared by Ryder Scott Company, +L.P. These reserve estimates have been prepared in compliance with +professional standards and the reserves definitions prescribed by the +SEC. +Proved +reserves are the estimated quantities of oil and natural gas that geologic and +engineering data demonstrate with reasonable certainty to be recoverable in +future years from known reservoirs under existing economic and operating +conditions. Estimates of proved reserves may change, either +positively or negatively, as additional information becomes available and as +contractual, economic and political conditions change. The Company's +net proved reserve estimates have been adjusted as necessary to reflect all +contractual agreements, royalty obligations and interests owned by others at the +time of the estimate. +Proved +developed reserves are the quantities of oil and natural gas expected to be +recovered through existing wells with existing equipment and operating +methods. In some cases, proved undeveloped reserves may require +substantial new investments in additional wells and related +facilities. +F-40 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +An +analysis of the change in estimated quantities of oil and gas reserves, all of +which are located within the United States, is shown below. +Oil +(MBbl) +Gas +(MMcf) +Total +(MMcfe) +Proved +Reserves: +Proved +reserves, January 1, 2005 +3,316 +197,548 +217,444 +Revisions +of previous estimates +80 +(6,894 +) +(6,414 +) +Extensions, +discoveries and other additions +Rocky +Mountain Region +1,576 +76,669 +86,125 +Purchases +of reserves +Appalachian +basin +- +434 +434 +Michigan +Basin +- +47 +47 +Rocky +Mountain region +5 +71 +101 +Dispositions +to partnerships +- +(9,556 +) +(9,556 +) +Production +(439 +) +(11,031 +) +(13,665 +) +Proved +reserves, December 31, 2005 +4,538 +247,288 +274,516 +Revisions +of previous estimates +226 +(21,721 +) +(20,365 +) +Extensions, +discoveries and other additions +Michigan +Basin +- +225 +225 +Rocky +Mountain Region +2,955 +63,901 +81,631 +Purchases +of reserves +Appalachian +basin +- +222 +222 +Michigan +Basin +- +35 +35 +Rocky +Mountain region +276 +3,504 +5,160 +Dispositions +to partnerships +(92 +) +(1,215 +) +(1,767 +) +Production +(631 +) +(13,161 +) +(16,947 +) +Proved +reserves, December 31, 2006 +7,272 +279,078 +322,710 +Revisions +of previous estimates +1,375 +14,177 +22,427 +Extensions, +discoveries and other additions +Appalachian +Basin +- +5,493 +5,493 +Michigan +Basin +- +488 +488 +Rocky +Mountain Region +3,700 +210,402 +232,602 +Purchases +of reserves +Appalachian +basin +2 +63,014 +63,026 +Michigan +Basin +- +6,059 +6,059 +Rocky +Mountain region +4,490 +39,239 +66,179 +Dispositions +to partnerships +(591 +) +(1,874 +) +(5,420 +) +Production +(910 +) +(22,513 +) +(27,973 +) +Proved +reserves, December 31, 2007 +15,338 +593,563 +685,591 +Proved +Developed Reserves, As of: +January +1, 2005 +3,190 +146,152 +165,292 +December +31, 2005 +3,860 +155,354 +178,514 +December +31, 2006 +4,629 +158,978 +186,752 +December +31, 2007 +8,927 +314,123 +367,685 +2007 Activity . In +2007, we recorded an upward revision to our previous estimate of proved reserves +of approximately 22 Bcfe. The revision was primarily due to an +increase of approximately 25 Bcfe and 12 Bcfe, respectively, due to asset +performance and higher commodity prices, partially offset by a decrease of +approximately 15 Bcfe due primarily to increased operating costs, adjustments to +proved undeveloped reserve values and change in well ownership +interests. New discoveries and extensions of 239 Bcfe in 2007 are due +to the drilling of 218 net wells and the addition of new proved undeveloped +reserves. Approximately 233 Bcfe were added in the Rocky Mountain +Region, with 43 Bcfe in the Wattenberg Field, 170 Bcfe in Grand Valley Field and +19 Bcfe in the NECO area. We acquired approximately 135 Bcfe of +proved reserves through purchases of oil and natural gas +properties. In the Rocky Mountain Region approximately 66 Bcfe +of proved reserves were acquired in the Wattenberg Field, in the Appalachian +Basin approximately 75 Bcfe were acquired and approximately 6 Bcfe in the +Michigan Basin. We sold proved reserves of approximately 5 Bcfe to +unaffiliated third parties and to our sponsored partnerships for drilling +activity. +F-41 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +2006 Activity. In +2006 we recorded a downward revision to our previous estimate of proved reserves +of approximately 20 Bcfe. The revision was primarily due to a +decrease of 3 Bcfe due to asset performance and a decrease of 10 Bcfe due +to lower commodity prices and a decrease of approximately 7 Bcfe due to changes +in proved undeveloped reserve value, operating expense, and well ownership +interests. New discoveries and extensions in 2006 of approximately 82 +Bcfe were primarily due to the drilling of 91 net wells and adding new proved +undeveloped reserves in the Rocky Mountain Region. Approximately 34 +Bcfe were added in Wattenberg Field, 33 Bcfe in Grand Valley Field and 12 Bcfe +in the NECO area. We acquired approximately 5 Bcfe of proved reserves +through purchases of oil and natural gas properties in Wattenberg +Field. We sold proved reserves of approximately 2 Bcfe to our +sponsored partnerships. +2005 Activity. In +2005, we recorded a downward revision to our previous estimate of proved +reserves of approximately 6 Bcfe. The revision was primarily due to a +decrease of 15 Bcfe due to asset performance, partially offset by additions of 6 +Bcfe and 3 Bcfe, respectively, due to commodity price increases and proved +undeveloped values, operating expense changes and well ownership +interests. New discoveries and extensions in 2005 of approximately 86 +Bcfe were primarily due to the drilling of 65 net wells and additions of new +proved undeveloped reserves in the Rocky Mountain +Region. Approximately 11 Bcfe were added in Wattenberg Field, 44 Bcfe +were added in Grand Valley Field and 27 Bcfe were added in the NECO +area. We sold proved reserves of approximately 10 Bcfe to our +sponsored partnership. +Standardized +Measure of Discounted Future Net Cash Flows and Changes Therein Relating to +Proved Oil and Gas Reserves (Unaudited) +Summarized +in the following table is information with respect to the standardized measure +of discounted future net cash flows relating to proved oil and gas +reserves. Future cash inflows are computed by applying year-end +prices of oil and gas relating to our proved reserves to the year-end quantities +of those reserves. Future production, development, site restoration +and abandonment costs are derived based on current costs assuming continuation +of existing economic conditions. Future income tax expenses are +computed by applying the statutory rate in effect at the end of each year to the +future pretax net cash flows, less the tax basis of the properties and gives +effect to permanent differences, tax credits and allowances related to the +properties. +2007 +2006 +2005 +(in +thousands) +Future +estimated cash flows +$ +5,257,962 +$ +1,804,796 +$ +2,381,238 +Future +estimated production costs +(1,374,027 +) +(571,346 +) +(545,683 +) +Future +estimated development costs +(876,961 +) +(373,460 +) +(207,164 +) +Future +estimated income tax expense +(1,159,489 +) +(334,536 +) +(633,444 +) +Future +net cash flows +1,847,485 +525,454 +994,947 +10% +annual discount for estimated timing of cash flows +(1,094,414 +) +(309,792 +) +(589,517 +) +Standardized +measure of discounted future estimated net cash flows +$ +753,071 +$ +215,662 +$ +405,430 +The +following table summarizes the principal sources of change in the standardized +measure of discounted future estimated net cash flows. +2007 +2006 +2005 +(in +thousands) +Sales +of oil and gas production net of production costs +$ +(137,725 +) +$ +(94,337 +) +$ +(86,366 +) +Net +changes in prices and production costs +157,797 +(301,132 +) +188,836 +Extensions, +discoveries, and improved recovery, less related costs +317,031 +46,109 +150,654 +Sales +of reserves +(7,846 +) +(3,356 +) +(14,456 +) +Purchase +of reserves +342,792 +11,003 +1,266 +Development +costs incurred during the period +42,510 +20,051 +24,035 +Revisions +of previous quantity estimates +92,462 +(22,090 +) +4,917 +Changes +in estimated income taxes +(335,327 +) +120,818 +(112,054 +) +Accretion +of discount +38,660 +62,838 +38,241 +Timing +and other +27,055 +(29,672 +) +(19,071 +) +Total +$ +537,409 +$ +(189,768 +) +$ +176,002 +F-42 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +It is +necessary to emphasize that the data presented should not be viewed as +representing the expected cash flow from, or current value of, existing proved +reserves since the computations are based on a large number of estimates and +arbitrary assumptions. Reserve quantities cannot be measured with +precision and their estimation requires many judgmental determinations and +frequent revisions. The required projection of production and related +expenditures over time requires further estimates with respect to pipeline +availability, rates of demand and governmental control. Actual future +prices and costs are likely to be substantially different from the current +prices and costs utilized in the computation of reported amounts. Any +analysis or evaluation of the reported amounts should give specific recognition +to the computational methods utilized and the limitations inherent +therein. +The +estimated present value of future cash flows relating to proved reserves is +extremely sensitive to prices used at any measurement period. The +average December 31 price used for each commodity at December 31, 2007, 2006 and +2005 is presented below. +Average +Price +As +of December 31, +Oil +Gas +2007 +$ +80.67 +$ +6.77 +2006 +57.70 +4.96 +2005 +58.25 +8.56 +F-43 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +NOTE +21 - QUARTERLY FINANCIAL DATA (UNAUDITED) +Quarterly +financial data for the years ended December 31, 2007 and 2006, are presented +below The sum of the quarters may not equal the total of the +year's net income per share due to changes in the weighted average shares +outstanding throughout the year. +2007 +Quarter +First +Second +Third +Fourth +Year +(in +thousands, except per share data) +Revenues: +Oil +and gas sales +$ +34,016 +$ +39,246 +$ +44,437 +$ +57,488 +$ +175,187 +Sales +from natural gas marketing activities +21,987 +29,924 +19,934 +31,779 +103,624 +Oil +and gas well drilling operations +4,030 +1,739 +1,573 +4,812 +12,154 +Well +operations and pipeline income +3,298 +1,292 +2,092 +2,660 +9,342 +Oil +and gas price risk management (loss) gain, net +(5,645 +) +3,742 +6,345 +(1,686 +) +2,756 +Other +income +226 +2 +1,894 +50 +2,172 +Total +revenues +57,912 +75,945 +76,275 +95,103 +305,235 +Costs +and expenses: +Oil +and gas production costs and well operations costs +9,035 +11,628 +12,645 +15,956 +49,264 +Cost +of natural gas marketing activities +21,512 +28,780 +19,810 +30,482 +100,584 +Cost +of oil and gas well drilling operations +564 +246 +749 +949 +2,508 +Exploration +expense +2,678 +6,780 +5,337 +8,756 +23,551 +General +and administrative expense +7,424 +6,886 +7,513 +9,145 +30,968 +Depreciation, +depletion and amortization +13,074 +17,429 +20,354 +19,987 +70,844 +Total +costs and expenses +54,287 +71,749 +66,408 +85,275 +277,719 +Gain +on sale of leaseholds +- +25,600 +- +7,691 +33,291 +Income +from operations +3,625 +29,796 +9,867 +17,519 +60,807 +Interest +income +1,143 +454 +462 +603 +2,662 +Interest +expense +(831 +) +(1,450 +) +(2,544 +) +(4,454 +) +(9,279 +) +Income +before income taxes +3,937 +28,800 +7,785 +13,668 +54,190 +Income +taxes +1,436 +10,749 +3,326 +5,470 +20,981 +Net +income +$ +2,501 +$ +18,051 +$ +4,459 +$ +8,198 +$ +33,209 +Basic +earnings per common share +$ +0.17 +$ +1.22 +$ +0.30 +$ +0.56 +$ +2.25 +Diluted +earnings per common share +$ +0.17 +$ +1.21 +$ +0.30 +$ +0.55 +$ +2.24 +F-44 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +2006 +Quarter +First +Second +Third +Fourth +Year +(in +thousands, except per share data) +Revenues: +Oil +and gas sales +$ +28,332 +$ +27,992 +$ +30,577 +$ +28,288 +$ +115,189 +Sales +from natural gas marketing activities +41,942 +29,129 +30,374 +29,880 +131,325 +Oil +and gas well drilling operations +5,278 +3,745 +2,659 +6,235 +17,917 +Well +operations and pipeline income +2,290 +2,486 +2,536 +3,392 +10,704 +Oil +and gas price risk management gain, net +4,925 +1,370 +2,707 +145 +9,147 +Other +income +3 +21 +1,964 +233 +2,221 +Total +revenues +82,770 +64,743 +70,817 +68,173 +286,503 +Costs +and expenses: +Oil +and gas production and well operations costs +6,949 +6,830 +8,584 +6,658 +29,021 +Cost +of natural gas marketing activities +41,780 +28,471 +29,988 +29,911 +130,150 +Cost +of oil and gas well drilling operations +4,212 +3,278 +3,838 +1,289 +12,617 +Exploration +expense +1,208 +1,898 +2,180 +2,845 +8,131 +General +and administrative expense +3,719 +5,102 +5,357 +4,869 +19,047 +Depreciation, +depletion and amortization +6,587 +7,605 +8,300 +11,243 +33,735 +Total +costs and expenses +64,455 +53,184 +58,247 +56,815 +232,701 +Gain +on sale of leaseholds +- +- +328,000 +- +328,000 +Income +from operations +18,315 +11,559 +340,570 +11,358 +381,802 +Interest +income +392 +349 +3,475 +3,834 +8,050 +Interest +expense +(352 +) +(436 +) +(366 +) +(1,289 +) +(2,443 +) +Income +before income taxes +18,355 +11,472 +343,679 +13,903 +387,409 +Income +taxes +6,710 +4,192 +132,795 +5,940 +149,637 +Net +income +$ +11,645 +$ +7,280 +$ +210,884 +$ +7,963 +$ +237,772 +Basic +earnings per common share +$ +0.72 +$ +0.45 +$ +13.39 +$ +0.54 +$ +15.18 +Diluted +earnings per common share +$ +0.72 +$ +0.45 +$ +13.33 +$ +0.54 +$ +15.11 +F-45 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +Schedule +II -VALUATION AND QUALIFYING ACCOUNTS +Description +Beginning +Balance +January +1 +Charged +to +Costs +and Expenses +Deductions +Ending +Balance +December +31 +(in +thousands) +2007: +Allowance +for doubtful accounts +(a) +$ +415 +$ +50 +$ +108 +$ +357 +Valuation +allowance for unproved oil and gas properties +(b) +$ +596 +$ +2,183 +$ +414 +$ +2,365 +2006: +Allowance +for doubtful accounts +(a) +$ +409 +$ +7 +$ +1 +$ +415 +Valuation +allowance for unproved oil and gas properties +(b) +$ +33 +$ +653 +$ +90 +$ +596 +2005: +Allowance +for doubtful accounts +(a) +$ +409 +$ +- +$ +- +$ +409 +Valuation +allowance for unproved oil and gas properties +(b) +$ +- +$ +81 +$ +48 +$ +33 +(a) +Deductions represent the write-off of accounts receivable deemed +uncollectible. +(b) +Deductions represent amortization of expired or abandoned unproved oil +and gas properties. +F-46 \ No newline at end of file diff --git a/raw/filings/0000077877/2007/0001140361-08-007391/filing_metadata.csv b/raw/filings/0000077877/2007/0001140361-08-007391/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..41d73185dc2190c11c234476f87e7a8b6964ca56 --- /dev/null +++ b/raw/filings/0000077877/2007/0001140361-08-007391/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 +0000077877,PDCE,"PDC ENERGY, INC.",10-K,2008-03-20,2007-12-31,2008-03-20T21:09:45.000Z,0001140361-08-007391,form10k.htm,PETROLEUM DEVELOPMENT CORPORATION 10-K 12-31-2007,4585465,0,0,https://www.sec.gov/Archives/edgar/data/77877/000114036108007391/form10k.htm,https://www.sec.gov/Archives/edgar/data/77877/000114036108007391/,2007,2007,1 diff --git a/raw/filings/0000077877/2007/0001140361-08-007391/item1.txt b/raw/filings/0000077877/2007/0001140361-08-007391/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..f05bdab182c4cc5c434426936f83c68e4bbb2ada --- /dev/null +++ b/raw/filings/0000077877/2007/0001140361-08-007391/item1.txt @@ -0,0 +1,11074 @@ +Item 1 and in Note +1 , Summary of +Significant Accounting Policies , to our consolidated financial statements +included in this report. +Substantially +all of our oil and natural gas properties have been mortgaged or pledged as +security for our credit facility. See Note 5 , Long Term Debt , to our +consolidated financial statements included in this report. +26 +Table of Contents +Facilities +We own +our 32,000 square feet corporate office building located in Bridgeport, West +Virginia. In February 2008, we entered into an agreement to lease +approximately 17,000 square feet of office space in a building under +construction near the corporate office and purchased an approximate 12 acre, +undeveloped parcel of land adjacent to our existing corporate offices for +potential future expansion of the corporate office facility. We +maintain a lease for 13,000 square feet of administrative office space in +downtown Denver, Colorado through May 2012. +We own or +lease field operating facilities in the following locations: +· +West +Virginia: Bridgeport, Glenville and West +Union +· +Michigan: Ossineke +· +Colorado: Evans, +Parachute and Wray +· +Pennsylvania: Indiana +and Mahaffey +ITEM 3. LEGAL PROCEEDINGS +Information +regarding our legal proceedings can be found in Note 8 , Commitments and Contingencies – +Litigation , to our consolidated financial statements included in this +report. +ITEM 4 . SUBMISSION OF MATTERS TO A VOTE OF SECURITY +HOLDERS +None. +PART +II +ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY, +RELATED STOCKHOLDERS MATTERS AND ISSUER PURCHASES OF EQUITY +SECURITIES. +Our +authorized capital stock consists of 50,000,000 shares of common stock, par +value $0.01 per share. There were 14,851,234 shares of common stock +issued and outstanding as of March 14, 2008. Our common stock is +traded on the NASDAQ Global Select Market under the ticker symbol +PETD. +The +following table sets forth the range of high and low sales prices for our common +stock as reported on the NASDAQ Global Select Market for the periods indicated +below. +High +Low +2007 +First +Quarter +$ +55.20 +$ +40.53 +Second +Quarter +55.24 +44.59 +Third +Quarter +51.13 +35.73 +Fourth +Quarter +61.91 +41.65 +2006 +First +Quarter +46.17 +32.12 +Second +Quarter +45.62 +32.51 +Third +Quarter +45.23 +33.16 +Fourth +Quarter +47.44 +36.54 +As of +March 14, 2008, we had approximately 1,242 shareholders of record. +We +have not paid any dividends on our common stock and currently intend to retain +earnings for use in our business. Therefore, we do not expect to +declare cash dividends in the foreseeable future. +27 +Table of Contents +ISSUER +PURCHASES OF EQUITY SECURITIES +Period +Total +Number +of +Shares +Purchased +Average +Price +Paid per +Share +Total +Number of Shares +Purchased +as +Part of +Publicly +Announced +Plans +or +Programs +Maximum +Number +of Shares that +May +Yet Be +Purchased +Under the +Plans +or +Programs +Shares +purchased prior to October 1, 2007, under the current +repurchase program. +6,833 +$ +50.63 +6,833 +1,470,276 +Fourth +quarter purchases: +October +1 - 31, 2007 +- +- +- +- +November +1-30, 2007 +- +- +- +- +December +1-31, 2007 +5,187 +57.93 +5,187 +1,465,089 +Total +fourth quarter purchases +5,187 +5,187 +Total +shares purchased under the current program +12,020 +53.78 +12,020 +1,465,089 +On +October 16, 2006, our Board of Directors approved a second 2006 share purchase +program authorizing us to purchase up to 10% of our then outstanding common +stock (1,477,109 shares) through April 2008. Stock purchases under +this program may be made in the open market or in private transactions, at times +and in amounts that we deem appropriate. Shares are generally +purchased at fair market value based on the closing price on the date of +purchase. Total shares purchased in 2007 pursuant to the program were +12,020 common shares at a cost of $0.6 million ($53.78 average price paid per +share), including 5,187 shares from our executive officers at a cost of $0.3 +million ($57.93 price paid per share). Shares purchased pursuant to +the plan were primarily to satisfy the statutory minimum tax withholding +requirement for restricted stock that vested in 2007. All shares were +subsequently retired. +Pursuant to +our senior notes indenture entered on February 8, 2008, any future purchases are +limited, see Note 19, Subsequent Events , +to our accompanying consolidated financial statements. +On +February 25, 2008, pursuant to a separation agreement, we purchased 50,000 +shares of our common stock from one of our executive officers at a cost of $3.4 +million, or $67.92 per share. See Note 19 , Subsequent Events , to our +consolidated financial statements included in this report. +28 +Table of Contents +SHAREHOLDER +PERFORMANCE GRAPH +The +performance graph below compares the cumulative total return of our common stock +over a five year period ended December 31, 2007, with the cumulative total +returns for the same period for a Standard Industrial Code Index, or SIC, and +the Standard and Poor's, or S&P, 500 Index. The SIC Code Index is +a weighted composite of 154 crude petroleum and natural gas +companies. The cumulative total shareholder return assumes that $100 +was invested, including reinvestment of dividends, if any, in our common stock +on December 31, 2002, and in the S&P 500 Index and the SIC Code Index on the +same date. The results shown in the graph below are not necessarily +indicative of future performance. +Year +Ended December 31, +2002 +2003 +2004 +2005 +2006 +2007 +PETROLEUM +DEVELOPMENT CORPORATION +$ +100.00 +$ +447.17 +$ +727.74 +$ +629.06 +$ +812.26 +$ +1,115.66 +SIC +CODE INDEX +100.00 +160.61 +204.02 +293.12 +381.13 +535.76 +S&P +500 INDEX +100.00 +128.68 +142.69 +149.70 +173.34 +182.87 +29 +Table of Contents +ITEM 6. SELECTED FINANCIAL DATA +Year +Ended December 31, +2007 +2006 +2005 +2004 +2003 +(in +thousands, except per share data) +Revenues: +Oil +and gas sales +$ +175,187 +$ +115,189 +$ +102,559 +$ +69,492 +$ +48,394 +Sales +from natural gas marketing activities +103,624 +131,325 +121,104 +94,627 +73,132 +Oil +and gas well drilling operations (1) +12,154 +17,917 +99,963 +94,076 +57,510 +Well +operations and pipeline income +9,342 +10,704 +8,760 +7,677 +6,907 +Oil +and gas price risk management (loss) gain, net +2,756 +9,147 +(9,368 +) +(3,085 +) +(812 +) +Other +2,172 +2,221 +2,180 +1,696 +3,338 +Total +revenues +305,235 +286,503 +325,198 +264,483 +188,469 +Costs +and expenses: +Oil +and gas production and well operations costs +49,264 +29,021 +20,400 +17,713 +13,630 +Cost +of natural gas marketing activities +100,584 +130,150 +119,644 +92,881 +72,361 +Cost +of oil and gas well drilling operations (1) +2,508 +12,617 +88,185 +77,696 +46,946 +Exploration +expense +23,551 +8,131 +11,115 +- +- +General +and administrative expense +30,968 +19,047 +6,960 +4,506 +4,975 +Depreciation, +depletion and amortization +70,844 +33,735 +21,116 +18,156 +15,313 +Total +costs and expenses +277,719 +232,701 +267,420 +210,952 +153,225 +Gain +on sale of leaseholds (2) +33,291 +328,000 +7,669 +- +- +Income +from operations +60,807 +381,802 +65,447 +53,531 +35,244 +Interest +income +2,662 +8,050 +898 +185 +190 +Interest +expense +(9,279 +) +(2,443 +) +(217 +) +(238 +) +(816 +) +Income +before income taxes and cumulative effect of change in accounting +principle +54,190 +387,409 +66,128 +53,478 +34,618 +Provision +for income taxes +20,981 +149,637 +24,676 +20,250 +11,934 +Income +before cumulative effect of change in accounting principle +33,209 +237,772 +41,452 +33,228 +22,684 +Cumulative +effect of change in accounting principle (net of taxes of $1,392) (3) +- +- +- +- +(2,271 +) +Net +income +$ +33,209 +$ +237,772 +$ +41,452 +$ +33,228 +$ +20,413 +Basic +earnings per common share +$ +2.25 +$ +15.18 +$ +2.53 +$ +2.05 +$ +1.30 +Diluted +earnings per share +$ +2.24 +$ +15.11 +$ +2.52 +$ +2.00 +$ +1.25 +December +31, +2007 +2006 +2005 +2004 +2003 +Total +assets +$ +1,050,479 +$ +884,287 +$ +444,361 +$ +329,453 +$ +294,004 +Working +capital (deficit) +$ +(50,212 +) +$ +29,180 +$ +(16,763 +) +$ +231 +$ +7,287 +Long-term +debt +$ +235,000 +$ +117,000 +$ +24,000 +$ +21,000 +$ +53,000 +Shareholders' +equity +$ +395,526 +$ +360,144 +$ +188,265 +$ +154,021 +$ +112,559 +(1) +In +December 2005, we began entering into cost-plus drilling service +arrangements, which are recorded on a net basis unlike our footage based +arrangements which are recorded on a gross basis. See Note 1 , +"Summary of Significant Accounting Policies," to our consolidated +financial statements included in this +report. +(2) +In +July 2006, we sold a portion of our undeveloped leasehold located in Grand +Valley Field, Garfield County, Colorado. See Note 16 , "Sale +of Oil and Gas Properties," to our consolidated financial statements +included in this report. +(3) +Represents +the income effect of the adoption of SFAS No. 143, Accounting for Asset +Retirement Obligations. See Note 7 , "Asset +Retirement Obligation," to our consolidated financial statements included +in this report. +30 +Table of Contents +ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF +FINANCIAL CONDITION AND RESULTS OF OPERATIONS +The +following discussion and analysis, as well as other sections in this Form 10-K, +should be read in conjunction with our accompanying consolidated financial +statements and related notes to consolidated financial statements included in +this report. +Year Ended December 31, +2007, Compared to December 31, 2006 +Management +Overview +Net +Income +The +following table presents net income and diluted earnings per share for the year +ended December 31, 2007 and 2006. +Year +Ended December 31, +Change +2007 +2006 +Amount +Percent +(dollars +in thousands, except per share data) +Net +income +$ +33,209 +$ +237,772 +$ +(204,563 +) +-86.0 +% +Diluted +earnings per share +$ +2.24 +$ +15.11 +$ +(12.87 +) +-85.2 +% +Net +income for 2007, declined significantly due to last year's $328 million pretax +gain associated with the July 2006 sale of a leasehold to an unrelated party +(see Gain on +Sale of Leaseholds below). In 2007, we had two sales of +leaseholds, which totaled $33.3 million pretax. The positive driver +of net income in 2007 was the 65% increase in production, which contributed to +the $60 million increase in oil and gas sales despite lower average natural gas +prices. The increase in oil and gas sales was offset by increases in +depreciation, depletion and amortization, or DD&A , +expense, production and well operations cost, exploration expense and +general and administrative expense. Additionally, gains from oil and +gas price risk management, net, decreased $6.4 million from a $9.1 million gain +in 2006 to a $2.8 million gain in 2007, primarily due to increasing oil prices +at the end of 2007. +Revenues +Revenues +for the years ended December 31, 2007 and 2006, are presented +below. +Year +Ended December 31, +Change +2007 +2006 +Amount +Percent +(dollars +in thousands) +Revenues: +Oil +and gas sales +$ +175,187 +$ +115,189 +$ +59,998 +52.1 +% +Sales +from natural gas marketing activities +103,624 +131,325 +(27,701 +) +-21.1 +% +Oil +and gas well drilling operations +12,154 +17,917 +(5,763 +) +-32.2 +% +Well +operations and pipeline income +9,342 +10,704 +(1,362 +) +-12.7 +% +Oil +and gas price risk management gain, net +2,756 +9,147 +(6,391 +) +-69.9 +% +Other +2,172 +2,221 +(49 +) +-2.2 +% +Total +revenues +$ +305,235 +$ +286,503 +$ +18,732 +6.5 +% +Total +revenues for 2007 were up $18.7 million or 6.5% over 2006. The +increase was primarily due to a 52.1 % increase in oil and gas sales largely +offset by declines in natural gas marketing activities, oil and gas well +drilling operations and oil and gas price risk management gain, +net. +31 +Table of Contents +Oil and +natural gas sales increased $60 million as a result of the increase in +production of 65% although natural gas prices declined an average of 10% per +Mcf. Our natural gas marketing division enters into fixed-price +physical purchase and sale agreements that qualify as derivative +contracts. In order to offset these fixed-price physical derivatives, +we enter into financial derivative instruments that have the effect of locking +in the prices we will receive or pay for the same volumes and period, offsetting +the physical derivative. The decreases in both sales from natural gas +marketing activities and oil and gas price risk management, net, are a result of +a comparison of lower natural gas prices at December 31, 2006, compared with the +higher fourth quarter and year-end 2007 pricing. Lower well +operations and pipeline income is directly attributable to our January 2007 +acquisition of the outstanding partnership interests in 44 of our sponsored +drilling partnerships for which we no longer receive income for operating these +wells and related pipelines. +Costs +and Expenses +Costs and +expenses for the years ended December 31, 2007 and 2006, are presented +below. +Year +Ended December 31, +Change +2007 +2006 +Amount +Percent +(dollars +in thousands) +Costs +and expenses: +Oil +and gas production and well operations cost +$ +49,264 +$ +29,021 +$ +20,243 +69.8 +% +Cost +of natural gas marketing activities +100,584 +130,150 +(29,566 +) +-22.7 +% +Cost +of oil and gas well drilling operations +2,508 +12,617 +(10,109 +) +-80.1 +% +Exploration +expense +23,551 +8,131 +15,420 +189.6 +% +General +and administrative expense +30,968 +19,047 +11,921 +62.6 +% +Depreciation, +depletion and amortization +70,844 +33,735 +37,109 +110.0 +% +Total +costs and expenses +$ +277,719 +$ +232,701 +$ +45,018 +19.4 +% +The +increase in total costs and expenses for 2007 compared to 2006 was a reflection +of our growth over the past year, which was funded primarily by the reinvestment +of the proceeds from the 2006 sale of undeveloped leasehold of $353.6 million +into productive operating properties. Due to the acquisitions and the +significant number of new wells drilled for our own account and placed in +service during 2007, we have substantially increased production, resulting in +higher costs and expenses. +The +increases in oil and gas production and well operations cost and DD&A +expense for 2007 over 2006 reflects the growth we are currently experiencing +through acquisitions and increased drilling. The larger number of new +wells drilled and the increasing cost of well drilling, completion and equipping +of new wells, along with the higher market cost of our 2007 property +acquisitions, is reflected in the DD&A rate of our oil and gas properties, +which increase from $1.86 per Mcfe in 2006 to $2.37 per Mcfe in +2007. The increase in exploration expense in 2007 was due to the +liquidated damages from an exploration agreement and the subsequent lease +abandonment, expense related to eight exploratory dry holes, including one that +was pending determination at December 31, 2006, and increases in other +exploratory costs. The decrease in natural gas marketing costs +corresponds to the decline in sales from natural gas marketing activities as +referenced above. While general and administrative expense increased +$11.9 million from 2006 to 2007, general and administrative expense on a unit of +production basis remained relatively unchanged. +See the +following discussion of results of operations describing in more detail the +components of revenues and expenses and, where significant, providing an +analysis of changes year over year and the cause or underlying reason for such +change. +Results +of Operations +Revenues +Oil +and Gas Sales +The table +below sets forth revenues for oil and gas sales for the years ended December 31, +2007 and 2006, excluding the impact of commodity based derivative instruments, +which are included in oil and gas price risk management gain, net in the +statement of income. +32 +Table of Contents +Year +Ended December 31, +Change +2007 +2006 +Amount +Percent +(dollars +in thousands) +Oil +and gas sales +$ +175,187 +$ +115,189 +$ +59,998 +52.1 +% +The +increase in oil and gas sales in 2007 was primarily due to increased volumes of +oil and natural gas of 65%, partially offset by lower average sales prices of +natural gas. The increased volume of oil and natural gas contributed +$75 million to oil and gas sales, while the decline in natural gas prices +reduced oil and gas sales by $14 million in 2007 compared to +2006. The increase in natural gas and oil volumes was the result of +our increased investment in oil and gas properties, primarily the fourth quarter +2006 and first quarter 2007 acquisitions and the significantly increase in the +number of wells we drilled for our own account over the past +year. The oil and gas sales generated during 2007 from the +acquisitions made in 2007 and December 2006, and their subsequent development, +were $45.8 million. +Oil and Natural +Gas Production. Oil and natural gas production by area of +operation along with average sales price (excluding derivative gains/losses) for +the year is presented below. +2007 +2006 +Change +Oil +(Bbls) +Natural +Gas (Mcf) +Natural +Gas Equivalent (Mcfe) +Oil +(Bbls) +Natural +Gas (Mcf) +Natural +Gas Equivalent (Mcfe) +Oil +(Bbls) +Natural +Gas (Mcf) +Natural +Gas Equivalent (Mcfe) +Production +(Mcf) +Appalachian +Basin +5,490 +2,711,300 +2,744,240 +1,837 +1,451,729 +1,462,751 +199 +% +87 +% +88 +% +Michigan +Basin +4,301 +1,678,155 +1,703,961 +4,439 +1,399,852 +1,426,486 +-3 +% +20 +% +19 +% +Rocky +Mountain Region +900,261 +18,123,851 +23,525,417 +625,119 +10,309,203 +14,059,917 +44 +% +76 +% +67 +% +Total +910,052 +22,513,306 +27,973,618 +631,395 +13,160,784 +16,949,154 +44 +% +71 +% +65 +% +2007 +2006 +Change +(in +thousands, except average price) +(in +thousands, except average price) +Sales +Appalachian +Basin +$ +324 +$ +18,952 +$ +19,276 +$ +110 +$ +10,699 +$ +10,809 +194 +% +77 +% +78 +% +Michigan +Basin +294 +10,270 +10,564 +271 +9,141 +9,412 +8 +% +12 +% +12 +% +Rocky +Mountain Region +54,578 +90,769 +145,347 +37,079 +57,889 +94,968 +47 +% +57 +% +53 +% +Total +$ +55,196 +$ +119,991 +$ +175,187 +$ +37,460 +$ +77,729 +$ +115,189 +47 +% +54 +% +52 +% +Average +Sales Price +(Oil +- per Bbl, Natural Gas - per Mcf) +Appalachian +Basin +$ +59.08 +$ +6.99 +$ +7.02 +$ +60.14 +$ +7.37 +$ +7.39 +-2 +% +-5 +% +-5 +% +Michigan +Basin +68.31 +6.12 +6.20 +61.07 +6.53 +6.60 +12 +% +-6 +% +-6 +% +Rocky +Mountain Region +60.62 +5.01 +6.18 +59.31 +5.62 +6.75 +2 +% +-11 +% +-9 +% +Total +$ +60.65 +$ +5.33 +$ +6.26 +$ +59.33 +$ +5.91 +$ +6.80 +2 +% +-10 +% +-8 +% +The +production generated from the acquisitions made in 2007 and December 2006, and +their subsequent development, was 6.5 Bcfe. This represents +approximately 59% of the total 11.0 Bcfe increase in production in 2007 compared +to 2006. +Late in +the second quarter of 2007, we placed into service the upgraded Garden Gulch +pipeline and compressor facility, which serves a majority of our wells in the +Piceance Basin. This upgrade included two new natural gas +compressors, with a third compressor added in the third quarter, and pipeline +facility enhancements. The upgrade and enhancements have increased +the capacity of the pipeline delivery system from 17,000 Mcf per day to +60,000 Mcf per day from the wells feeding this facility from the time of our +start-up in late June 2007. +Oil and Natural +Gas Pricing . Financial results depend +upon many factors, particularly the price of natural gas and our ability to +market our production effectively. Natural gas and oil prices have +been among the most volatile of all commodity prices. These price +variations have a material impact on our financial results. Natural +gas and oil prices also vary by region and locality, depending upon the distance +to markets, and the supply and demand relationships in that region or +locality. This can be especially true in the Rocky Mountain +Region. The combination of increased drilling activity and the lack +of local markets could result in a local market oversupply situation from time +to time. Such a situation existed in the Rocky Mountain Region during +2007, with production exceeding the local market demand and pipeline capacity to +non-local markets. The result, beginning in the second quarter of +2007 and continuing into the fourth quarter of 2007, had been a decrease in the +price of Rocky Mountain natural gas compared to the NYMEX price and other +markets as shown in the graph below. The expansion in January 2008 of +the Rockies Express pipeline, or REX, is the primary reason for the narrowing of +the NYMEX/CIG gap in December 2007 and forward. Once the third phase +of the expansion of the Rockies Express is completed in 2009, the pipeline +capacity is expected to increase by 64% to 1.8 Bcf/per day of natural gas from +the region. Like most producers in the region, we rely on major +interstate pipeline companies to construct these facilities to increase pipeline +capacity, rendering the timing and availability of these facilities beyond our +control. +33 +Table of Contents +Rocky +Mountain Region Pricing . Although our +weighted average price for natural gas in 2007 was $5.33 per Mcf, the price we +receive for a large portion of the natural gas produced in the Rocky Mountain +Region is based on a market basket of prices, which may include some gas sold at +the Colorado Interstate Gas, or CIG, Index. The CIG Index, and other +indices for production delivered to other Rocky Mountain pipelines, has +historically been less than the price received for natural gas produced in the +eastern regions, which is New York Mercantile Exchange, or NYMEX, +based. The natural gas price in the eastern regions, where 19.5% of +our total natural gas production for the year was produced, was $6.67 per Mcf +compared to our Rocky Mountain Region price per Mcf of $5.01. The +Rocky Mountain Region contributed 80.5% of our natural gas for the year and is +where we anticipate a majority of our future production increases will +occur. During 2007, through our derivative activities, we realized a +benefit from the floors put in place on our production in the Rocky Mountain +Region. We received $7.2 million in proceeds (gross, excluding the +cost of floors) from our derivative instruments during 2007 or $0.40 per Mcf, +which helped to offset the lower prices we received for our Rocky Mountain +Region natural gas. We report our activities from derivative +transactions under the oil and gas price risk management, net line item in our +accompanying consolidated statements of income. +The graph +below identifies the actual NYMEX and CIG natural gas prices by month from +January 2006 through February 2008 and the forward curve for natural gas prices +through March 2009 as of February 15, 2008. The forecasted prices in +the graph have been derived from the sources indicated and represent, in our +opinion, a reasonable view of the possible movement of the CIG and NYMEX natural +gas prices over the next thirteen months. However, because the prices +given in the graph represent forecasts of future matters and are subject to +future events which we cannot predict, we can give no assurance that these +forecasted prices will be as they are presented in the graph. An +investor should therefore not rely on these forecasted prices in making an +investment decision regarding our stock. +___________ +*Source: Derived +from various sources including FutureSource, Inside FERC’s Gas Market Report and +ClearPort Trading. +While the +above graph shows a large differential between recent NYMEX and CIG pricing, the +gap began narrowing in November 2007 and has continued. As of +February 15, 2008, the price differential between NYMEX and CIG for 2008 has +narrowed to $(1.32) from $(3.38) average for the fourth +quarter. Although 80.5% of our 2007 natural gas production came from +the Rocky Mountain Region, the Rocky Mountain natural gas pricing is based upon +other indices in addition to CIG. +The +table below identifies the basis of our natural gas and oil pricing on a sales +volume basis for the year ended December 31, 2007. It further +outlines that 38% of our natural gas sales are derived from the CIG Index and +other similarly priced Rocky Mountain pipelines. In 2007, we realized +considerably higher prices associated with our non CIG volumes. +34 +Table of Contents +Energy +Market Exposure +as +of December 31, 2007 +Area +Pricing +Basis +Commodity +Percent +of Oil and Gas Sales +Grand +Valley/Wattenberg +Rocky +Mountain (CIG, et. al.) +Gas +38% +Colorado/North +Dakota +NYMEX +Oil +16% +NECO/Grand +Valley +Mid +Continent (Panhandle Eastern) +Gas +29% +Appalachian +NYMEX +Gas +10% +Michigan +Mich-Con/NYMEX +Gas +4% +Wattenberg +Colorado +Liquids +Gas +2% +Other +Other +Gas/Oil +1% +100% +Sales +from Natural Gas Marketing Activities +Revenues +from natural gas marketing activities for the years ended December 31, 2007 and +2006, are presented below. +Year +Ended December 31, +Change +2007 +2006 +Amount +Percent +(dollars +in thousands) +Sales +from natural gas marketing activities +$ +103,624 +$ +131,325 +$ +(27,701 +) +-21.1 +% +The +decrease in sales from natural gas marketing activities in 2007 was primarily +due to a decrease in prices and a decrease in volumes sold, along with a $14 +million decrease in unrealized gains on derivative transactions, from a $12.3 +million gain in 2007 to a $1.7 million loss in 2007. In 2007, prices +were 5% lower on average than in 2006, resulting in a $4.8 million decline in +sales, and volumes sold decreased by 9%, resulting in an additional $8.8 million +decline in sales. In January 2007, we acquired all of the outstanding +partnership interests in 44 of our sponsored drilling +partnerships. Since this acquisition, we no longer record oil and gas +sales for the net 423 wells acquired. In total, our natural gas +marketing segment's sales volumes increased by 4% in 2007; however, once the +intercompany volumes are eliminated, the net remaining sales from our natural +gas marketing segment declined. +Our +natural gas marketing segment is composed of our wholly owned subsidiary, +RNG. RNG is a natural gas marketing company that specializes in the +purchase, aggregation and sale of natural gas production in our Eastern +operating areas. RNG markets the natural gas we produce and also +purchases natural gas in the Appalachian Basin from other producers, including +our affiliated partnerships, and resells it to utilities, industrial and +commercial customers as well as other marketers. RNG has established +relationships with many of the natural gas producers in the Appalachian Basin +and has gained significant expertise in the natural gas end-user +market. RNG's sales to end-user customers utilize transportation +services provided by regulated interstate pipeline companies. RNG's +derivative activities are comprised of both physical and cash-settled +derivatives. RNG offers fixed-price derivative contracts for the +purchase or sale of physical gas. RNG also enters into cash-settled +derivative positions with counterparties in order to offset those same physical +positions. RNG does not take speculative positions on commodity +prices. +35 +Table of Contents +The +following table sets forth RNG's derivative positions in effect as of December +31, 2007. +Riley +Natural Gas +Open +Derivative Positions +(dollars +in thousands, except average price data) +Weighted +Total +Quantity +Average +Contract +Commodity +Type +Gas-MMbtu +Price +Amount +Fair +Value +Total +Positions as of December 31, 2007 +Natural +Gas +Cash +Settled Futures/Swaps Purchases +588,950 +$ +7.79 +$ +4,586 +$ +(246 +) +Natural +Gas +Cash +Settled Futures/Swaps Sales +2,085,400 +8.50 +17,722 +1,236 +Natural +Gas +Cash +Settled Basis Swap Purchases +397,500 +0.54 +214 +3 +Natural +Gas +Physical +Purchases +2,085,400 +8.51 +17,748 +(473 +) +Natural +Gas +Physical +Sales +518,951 +8.50 +4,409 +129 +$ +649 +Oil +and Gas Well Drilling Operations +Revenues +from drilling operations for the years ended December 31, 2007 and 2006, are +presented below. +Year +Ended December 31, +Change +2007 +2006 +Amount +Percent +(dollars +in thousands) +Oil +and gas well drilling operations +$ +12,154 +$ +17,917 +$ +(5,763 +) +-32.2 +% +The +decrease in oil and gas well drilling operations revenue was due to our change +from footage-based drilling arrangements to cost-plus drilling arrangements, +which are presented differently for accounting purposes. Beginning +with the last sponsored partnership in 2005 (for which revenue generating +activities began in 2006), our partnership wells have been drilled on a +"cost-plus" basis, which means that we charge the partnerships for the actual +cost of the wells plus an agreed upon mark-up above that cost. Prior +to that partnership, we had conducted most of our third-party drilling +activities on a footage basis, pursuant to which we drilled the wells for a +fixed price per foot drilled with additional chargeable items as provided for in +the drilling agreement. Our services provided under the cost-plus +drilling arrangements are reported net of recovered costs and reflected as +revenue in oil and gas well drilling operations, whereas the revenues under the +footage-based arrangements were recorded gross of related +expenses. For the year ended December 31, 2006, oil and gas well +drilling operations included $5.4 million in revenues related to footage based +arrangements. +Well +Operations and Pipeline Income +Revenues +from well operations and pipeline income for the years ended December 31, 2007 +and 2006 are presented below. +Year +Ended December 31, +Change +2007 +2006 +Amount +Percent +(dollars +in thousands) +Well +operations and pipeline income +$ +9,342 +$ +10,704 +$ +(1,362 +) +-12.7 +% +In +January 2007, we acquired all of the outstanding partnership interests in 44 of +our sponsored drilling partnerships. Having acquired 423 net wells +pursuant to the acquisition, we no longer record income for operating these +wells and related pipelines. This decrease in revenue was offset in +part by an increase in the number of new wells drilled and placed in service and +pipeline systems we operate for our sponsored drilling partnerships as well as +third parties. +36 +Table of Contents +Oil +and Gas Price Risk Management, Net +Oil and +gas price risk management, net for the years ended December 31, 2007 and 2006, +are presented below. +Year +Ended December 31, +Change +2007 +2006 +Amount +Percent +(dollars +in thousands) +Oil +and gas price risk management gain, net +$ +2,756 +$ +9,147 +$ +(6,391 +) +-69.9 +% +In 2007, +we recorded realized gains of $7.2 million and unrealized losses of $4.4 +million, resulting in a net $2.8 million gain for the year. In 2006, +we incurred realized and unrealized gains of $1.9 million and $7.2 million, +respectively, resulting in a $9.1 million gain. The significant +decline in the CIG market during the fall of 2007 resulted in the substantial +realized gains in 2007. When forward prices for oil and natural gas +prices increase, as they did at December 31, 2007, and for the additional +increases we are experiencing in 2008, our derivative portfolio, which includes +floors and swaps, decreases in value, resulting in unrealized loss +positions. +Oil and +gas price risk management, net is comprised of realized and unrealized changes +in the fair value of oil and natural gas derivatives related to our oil and +natural gas production. Oil and gas price risk management, net does +not include commodity based derivative transactions related to transactions from +marketing activities, which are included in sales from and cost of natural gas +marketing activities. +Oil and Natural +Gas Derivative Activities. Because of the +uncertainty surrounding natural gas and oil prices, we have used various +derivative instruments to manage some of the effect of fluctuations in +prices. Through December 2010, we have in place a series of floors +and ceilings, or “collars”, on a portion of the natural gas and oil +production. Under the arrangements, if the applicable index rises +above the ceiling price, we pay the counterparty; however, if the index drops +below the floor, the counterparty pays us. Through February 2011, we +have fixed price swaps in place on a small portion of our natural gas +production. During the three months ended December 31, 2007, our +average monthly natural gas and oil volumes sold were 2.3 Bcf and 81,100 +Bbls. +The +following table sets forth our derivative positions in effect as of December 31, +2007, and includes positions entered into subsequently through March 3, 2008, on +our share of production by area. The table does not include positions +related to RNG or derivative contracts we entered into on behalf of our +affiliated partnerships. +Floors +Ceilings +Swaps +(Fixed Prices) +Monthly +Quantity +Monthly +Monthly +Gas-MMbtu +Contract +Quantity +Contract +Volume +Oil-Bbls +Price +MMbtu +Price +MMbtu/Bbls +Price +Month +Set +Months +Covered +Colorado +Interstate Gas (CIG) Based Hedges (Grand Valley Field, Piceance +Basin) +Dec-06 +Jan +2008 – Mar 2008 +247,700 +$ +5.25 +- +$ +- +- +$ +- +Jan-07 +Jan +2008 – Mar 2008 +247,700 +5.25 +247,700 +9.80 +- +- +Feb-08 +April +2008 – Oct 2008 +- +- +- +- +488,900 +7.05 +Jan-08 +April +2008 – Oct 2008 +- +- +- +- +410,700 +6.54 +Jan-08 +Jan +2008 - Mar 2009 +371,600 +6.50 +371,600 +10.15 +- +- +Feb-08 +Jan +2008 - Mar 2009 +221,650 +7.00 +221,650 +9.70 +- +- +Feb-08 +Jan +2008 - Mar 2009 +- +- +- +- +221,650 +8.18 +Jan-08 +April +2009 - Oct 2009 +371,600 +5.75 +371,600 +8.75 +- +- +Mar-08 +April +2009 - Oct 2009 +365,050 +5.75 +365,050 +9.05 +- +- +NYMEX +Based Hedges - (Appalachian and Michigan Basins) +Dec-06 +Jan +2008 – Mar 2008 +123,100 +7.00 +- +- +- +- +Jan-07 +Jan +2008 – Mar 2008 +123,100 +7.00 +123,100 +13.70 +- +- +Feb-08 +April +2008 – Oct 2008 +- +- +- +- +123,100 +8.33 +Feb-08 +April +2008 – Oct 2008 +- +- +- +- +123,100 +8.58 +Jan-08 +Nov +2008 - Mar 2009 +123,100 +9.00 +123,100 +11.32 +- +- +Feb-08 +Nov +2008 - Mar 2009 +72,400 +8.40 +72,400 +13.05 +- +- +Feb-08 +Nov +2008 - Mar 2009 +- +- +- +- +72,400 +9.62 +Jan-08 +April +2009 - Oct 2009 +123,100 +6.75 +123,100 +12.45 +- +- +Mar-08 +April +2009 - Oct 2009 +123,100 +7.50 +123,100 +13.25 +- +- +Feb-08 +Mar +2008 - Feb 2011 +- +- +- +- +90,000 +8.62 +37 +Table of Contents +Floors +Ceilings +Swaps +(Fixed Prices) +Monthly +Quantity +Monthly +Monthly +Gas-MMbtu +Contract +Quantity +Contract +Volume +Oil-Bbls +Price +MMbtu +Price +MMbtu/Bbls +Price +Month +Set +Months +Covered +Panhandle +Based Hedges (NECO) +Dec-06 +Jan +2008 – Mar 2008 +70,000 +5.75 +- +- +- +- +Jan-07 +Jan +2008 – Mar 2008 +90,000 +6.00 +90,000 +11.25 +- +- +Feb-08 +April +2008 – Oct 2008 +- +- +- +- +180,000 +7.45 +Jan-08 +April +2008 – Oct 2008 +- +- +- +- +120,000 +6.80 +Jan-08 +Nov +2008 - Mar 2009 +110,000 +6.75 +110,000 +10.05 +- +- +Feb-08 +Nov +2008 - Mar 2009 +80,000 +7.25 +80,000 +10.05 +- +- +Feb-08 +Nov +2008 - Mar 2009 +- +- +- +- +80,000 +8.44 +Jan-08 +April +2009 - Oct 2009 +110,000 +6.00 +110,000 +9.70 +- +- +Mar-08 +April +2009 - Oct 2009 +130,000 +6.25 +130,000 +11.75 +- +- +Colorado +Interstate Gas (CIG) Based Hedges (Wattenberg) +Jan-07 +Jan +2008 – Mar 2008 +123,650 +5.25 +123,650 +9.80 +- +- +Feb-08 +April +2008 - Oct 2008 +- +- +- +- +314,750 +7.05 +Jan-08 +April +2008 - Oct 2008 +- +- +- +- +207,350 +6.54 +Jan-08 +Nov +2008 - Mar 2009 +237,350 +6.50 +237,350 +10.15 +- +- +Feb-08 +Nov +2008 - Mar 2009 +131,150 +7.00 +131,150 +9.70 +- +- +Feb-08 +Nov +2008 - Mar 2009 +- +- +- +- +131,150 +8.18 +Jan-08 +April +2009 - Oct 2009 +237,350 +5.75 +237,350 +8.75 +- +- +Mar-08 +April +2009 - Oct 2009 +214,850 +5.75 +214,850 +9.05 +- +- +Oil +– NYMEX Based (Wattenberg/North Dakota) +Oct-07 +Jan +2008 – Dec 2008 +- +- +- +- +25,900 +84.20 +Jan-08 +Jan +2009 - Dec 2009 +- +- +- +- +16,150 +84.90 +Jan-08 +Jan +2009 - Dec 2009 +- +- +- +- +16,150 +85.40 +Jan-08 +Jan +2010 - Dec 2010 +16,150 +70.00 +16,150 +102.25 +- +- +Jan-08 +Jan +2010 - Dec 2010 +16,150 +70.00 +16,150 +103.00 +- +- +We use +oil and natural gas commodity derivative instruments to manage price risk for +ourselves as well as our sponsored drilling partnerships. We set +these instruments for ourselves and the partnerships jointly by area of +operation. As volumes produced change, the mix between PDC and the +partnerships may change. The above table reflects such revisions +necessary to present our positions in effect as of March 3, 2008. +Costs +and Expenses +Oil +and Gas Production and Well Operations Costs +Oil and +gas production and well operations costs for the years ended December 31, 2007 +and 2006, are presented below. +Year +Ended December 31, +Change +2007 +2006 +Amount +Percent +(dollars +in thousands, except per Mcfe) +Oil +and gas production and well operations cost +$ +49,264 +$ +29,021 +$ +20,243 +69.8 +% +Per +Mcfe +$ +1.76 +$ +1.71 +$ +(0.05 +) +2.9 +% +The +increase in oil and gas production and well operations costs for the year was +primarily attributable to the 65% increase in production volumes and the +increased number of wells and pipeline systems we operate as a result of our +2007 and December 2006 acquisitions. Lifting costs per Mcfe increased +8.9% from $1.23 per Mcfe in 2006 to $1.34 per Mcfe in 2007. +In +addition to increased production, the increase in costs is also attributable to +increased production and engineering staff, increased maintenance and operating +cost of the new pipeline and compressor upgrades and improvements, increased +production enhancements and workovers associated +with the December 2006 and the first quarter 2007 acquisitions and general oil +field services inflation pressures. +38 +Table of Contents +Cost +of Natural Gas Marketing Activities +Cost of +natural gas marketing activities for the years ended December 31, 2007 and 2006, +are presented below. +Year +Ended December 31, +Change +2007 +2006 +Amount +Percent +(dollars +in thousands) +Cost +of natural gas marketing activities +$ +100,584 +$ +130,150 +$ +(29,566 +) +-22.7 +% +The +decrease in the costs of natural gas marketing activities in 2007 was primarily +due to a decrease in prices and in volumes purchased, along with a $13.4 million +decrease in unrealized losses on derivative transactions, from an $11.9 million +loss in 2006 to a $1.5 million gain in 2007. In 2007, prices declined +by 5% resulting in a $5.2 million decrease in costs and volumes purchased +decreased 8% resulting in an additional $8 million decrease in +costs. In January 2007, we acquired all of the outstanding +partnership interests in 44 of our sponsored drilling +partnerships. Since this acquisition, we no longer record the natural +gas purchases from the net 423 wells acquired . In total, the natural +gas marketing segment's purchased volumes increased by 5%; however, once the now +proportionately larger inter-company volumes are eliminated, the net remaining +purchases from the natural gas marketing segment declined. +Oil +and Gas Well Drilling Operations +Cost of +oil and gas well drilling operations for the years ended December 31, 2007 and +2006, are presented below. +Year +Ended December 31, +Change +2007 +2006 +Amount +Percent +(dollars +in thousands) +Cost +of oil and gas well drilling operations +$ +2,508 +$ +12,617 +$ +(10,109 +) +-80.1 +% +The +decrease in cost of oil and gas well drilling operations was due to our change +from footage-based drilling arrangements to cost-plus drilling arrangements, +which are presented differently for accounting purposes. Beginning +with the last sponsored partnership in 2005 (for which revenue generating +activities began in 2006), our partnership wells have been drilled on a +"cost-plus" basis, which means that we charge the partnerships for the actual +cost of the wells plus an agreed upon mark-up above that cost. Prior +to that partnership, we had conducted most of our third-party drilling +activities on a footage basis, pursuant to which we drilled the wells for a +fixed price per foot drilled with additional chargeable items as provided for in +the drilling agreement. Our services provided under the cost-plus +drilling arrangements are reported net of recovered costs and reflected as +revenue in oil and gas well drilling operations, whereas the revenues under the +footage-based arrangements were recorded gross of related +expenses. For the year ended December 31, 2006, oil and gas well +drilling operations included $10 million in expenses related to footage based +arrangements. We recorded a $2.1 million loss from footage-based +contracts during the year ended December 31, 2006. +Exploration +Expense +Exploration +expense for the years ended December 31, 2007 and 2006, are presented +below. +Year +Ended December 31, +Change +2007 +2006 +Amount +Percent +(dollars +in thousands) +Exploration +expense +$ +23,551 +$ +8,131 +$ +15,420 +189.6 +% +The +increase in exploration expense for 2007 is primarily due to an exploration +agreement with an unaffiliated party, which we abandoned and for which we +recorded charges for liquidated damages of $2.7 million and $1.1 million related +to the write-off of the carrying value of the related acreage, $4.2 million in +expense related to eight exploratory dry holes, including one which was pending +determination at December 31, 2007, compared to one in 2006, $5.5 million +geological and geophysical costs related to seismic evaluation of various +exploratory prospects, $2.2 million in unproved oil and gas properties +amortization, and increased payroll and payroll related costs and other +exploratory department costs. +39 +Table of Contents +General +and Administrative Expense +General +and administrative expense for the years ended December 31, 2007 and 2006, are +presented below. +Year +Ended December 31, +Change +2007 +2006 +Amount +Percent +(dollars +in thousands, except per Mcfe) +General +and administrative expense +$ +30,968 +$ +19,047 +$ +11,921 +62.6 +% +Per +Mcfe +$ +1.11 +$ +1.12 +$ +(0.01 +) +0.9 +% +The +increase in general and administrative expense for the year was primarily due to +increased costs related to higher payroll and employee benefits costs, including +stock-based compensation for the approximately one-third increase in employees +during 2007. The increase in management personnel is attributable to +the growth we are experiencing, the increase in the cost of recruiting and the +higher compensation required to obtain experienced oil and gas +personnel. +We have +also experienced higher financial statement audit costs related to the late +filing of our 2006 Form 10-K, higher compliance costs with the various +provisions of the Sarbanes-Oxley Act, increased accounting assistance from third +party consulting services and increased legal costs. Although general +and administrative expenses increased $11.9 million from 2006 to 2007, the rate +per Mcfe declined from $1.12 per Mcfe to $1.11 per Mcfe produced. +Depreciation, +Depletion and Amortization +DD&A +expense for the years ended December 31, 2007 and 2006, are presented +below. +Year +Ended December 31, +Change +2007 +2006 +Amount +Percent +(dollars +in thousands, except per Mcfe) +Depreciation, +depletion and amortization +$ +70,844 +$ +33,735 +$ +37,109 +110.0 +% +Per +Mcfe +2.53 +1.99 +0.54 +27.1 +% +The 65% +higher production volumes realized in 2007 resulted in a $20.7 million increase +in DD&A expense in 2007 compared to 2006. The remaining period to +period change is primarily related to the cost of acquisitions of proved mineral +interest and the addition of wells, related equipment and +facilities. These acquisitions have been made at current market +prices, which are higher than our historical cost of property and +reserves. The increasing cost of well drilling, completion and +equipping of new wells along with the higher current costs of the acquisitions +during 2007 is reflected in the DD&A rates for oil and +gas properties as shown in the table below for our significant areas of +operations. +Year +Ended December 31, +2007 +2006 +(per +Mcfe) +Appalachian +Basin +$ +1.32 +$ +1.13 +Michigan +Basin +1.28 +0.83 +Rocky +Mountain Region: +Wattenberg +Field +(1) +2.99 +2.34 +Piceance +Basin +2.27 +1.83 +NECO +1.45 +1.26 +__________ +(1) +This +field contains 89.1% of our oil +production. +The +weighted average DD&A rate for oil and gas properties increased to $2.37 per +Mcfe in 2007 from $1.87 per Mcfe in 2006. DD&A expense for +non-oil and gas properties, which are not included in the above table, increased +to $4.3 million in 2007 from $2 million in 2006. +40 +Table of Contents +The +DD&A rate for oil and gas properties declined from $2.50 per Mcfe from the +third quarter of 2007 to $2.12 per Mcfe in the fourth quarter of +2007. The major reason for the decline was the upward revision in our +new reserve report as of December 31, 2007, compared to 2006 primarily due to an +upward revision in production and higher commodity prices, partially offset by +increased operating costs. The average price for natural gas in the +reserve report was $6.77 per Mcf at December 31, 2007, compared to $4.96 per Mcf +at December 31, 2006, an increase of $1.81 per Mcf or 36.5%. The +average price for oil was $80.67 per barrel at December 31, 2007, compared to +$57.70 per barrel at December 31, 2006, an increase of $22.97 per barrel or +39.8%. +Gain +on Sale of Leaseholds +In July +2006, we entered into a purchase and sale agreement with an unaffiliated party +regarding the sale of our undeveloped leasehold located in the Grand Valley +Field, Garfield County, Colorado, as filed with the Securities and Exchange +Commission, or SEC, as Exhibit 10.3 to the Form 10-Q for the period ended +September 30, 2006. Total proceeds from the sale were $353.6 million, +of which we recognized a $328 million gain on sale of leasehold in the third +quarter of 2006. +In +May 2007, we entered into a letter agreement amending the above +mentioned purchase and sale agreement, relieving us of our obligation, in its +entirety, to either drill 16 wells or pay liquidated damages of $1.6 million per +undrilled well. As a result, we recognized the remaining deferred +gain of $25.6 million in the second quarter of 2007. +In +December 2007, we sold to the same unaffiliated party a portion of our North +Dakota properties for approximately $34.7 million. The properties, +located in Dunn, Williams and McKenzie Counties, North Dakota, include interests +in five producing Bakken wells and approximately 72,000 net undeveloped +acres. We recorded a gain on sale of leaseholds of $7.7 million in +the fourth quarter of 2007. +Non-operating +Income/Expense +Non-operating +income and expense for the years ended December 30, 2007 and 2006, are presented +below. +Year +Ended December 31, +Change +2007 +2006 +Amount +Percent +(dollars +in thousands) +Non-operating +income (expense): +Interest +income +$ +2,662 +$ +8,050 +$ +(5,388 +) +-66.9 +% +Interest +expense +$ +(9,279 +) +$ +(2,443 +) +$ +(6,836 +) +279.8 +% +The +decrease in interest income for the quarter is a result of lower cash balances +earning interest compared to the same period last year, primarily due to the +$353.6 million in cash proceeds from the sale of undeveloped leaseholds in July +2006. The proceeds were reinvested in oil and gas properties by +mid-January 2007. The increase in interest expense in 2007 was due to +significantly higher average outstanding balances of our credit facility, offset +by capitalized construction period interest of $3 million in 2007 compared to +$1.6 million in 2006. We utilize our daily cash balances to reduce +the line of credit, lowering the costs of interest. +Provision +for Income Taxes +The +effective income tax rate for the provision for income taxes for 2007, was +38.7%, relatively unchanged from 38.6% for 2006. The benefit we +received from the 2007 domestic production deduction was offset by +non-deductible income tax and production tax penalties that were expensed during +the year. +Year Ended December 31, +2006, Compared to December 31, 2005 +Management +Overview +Net +Income +Year +Ended December 31, +Change +2006 +2005 +Amount +Percent +(dollars +in thousands, except per share data) +Net +income +$ +237,772 +$ +41,452 +$ +196,320 +473.6 +% +Diluted +earnings per share +$ +15.11 +$ +2.52 +$ +12.59 +499.6 +% +41 +Table of Contents +Revenues +Revenues +for the years ended December 31, 2006 and 2005, are presented +below. +Year +Ended December 31, +Change +2006 +2005 +Amount +Percent +(dollars +in thousands) +Revenues: +Oil +and gas sales +$ +115,189 +$ +102,559 +$ +12,630 +12.3 +% +Sales +from natural gas marketing activities +131,325 +121,104 +10,221 +8.4 +% +Oil +and gas well drilling operations +17,917 +99,963 +(82,046 +) +-82.1 +% +Well +operations and pipeline income +10,704 +8,760 +1,944 +22.2 +% +Oil +and gas price risk management gain (loss) net +9,147 +(9,368 +) +18,515 +-197.6 +% +Other +2,221 +2,180 +41 +1.9 +% +Total +revenues +$ +286,503 +$ +325,198 +$ +(38,695 +) +-11.9 +% +The +decrease in revenues was primarily attributable to a decrease in drilling +revenues of $82.1 million partially offset by the increased oil and gas sales +from both gas marketing activities and our share of production for a total of +$22.9 million and the swing from a $9.4 million loss in oil and gas price risk +management for the year ended December 31, 2005, to a gain of $9.1 million for +the year ended December 31, 2006. See Drilling +Operations below for an explanation of the effect the new cost-plus +drilling arrangements and related accounting had on drilling revenues for the +year 2006. +Costs +and Expenses +Costs and +expenses for the years ended December 31, 2006 and 2005, are presented +below. +Year +Ended December 31, +Change +2006 +2005 +Amount +Percent +(dollars +in thousands) +Costs +and expenses: +Oil +and gas production and well operations cost +$ +29,021 +$ +20,400 +$ +8,621 +42.3 +% +Cost +of natural gas marketing activities +130,150 +119,644 +10,506 +8.8 +% +Cost +of oil and gas well drilling operations +12,617 +88,185 +(75,568 +) +-85.7 +% +Exploration +expense +8,131 +11,115 +(2,984 +) +-26.9 +% +General +and administrative expense +19,047 +6,960 +12,087 +173.7 +% +Depreciation, +depletion and amortization +33,735 +21,116 +12,619 +59.8 +% +Total +costs and expenses +$ +232,701 +$ +267,420 +$ +(34,719 +) +-13.0 +% +The +decrease in costs was primarily attributable to decreases in the cost of oil and +gas well drilling operations of $75.6 million and exploration cost of $3 million +offset in part by increases in the cost of gas marketing activities of $10.5 +million, oil and gas production and well operations costs of $8.6 million, +general and administrative expenses of $12.1 million and depreciation, depletion +and amortization of $12.6 million. See Drilling +Operations below for an explanation of the effect of the new cost plus +drilling arrangements and related accounting had on drilling expenses for the +year 2006. +Results +of Operations +Revenues +Oil +and Gas Sales +Revenues +for oil and gas sales for the years ended December 31, 2006 and 2005, are +presented below. +Year +Ended December 31, +Change +2006 +2005 +Amount +Percent +(dollars +in thousands) +Oil +and gas sales +$ +115,189 +$ +102,559 +$ +12,630 +12.3 +% +42 +Table of Contents +The +increase was due to a 24% increase in volumes sold at lower average sales prices +of natural gas and, in part, to higher average sales prices and higher volumes +sold of oil. The volume of natural gas sold for the year ended +December 31, 2006, was 13.2 Bcf at an average price of $5.91 per Mcf compared to +11.0 Bcf at an average sales price of $7.29 per Mcf for the year ended December +31, 2005. Oil sales for the year ended December 31, 2006, were +631,000 barrels at an average sales price of $59.33 per barrel compared to +439,000 barrels at an average sales price of $50.56 per barrel for the year +ended December 31, 2005. The increase in natural gas and oil volumes +was the result of our increased investment in oil and gas properties, primarily +the increase in net wells drilled for our own account, recompletions of existing +wells, and the investment in oil and gas properties we own in drilling program +partnerships. +Oil +and Gas Production +Our oil +and gas production by area of operations along with average sales price +(excluding derivative losses) is presented below: +Year +Ended December 31, +Change +2006 +2005 +Amount +Percent +Natural +Gas (Mcf) +Appalachian +Basin +1,451,729 +1,631,552 +(179,823 +) +-11.0 +% +Michigan +Basin +1,399,852 +1,555,958 +(156,106 +) +-10.0 +% +Rocky +Mountains +10,309,203 +7,843,250 +2,465,953 +31.4 +% +Total +13,160,784 +11,030,760 +2,130,024 +19.3 +% +Average +Sales Price +$ +5.91 +$ +7.29 +$ +(1.38 +) +-18.9 +% +Oil +(Bbls) +Appalachian +Basin +1,837 +3,973 +(2,136 +) +-53.8 +% +Michigan +Basin +4,439 +4,732 +(293 +) +-6.2 +% +Rocky +Mountains +625,119 +430,266 +194,853 +45.3 +% +Total +631,395 +438,971 +192,424 +43.8 +% +Average +Sales Price +$ +59.33 +$ +50.56 +$ +8.77 +17.3 +% +Natural +Gas Equivalents (Mcfe)* +Appalachian +Basin +1,462,751 +1,655,390 +(192,639 +) +-11.6 +% +Michigan +Basin +1,426,486 +1,584,350 +(157,864 +) +-10.0 +% +Rocky +Mountains +14,059,917 +10,424,846 +3,635,071 +34.9 +% +Total +16,949,154 +13,664,586 +3,284,568 +24.0 +% +Average +Sales Price +$ +6.80 +$ +7.51 +$ +(0.71 +) +-9.5 +% +_____________ +*One +Bbl of oil is equal to the energy equivalent of six Mcf of natural +gas. +Sales +from Natural Gas Marketing Activities +Year +Ended December 31, +Change +2006 +2005 +Amount +Percent +(dollars +in thousands) +Sales +from natural gas marketing activities +$ +131,325 +$ +121,104 +$ +10,221 +8.4 +% +The +increase in revenue was the result of a 9% increase in volumes sold at prices +17.2% lower than 2005 levels and significant unrealized gains on derivative +transactions which amounted to approximately $12.3 million for the year ended +December 31, 2006, compared to unrealized losses of $8.5 million for the year +ended December 31, 2005. +43 +Table of Contents +Oil +and Gas Drilling Operations +Revenues +for oil and gas drilling operations for the years ended December 31, 2006 and +2005, are presented below. +Year +Ended December 31, +Change +2006 +2005 +Amount +Percent +(dollars +in thousands) +Oil +and gas well drilling operations +$ +17,917 +$ +99,963 +$ +(82,046 +) +-82.1 +% +During +the first quarter of 2006, we began operating and recognizing revenues for our +cost-plus service arrangements with new partnerships, in addition to our +footage-based drilling arrangements on earlier partnerships. The +cost-plus drilling arrangements became effective with the private program +partnership we funded in December 2005 and continued in the 2006 partnership +funded on September 1, 2006. Drilling revenues for the year ended +December 31, 2006, were $17.9 million, net of $74.6 million of costs related to +drilling arrangements accounted for on the cost-plus basis, compared to $100 +million for the year ended December 31, 2005, a decrease of $82.1 +million. The decrease was primarily due to the change in our drilling +contracts, which resulted in net revenue recognition related to the new +contracts. +Although +we changed to cost-plus drilling arrangements with our two recent partnerships, +prior footage-based contracts continue to be in effect, and realized a loss of +$2.1 million during 2006. This loss contributed to the decrease in +the drilling and development segment gross margin from $11.8 million for the +year ended December 31, 2005, to $5.3 million for the year ended December 31, +2006. This loss was due to some drilling and completion difficulties +incurred and significantly increasing well drilling and completion costs, +particularly the costs of fracturing and rising steel costs for casing and other +well equipment and oil field services. Future partnerships will be +drilled on a “cost-plus basis,” which should reduce these fluctuations in +drilling gross margins. See Note 1 , Summary of Significant Accounting +Policies , to our accompanying consolidated financial +statements. +Well +Operations and Pipeline Income +Revenues +for Well operations and pipeline income for the years ended December 31, 2006 +and 2005, are presented below. +Year +Ended December 31, +Change +2006 +2005 +Amount +Percent +(dollars +in thousands) +Well +operations and pipeline income +$ +10,704 +$ +8,760 +$ +1,944 +22.2 +% +The +increase in revenue was due to an increase in the number of wells and pipeline +systems we operate for drilling partnerships, as well as for third +parties. +Oil +and Gas Price Risk Management Gain (Loss), Net +Oil and +gas price risk management, net for the years ended December 31, 2006 and 2005, +is presented below. +Year +Ended December 31, +Change +2006 +2005 +Amount +Percent +(dollars +in thousands) +Oil +and gas price risk management gain (loss), net +$ +9,147 +$ +(9,368 +) +$ +18,515 +-197.6 +% +For the +year ended December 31, 2006, we recorded realized gains of $1.9 million and +unrealized gains of $7.2 million compared to the year ended December 31, 2005, +which is comprised of unrealized losses of $3 million and realized losses of +$6.4 million. Our strategy is to provide protection in the event of +declining oil and natural gas prices. During 2006, we experienced +decreasing natural gas and rising oil pricing environments. This +trend and the timing, extent and nature of the derivative trades executed caused +us to record gains in our derivative transactions as a result of gains on the +natural gas positions. Oil and gas price risk management gains +(losses), net is comprised of the change in fair value of oil and natural gas +derivatives related to oil and gas production (this line item does not include +commodity-based derivative transactions related to transactions from gas +marketing activities, which are included in the revenues and expenses of the +related purchase and sales transactions). +44 +Table of Contents +Other +Income +Other +income, consisting primarily of management fees associated with +Company-sponsored drilling programs, was relatively unchanged at $2.2 million +for each of the years ended December 31, 2006 and 2005. +Costs +and Expenses +Oil +and Gas Production and Well Operations Costs +Oil and +gas production and well operations costs for the years ended December 31, 2006 +and 2005, are presented below. +Year +Ended December 31, +Change +2006 +2005 +Amount +Percent +(dollars +in thousands, except per Mcfe) +Oil +and gas production and well operations cost +$ +29,021 +$ +20,400 +$ +8,621 +42.3 +% +Per +Mcfe +$ +1.71 +$ +1.49 +$ +0.22 +14.7 +% +The +increase in cost was due to the increased production costs associated with the +24% increase in production volumes, along with the increased number of wells and +pipelines we operate. Lifting costs per Mcfe increased from $1.19 per +Mcfe for the year ended December 31, 2005, to $1.23 per Mcfe for the year ended +December 31, 2006, due to the significant inflation of oil field production +services along with additional well workovers and production enhancements work +performed. +Cost +of Natural Gas Marketing Cost +Cost of +natural gas marketing activities for the years ended December 31, 2006 and 2005, +are presented below. +Year +Ended December 31, +Change +2006 +2005 +Amount +Percent +(dollars +in thousands) +Cost +of natural gas marketing activities +$ +130,150 +$ +119,644 +$ +10,506 +8.8 +% +The +increase in cost was due to higher average volumes of natural gas purchased for +resale and a significant increase in unrealized losses on derivative +transactions, which amounted to approximately $11.9 million for the year ended +December 31, 2006, compared to an unrealized gain of $8.3 million for the year +ended December 31, 2005. Income before income taxes for our natural +gas marketing subsidiary increased from $1.7 million for the year ended December +31, 2005, to $1.8 million for the year ended December 31, 2006. Based +on the nature of our gas marketing activities, derivatives did not have a +significant effect on our net margins from marketing activities during either +period. +Cost +of Oil and Gas Well Drilling Operations +Cost of +oil and gas well drilling operations for +the years ended December 31, 2006 and 2005, are presented below. +Year +Ended December 31, +Change +2006 +2005 +Amount +Percent +(dollars +in thousands) +Cost +of oil and gas well drilling operations +$ +12,617 +$ +88,185 +$ +(75,568 +) +-85.7 +% +The +decrease in costs is primarily attributable to our revenue reporting for our new +cost-plus drilling arrangements, which reduced drilling costs by $74.6 million +for the year as discussed above. +The new +cost-plus drilling arrangement eliminates our risk of loss from the contract +drilling services we provide the partnerships. Our drilling revenues +and corresponding costs are presented net as a one-lined income statement item +representing only the gross profit portion of the drilling +arrangement. The new cost-plus contract affected 2006 by reducing +drilling revenues and drilling costs by $74.6 million as outlined in the table +below (in millions): +45 +Table of Contents +Year +ended December 31, +2006 +2005 +Drilling +Service Revenue/Cost +Direct +Reimbursed Cost +Revenue/Cost +including +reimbursement +from Partnerships +Drilling +Service Revenue/Cost +Oil +and gas well drilling operations +$ +17.9 +$ +74.6 +$ +92.5 +$ +100.0 +Total +revenues +286.5 +74.6 +361.1 +325.2 +Cost +of oil and gas well drilling operations +12.6 +74.6 +87.2 +88.2 +Total +costs and expenses +232.7 +74.6 +307.3 +267.4 +Exploration +Expense +Exploration +expense for the years ended December 31, 2006 and 2005, is presented +below. +Year +Ended December 31, +Change +2006 +2005 +Amount +Percent +(dollars +in thousands) +Exploration +expense +$ +8,131 +$ +11,115 +$ +(2,984 +) +-26.8 +% +The +decrease in expense is primarily attributable to fewer exploratory dry holes +being drilled in 2006. In 2006, exploratory dry hole expenses were +$1.8 million compared to $11.1 million in 2005. In 2006, we recorded +an impairment charge of $1.5 million on our Nesson Field in North Dakota and +incurred geological and geophysical costs of $2.2 million which relate to an +exploratory seismic program initiated on our Northeast Colorado +properties. We anticipate additional geological and geophysical +activities and related costs in 2007. +General +and Administrative Expense +General +and administrative expense for the years ended December 31, 2006 and 2005, is +presented below. +Year +Ended December 31, +Change +2006 +2005 +Amount +Percent +(dollars +in thousands, except per Mcfe) +General +and administrative expense +$ +19,047 +$ +6,960 +$ +12,087 +173.7 +% +Per +Mcfe +$ +1.12 +$ +0.51 +$ +0.61 +119.6 +% +A +substantial portion of the increase was attributable to the costs of our +financial statement restatement and the restatement of our sponsored +partnerships’ financial statements. In addition, we continue to +experience a high level of costs complying with the various provisions of the +Sarbanes-Oxley Act, in particular Section 404 (internal and external costs of +assessing Internal Controls over Financial Reporting). Approximately +$3.2 million of the increase is attributable to the external costs incurred in +connection with restatement of financial statements and compliance with the +provisions of the Sarbanes-Oxley Act. Finally, we added over 39 new +employees in 2006 and experienced increased payroll and payroll-related costs of +$4.3 million. +46 +Table of Contents +Depreciation, +Depletion, and Amortization +DD&A expense for the years ended +December 31, 2006 and 2005, is presented below. +Year +Ended December 31, +Change +2006 +2005 +Amount +Percent +(dollars +in thousands, except per Mcfe) +Depreciation, +depletion and amortization +$ +33,735 +$ +21,116 +$ +12,619 +59.8 +% +Per +Mcfe +$ +1.99 +$ +1.55 +$ +0.44 +28.4 +% +The +increase in cost was due to the 24% increase in production volumes, significant +investments in oil and gas properties by us in 2006, and increased per unit cost +of depreciation, depletion and amortization as a result of rising costs of +drilling, completing and equipping wells. +Gain +on Sale of Leaseholds +Gain on +sale of leaseholds for the year ended December 31, 2006, was $328 million +compared to $7.7 million in 2005, an increase of $320.3 million. The +increase is attributable to the sale of undeveloped leaseholds in Garfield +County, Colorado in the third quarter of 2006, for which a portion of the gain +to be recognized was deferred to future periods. See Note 16 , Sale of Oil and Gas +Properties , to our accompanying consolidated financial +statements. The prior year period included a gain of $6.2 million for +the sale of a portion of one of our undeveloped leases in Garfield County, +Colorado and a gain of $1.5 million for the sale to an unaffiliated party of +some Pennsylvania wells. +Non-Operating +Income/Expense +Year +Ended December 31, +Change +2006 +2005 +Amount +Percent +(dollars +in thousands) +Non-operating +income (expense): +Interest +income +$ +8,050 +$ +898 +$ +7,152 +796.4 +% +Interest +expense +$ +(2,443 +) +$ +(217 +) +$ +(2,226 +) +1025.8 +% +The +increase in interest income was primarily due to the interest on the temporary +investment, in cash equivalents, of cash proceeds of $353.6 million from the +sale of undeveloped leaseholds. The increase in interest expense was +due to rising interest rates on significantly higher average outstanding +balances of the credit facility, offset in part by $1.6 million of capitalized +construction period interest. We utilize our daily cash balances to +reduce our line of credit to lower our cost of borrowing. The average +outstanding debt balance for the year ended December 31, 2006, was $44.2 million +compared to $4.1 million for the year ended December 31, 2005. +Provision +for Income Taxes +The +effective income tax rate for our provision for income taxes increased from +37.3% for the year ended December 31, 2005, to 38.6% for the year ended December +31, 2006, primarily as a result of the gain on sale of leasehold being taxed at +the full federal and state statutory rates because there are no offsetting +permanent deductions, such as percentage depletion, available on such a +sale. In addition, the domestic production activities deduction was +not utilized in 2006 due to our decision, for tax purposes only, to expense the +majority of our intangible drilling costs. +Liquidity +and Capital Resources +Cash flow +from operations and our bank credit facility are our primary sources of +liquidity to meet operating expenses and fund capital expenditures (other than +for certain acquisitions). Recently, as of February 8, 2008, we +completed the issuance and sale of $203 million of 12% senior notes due 2018 for +net proceeds received of approximately $196 million. The completion +of the issuance and sale of our senior notes enabled us to reduce our short term +liquidity risk through the terming out of our existing credit facility of +November 2010 and extending it until February 2018. The repayment of +the amounts outstanding under the credit facility with a portion of the net +proceeds from the senior notes provided $234.1 million of available borrowing +capacity. As of February 29, 2008, we have access to all of the +$234.1 million facility as it was un-drawn. Additionally, we believe +that our continued drilling activities will allow us, through our permitted +borrowing base re-determinations, to increase the borrowing capacity of the +credit facility. See Long Term Debt discussed +below. +47 +Table of Contents +Our 2008 +capital expenditure budget is $255 million: $194 million for drilling and +development; $50 million for exploratory drilling, land acquisitions and seismic +activities; and $11 million for other capital expenditures. We +believe this level of exploration and development activity will be sufficient to +increase our proved oil and natural gas reserves in 2008 and increase our total +production by between 30% and 40% (without regard to any additional acquisitions +that may be completed in 2008). We retain a significant degree of +control over the timing of our capital expenditures, which permits us to defer +or accelerate certain capital expenditures if necessary to address any potential +liquidity issues. In addition, higher drilling and field operating +costs, drilling results that alter planned development schedules, acquisitions +or other factors could cause us to revise our drilling program, which programs +are largely discretionary. We believe that our available cash, cash +provided by operating activities and funds available under our revolving credit +facility will be sufficient to fund our operations, debt service, partnership +drilling obligation, general and administrative expenses, capital budget, and +short-term contractual obligations for the next few years . +Changes +in market prices for oil and natural gas directly affect the level of our cash +flow from operations. While a decline in oil and natural gas prices +would affect the amount of cash flow that would be generated from operations, we +had oil and natural gas hedges in place, as of March 3, 2008, covering 41% of +our expected oil production and 62% of our expected natural gas production in +2008, thereby providing price certainty for a substantial portion of our 2008 +cash flow. Depending on changes in oil and natural gas futures +markets and our view of underlying oil and natural gas supply and demand trends, +we may increase or decrease our current hedging positions. Our oil +and natural gas hedges as of December 31, 2007, are detailed in Item 7A of this +report. +We have +utilized public and private markets, proceeds from bank borrowings and cash flow +from operations for our capital resources and liquidity. To date, our +primary use of capital has been for the acquisition and development of oil and +gas properties. As we pursue growth, we will continually monitor the +capital resources available to meet our future financial obligations and planned +capital expenditures. Our future success in replacing and growing +reserve levels will be highly dependent on the capital resources available and +our success in drilling for or acquiring additional reserves. We +actively review acquisition opportunities on an ongoing basis. If we +were to make significant additional acquisitions for cash, we would need to +borrow additional amounts under our current credit facility, if available, or +obtain additional debt or equity financing. +On +January 7, 2008, we announced that we do not plan to sponsor new drilling +partnerships in 2008 in order to focus our efforts on continuing our growth +through drilling and exploration. In 2008, we expect +to recognize $7.8 million in oil and gas well drilling revenue related to +the 2007 drilling partnership. +Operating +Cash Flows +Net cash +provided by operating activities was $60.3 million in 2007 compared to $67.4 +million in 2006, a decrease of $7.1 million. The decrease in cash +provided by operating activities was due primarily to the +following: +· +Increased +costs from production and well operations related to the 65% increase in +production, as well as the increases in exploration and general and +administrative expenses, partially offset by the increase in oil and gas +sales revenues; +· +Federal +and state taxes payable decreased primarily due to the 2007 payment of +taxes of the non deferred portion of the gain on the sale of the Grand +Valley Field Acreage; +· +The +decrease in accounts payable is primarily due to the timing of payments +related to the purchase of properties and +equipment; +· +Current +restricted cash increased due to the funding in 2007 of an escrow account +for amounts due limited partners as a result of over withholding of +estimated production taxes; +· +Accounts +payable to affiliates decreased for the partnership’s share of unpaid +premiums and unrealized losses related to hedge positions at December 31, +2007; +· +Production +tax liability increased due to the 65% increase in oil and gas production +volumes in 2007; and +· +Advances +for future drilling contracts increased due to the timing of drilling and +development activities on behalf of our 2007 sponsored drilling +partnership. +Net cash +provided by operating activities was $67.4 million in 2006 compared to $112.4 +million in 2005, a decrease of $45 million. +The +decrease in cash provided by operating activities was due primarily to the +following: +· +Increased +costs from production and well operations related to the 24% increase in +production volumes and increased number of +wells; +· +Increase +in general and administrative costs due to the Company’s financial +statement restatement and incremental costs to comply with various +provisions of Sarbanes-Oxley partially offset by; +and +· +The +increase in oil and gas sales revenues due to the 24% increase in +production volumes at lower unit sales +prices. +48 +Table of Contents +Investing +Cash Flows +Net cash +used in investing activities was $267.4 million in 2007 compared to $9.6 million +in 2006, an increase of $257.8 million. +The +increase in cash used in investing activities was due primarily to the +following: +· +An +approximate $93 million increase in capital expenditures is primarily due +to an increase in the number of wells drilled to 349 in 2007 from 231 in +2006 or approximately $72 +million; and +· +Acquisitions +of oil and natural gas properties of approximately $256 +million; +Partially +offset by: +· +The +2006 acquisition of Unioil of approximately $18 million; +and +· +The +net effect of the transfer of the funds from the Like kind exchange, or +LKE, from restricted cash and the proceeds from the 2006 sale of the Grand +Valley Field acreage. +Net cash +used in investing activities was $9.6 million in 2006 compared to $94 million in +2005, a decrease of $84.4 million. The decrease in cash used in +investing activities was due primarily to the following: +· +An +approximate $49 million increase in the capital expenditures; +and +· +Approximately +$192 million increase in restricted/designated cash due to +acquisitions; +Partially +offset by: +· +An +approximate $344 million increase in proceeds from sale of +leasehold/assets due to the sale of the Grand Valley Field acreage in July +2006. +Financing +Cash Flows +Net cash +provided by financing activities was $97.5 million in 2007 compared to $46.5 +million in 2006, an increase of $51 million. The increase in cash +provided by financing activities was due primarily to the +following: +· +A +decrease of treasury stock purchases of approximately $66 million offset +by the net change in short and long term debt from borrowing +activities. +Net cash +provided by financing activities was $46.5 million in 2006 compared to net cash +used in financing activities of $5.3 million in 2005, an increase of $51.8 +million. The increase in cash provided by financing activities was +due primarily to the following: +· +An +approximate $110 million increase in proceeds from the issuance of +long-term and short-term debt, net of retirement of debt, in +2006; +Partially +offset by: +· +An +approximate $59 million of additional treasury stock +purchases. +Working +Capital +Our +working capital usage for 2007 was $50.2 million. At December 31, +2007, we had available borrowing capacity under our bank credit facility of $60 +million. Historically, we have satisfied our working capital needs +through free cash flow and borrowings under our credit facility. We +may need to raise additional capital in the bank, private and public markets to +fund future acquisitions and increases in capital expenditure +levels. We expect to continue to maintain adequate liquidity to meet +our obligations on an ongoing basis. If we are unable to raise +incremental capital, future capital expenditures and acquisitions may be +affected. We used most of the net proceeds of approximately $196 +million from our February 8, 2008, $203 million senior notes offering to repay +the $180 million then drawn under our bank credit facility. Upon the +issuance of our senior notes on February 8, 2008, our activated commitment of +$295 million was mandatorily reduced to $234.1 million. As of +February 29, 2008, our outstanding credit facility was +un-drawn. Based on near-term cash flow projections, the discretionary +nature of our capital program, our bank credit facility capacity and the +demonstrated ability to raise capital in bank, private and public markets, we +believe that we have sufficient liquidity to fund our operations in +2008. +49 +Table of Contents +Long-Term +Debt +We +have a credit facility with JPMorgan Chase Bank, N.A., or JPMorgan, and BNP +Paribas, as amended, dated as of November 4, 2005, with an activated commitment +of $295 million as of December 31, 2007. The credit facility, through +a series of amendments, includes commitments from Wachovia Bank, N.A., Bank of +Oklahoma, Allied Irish Banks p.l.c., Guaranty Bank, BSB, Royal Bank of Canada +and The Royal Bank of Scotland, plc. The maximum allowable commitment +under the current credit facility is $400 million. The credit +facility is subject to and secured by required levels of natural gas and oil and +reserves. The credit facility requires an aggregated security of a +value no less than 80% of the value of the direct interests included in the +borrowing base properties. We are required to pay a commitment fee of +0.25% to 0.375% per annum on the unused portion of the activated credit +facility. Interest accrues at an alternative base rate or adjusted +LIBOR at our discretion. The +alternative base rate is the greater of JPMorgan's prime rate, an adjusted +secondary market rate for a three-month certificate of deposit plus 1% or the +federal funds effective rate plus 0.5%. Alternative base rate +borrowings are assessed an additional margin spread up to 0.375% and adjusted +LIBOR borrowings are assessed an additional margin spread of 1.125% to 1.875%, +based upon the outstanding balance under the credit facility. The +credit agreement requires, among other things, the maintenance of certain +working capital and tangible net worth ratios. No principal payments +are required until the credit agreement expires on November 4, +2010. +Effective +August 9, 2007, the first amendment to our credit facility waived our working +capital covenant until the earlier of (i) a debt or equity transaction resulting +in net proceeds, as defined, to us of at least $200 million or (ii) July 1, +2008, which was further extended to October 1, 2008, effective October 16, +2007. In accordance with the first amendment, the alternative base +rate was increased by 0.375% as long as the waiver of the working capital +covenant was in effect. +On +February 8, 2008, we completed the issuance and sale of $203 million aggregate +principal amount of 12% senior notes due 2018 for net proceeds received of +approximately $196 million; see Note 5 , Long Term Debt , to our +accompanying consolidated financial statements. In accordance with +the senior credit agreement, upon the issuance of any senior notes, the +borrowing base then in effect on our credit facility shall automatically be +reduced by $300 for each $1,000 in stated principal amount of such senior notes +issued by us. Accordingly, effective February 8, 2008, our borrowing +base under the credit facility was reduced from $295 million to $234.1 +million. Further, our senior notes issuance meets the requirements of +a debt transaction described above, and thus, the testing of our working capital +covenant will resume with our quarter ending March 31, 2008. +As of +December 31, 2007, the outstanding balance under our credit facility was $235 +million compared to $117 million, excluding the overline note discussed below, +as of December 31, 2006. The borrowing rate on the outstanding +balance was 7.07% and 7.79% at December 31, 2007, and December 31, 2006, +respectively. Amounts outstanding under the credit facility were +secured by substantially all of our properties. We were in compliance +with all covenants at December 31, 2007, and expect to remain in compliance +throughout 2008. +On +December 19, 2006, we executed, pursuant to our credit facility, an overline +note in the amount of $20 million to be repaid on January 31, +2007. Interest on the overline note accrued at a per annum rate equal +to the alternate base rate plus 0.8% until December 22, 2006, at which time the +rate converted to a Eurodollar borrowing for a one month period and at a per +annum rate equal to an adjusted LIBOR rate plus 2.30%. The overline +note was paid in full in accordance with its terms in January 2007. +Drilling +Programs +In August +2007, we completed our sponsored drilling partnership offering, Rockies Region +2007 Limited Partnership, and received subscriptions of approximately $90 +million. We contributed $38.7 million, which represented 43% of the +$90 million of total subscriptions received, for our general partner capital +contribution. Drilling for the partnership commenced during the third +quarter and continued in the fourth quarter of 2007. From inception +to December 31, 2007, $5.3 million in revenues has been +recognized. On December 28, 2007, the drilling partnership paid to us +$54 million, in accordance with the partnership agreement, to secure intangible +drilling cost tax deductions for the investing partners. This payment is +included in advances for future drilling contracts on our consolidated balance +sheet. In early January 2008, we used this advance to pay down our +credit facility. Drilling and completion operations for the 2007 +drilling program will continue through the first half of 2008. We +expect to recognize additional revenue of approximately $7.8 million in our oil +and gas well drilling operations related to this partnership during +2008. In January 2008, we announced that we do not plan to sponsor +new drilling partnerships in 2008 in order to focus our effort on maximizing the +value of the existing partnerships and our continuing growth through drilling +and exploration. +50 +Table of Contents +Treasury +Share Purchases +On +October 16, 2006, our Board of Directors approved a second 2006 share purchase +program authorizing us to purchase up to 10% of our then outstanding common +stock (1,477,109 shares) through April 2008. Stock purchases under +this program may be made in the open market or in private transactions, at times +and in amounts that we deem appropriate. Shares are generally +purchased at fair market value based on the closing price on the date of +purchase. Total shares purchased in 2007 pursuant to the program were +12,020 common shares at a cost of $0.6 million ($53.78 average price paid per +share), including 5,187 shares from our executive officers at a cost of $0.3 +million ($57.93 price paid per share). Shares purchased pursuant to +the plan were primarily to satisfy the statutory minimum tax withholding +requirement for restricted stock that vested in 2007. All shares were +subsequently retired. At December 31, 2007, the remaining number of +shares that may be purchased under this program is 1,465,089, see Item 5 , Market for Registrant's Common +Equity and Related Stockholders Matters - Issuer Purchases of Equity +Securities , of this report for a reconciliation of +activities. +Pursuant to our senior notes indenture entered on February 8, +2008, any future purchases are limited, see Note 19, Subsequent Events , to our accompanying +consolidated financial statements. +On +February 25, 2008, pursuant to a separation agreement, we purchased 50,000 +shares of our common stock from one of our executive officers at a cost of $3.4 +million, or $67.92 per share. See Note 19 , Subsequent Events , to our +accompanying consolidated financial statements. +Contractual +Obligations and Contingent Commitments +The table +below sets forth our contractual obligations and contingent commitments as of +December 31, 2007: +Payments +due by period +Contractual +Obligations and Contingent Commitments +Total +Less +than +1 +year +1-3 +years +3-5 +years +More +than +5 +years +(in +thousands) +Debt (1) +$ +235,000 +$ +- +$ +235,000 +$ +- +$ +- +Interest +(2) +47,255 +16,613 +30,642 +- +- +Operating +leases +4,460 +1,948 +1,827 +685 +- +Asset +retirement obligations +20,781 +50 +100 +100 +20,531 +Rig +commitments (3) +24,669 +8,810 +15,859 +- +- +Drilling +commitments (4) +3,655 +- +1,155 +- +2,500 +Other +liabilities (5) +8,876 +1,133 +720 +720 +6,303 +Total +$ +344,696 +$ +28,554 +$ +285,303 +$ +1,505 +$ +29,334 +__________ +(1) +Long-term +debt does not include interest. +(2) +Interest +based on balance at December 31, 2007, at an applied rate of +7.07%. +(3) +Drilling rig commitments in +the above table do not include future adjustments to daily rates as +provided for in the agreements as such increases are not predictable and +are only included in the above obligation table upon notification to us by +the contractor of an increase in the +rate . +(4) +Amounts +represent our maximum obligation for potential liquidating damages if we +do not comply with certain drilling and development +agreements. See Note 8, Commitments and Contingencies, to our +accompanying consolidated financial statements. These amounts +do not include advances for future drilling contracts totaling $68.4 +million at December 31, 2007. +(5) +Includes +funds held from revenue distribution to third party investors for plugging +liabilities related to wells we operate and deferred officer compensation. +Further, includes unrecognized tax benefits totaling $0.9 million pursuant +to FIN No. 48. +(6) +Table +does not include maximum annual repurchase obligation of $6.7 million as +of December 31, 2007, see Note 8, Commitments and Contingencies, to our +accompanying consolidated financial +statements. +51 +Table of Contents +Commitments +and Contingencies +As +managing general partner of 33 partnerships (see Item 1. Business – +Drilling and Development +Conducted for Company Sponsored Partnerships , we have liability for any +potential casualty losses in excess of the partnership assets and +insurance. In January 2007, we purchased the remaining working +interests in 44 of 77 partnerships, which we sponsored in the late 1980s and +1990s (see Note +2 , Acquisitions , +to our accompanying consolidated financial statements). We believe +that the casualty insurance coverage we and our subcontractors carry is adequate +to meet this potential liability. +For +information regarding our legal proceedings, see Note 8 , Commitments and Contingencies – +Litigation , to our accompanying consolidated financial statements +included in this report. +From time +to time we are a party to various other legal proceedings in the ordinary course +of business. We are not currently a party to any litigation that we +believe would have a materially adverse affect on our business, financial +condition, results of operations, or liquidity. +Sale +of Undeveloped Leaseholds +In July +2006, we sold to an unaffiliated company a portion of our undeveloped leasehold +located in Grand Valley Field, Garfield County, Colorado. The sale +encompassed 100% of the working interest in approximately 8,700 acres, including +approximately 6,400 acres of the Chevron leasehold and 2,300 acres of the +Puckett Land Company leasehold. We retained approximately 475 +undeveloped locations on 10 acre spacing on the Grand Valley Field leasehold in +addition to all of our producing properties in the field. The +proceeds from the sale were $353.6 million. We recorded a gain on +sale of leaseholds of $328 million and a deferred gain on sale of leaseholds of +$25.6 million. +Pursuant +to the purchase and sale agreement, we were obligated to either drill 16 wells +on specifically identified acreage over the next three years or pay liquidated +damages of $1.6 million per undrilled well for a total contingent obligation of +$25.6 million, which was reflected as a deferred gain on sale of leaseholds on +the balance sheet as of December 31, 2006. In May 2007, we entered +into a letter agreement amending the original purchase and sale +agreement. The letter agreement relieved us of the obligation, in its +entirety, to either drill 16 wells or pay liquidated damages, resulting in the +recognition of the remaining $25.6 million deferred gain on sale of leaseholds +in the second quarter of 2007. Pursuant to the letter agreement, we +were obligated to drill six wells on specifically identified +acreage. As of December 31, 2007, we had drilled all six wells, which +were drilled on the unaffiliated party's leasehold for its benefit and at its +cost. +In +conjunction with the purchase and sale agreement described above, we entered +into a LKE agreement, in accordance with Section 1031 of the Internal Revenue +Code, with a “qualified intermediary.” Proceeds in the amount of $300 +million were transferred directly to the qualified intermediary to be held in +trust pursuant to the terms of the LKE agreement. We had until +mid-January 2007 to close any acquisition of suitable like-kind property, +allowing us to take advantage of the income tax deferral benefits of a LKE +transaction. See below a discussion of the acquisition of suitable +like-kind properties. +In +December 2007, we sold to the same unaffiliated party a portion of our North +Dakota properties for approximately $34.7 million. The properties, +located in Dunn, Williams and McKenzie Counties, North Dakota, include interests +in five producing Bakken wells and leasehold interests in approximately 72,000 +net undeveloped acres. The reduction in our production and proved +reserves as a result of this transaction is not material. We recorded +a gain on sale of leaseholds of $7.7 million in the fourth quarter of +2007. The proceeds from the sale were used to pay down +debt. Following the sale, as it relates to our North Dakota +properties, we retain ownership in three producing wells in Dunn County, ten +producing wells in Burke County and approximately 60,000 acres of undeveloped +leasehold in Burke County. +Acquisition +of Oil and Gas Properties +Acquisition +of Section 1031 – LKE Properties +In +January 2007, we completed our acquisitions of suitable like-kind properties in +accordance with the LKE agreement we entered into in connection with our sale of +undeveloped leaseholds located in Grand Valley Field, Garfield Country, +Colorado, in July 2006. We paid cash consideration for the acquired +oil and gas properties totaling $188.9 million, as described below. +52 +Table of Contents +EXCO +Resources Inc . On +January 5, 2007, we completed our purchase of EXCO Resources Inc.’s producing +properties and remaining undeveloped drilling locations and acreage in the +Wattenberg Field of the DJ Basin, Colorado. The cash consideration +paid for the EXCO properties was $130.2 million. The acquisition +included substantially all of EXCO’s assets in the area and encompassed 144 oil +and gas wells (approximating 25.5 Bcfe, net of royalty interests, proved +developed reserves as of December 31, 2005) and 8,160 acres of leasehold +interests. The wells and leases acquired are located in Weld, Adams, +Larimer, and Broomfield Counties, Colorado. We operate the assets and +hold a majority working interest in the properties. +Company-Sponsored +Partnerships . On +January 10, 2007, we completed the purchase of a majority interest in 44 of our +sponsored partnerships for $56.6 million. This transaction was not +effected pursuant to purchase requests by investor partners (see Note 8 , Commitments and +Contingencies , to our accompanying consolidated financial +statements). The wells are located in the Appalachian Basin, +Michigan, and Colorado. The transaction resulted in an increase of +423 net wells that we currently operate. +Other. We +acquired from unaffiliated parties undeveloped leaseholds in Erath County, Texas +for $2.1 million. +Other +Acquisitions +On +February 22, 2007, we acquired from an unaffiliated party 28 producing wells and +associated undeveloped acreage located in Colorado (Wattenberg Field) for a +purchase price of $12 million. The acquisition encompassed daily +production of approximately 668 Mcfe (520 Mcf of gas and 25 barrels of oil per +day), net to the interests acquired, 100 or more undeveloped drilling locations, +19.1 Bcfe of proved reserves, and an additional 7.5 Bcfe of probable +reserves. +On +October 30, 2007, with an effective date of October 1, 2007, we purchased from +unrelated parties a majority working interest in 762 natural gas wells located +in southwestern Pennsylvania for approximately $54 million. We +estimated that the acquisition included approximately 47 Bcfe of reserves, or 31 +Bcfe of proved reserves and 16 Bcfe of unproved reserves. The +purchase also included associated pipelines, equipment, real estate and +undeveloped acreage. +Critical +Accounting Policies and Estimates +We +have identified the following policies as critical to business operations and +the understanding of our results of operations. This is not a +comprehensive list of all of the accounting policies. In many cases, +the accounting treatment of a particular transaction is specifically dictated by +accounting principles generally accepted in the United States, with no need for +our judgment in the application. There are also areas in which our +judgment in selecting any available alternative would not produce a materially +different result. However, certain of our accounting policies are +particularly important to the portrayal of our financial position and results of +operations and we may use significant judgment in the application; as a result, +they are subject to an inherent degree of uncertainty. In applying +those policies, we use our judgment to determine the appropriate assumptions to +be used in the determination of certain estimates. Those estimates +are based on historical experience, observation of trends in the industry, and +information available from other outside sources, as appropriate. For +a more detailed discussion on the application of these and other accounting +policies, see Note +1 , Summary of +Significant Accounting Policies , to our accompanying consolidated +financial statements. Our critical accounting policies and estimates +are as follows: +Revenue +Recognition +Oil and natural gas +sales . Sales of oil are recognized when persuasive evidence of +a sales arrangement exists, the oil is verified as produced and is delivered to +a purchaser, collection of revenue from the sale is reasonably assured and the +sales price is determinable. We are currently able to sell all the +oil that we can produce under existing sales contracts with petroleum refiners +and marketers. We do not refine any of our oil +production. Our crude oil production is sold to purchasers at or near +our wells under short-term purchase contracts at prices and in accordance with +arrangements that are customary in the oil industry. +Sales of +natural gas are recognized when natural gas has been delivered to a custody +transfer point, persuasive evidence of a sales arrangement exists, the rights +and responsibility of ownership pass to the purchaser upon delivery, collection +of revenue from the sale is reasonably assured and the sales price is fixed or +determinable. Natural gas is sold by us under contracts with terms +ranging from one month to three years. Virtually all of our contract +pricing provisions are tied to a market index, with certain adjustments based +on, among other factors, whether a well delivers to a gathering or transmission +line, quality of natural gas and prevailing supply and demand conditions, so +that the price of the natural gas fluctuates to remain competitive with other +available natural gas supplies. As a result, our revenues from the +sale of natural gas will suffer if market prices decline and benefit if they +increase. We believe that the pricing provisions of our natural gas +contracts are customary in the industry. +53 +Table of Contents +We +currently use the “net-back” method of accounting for transportation +arrangements of natural gas sales. We sell gas at the wellhead and +collect a price and recognize revenues based on the wellhead sales price since +transportation costs downstream of the wellhead are incurred by our customers +and reflected in the wellhead price. +Natural gas marketing +activities . Natural gas marketing is reported on the gross +accounting method, based on the nature of the agreements between RNG, our +suppliers and our customers. RNG, our marketing subsidiary, purchases +gas from many small producers and bundles the gas together to sell in larger +amounts to purchasers of natural gas for a price advantage. RNG has +latitude in establishing price and discretion in supplier and purchaser +selection. Natural gas marketing revenues and expenses reflect the +full cost and revenue of those transactions because RNG takes title to the gas +it purchases from the various producers and bears the risks and rewards of that +ownership. Both the realized and unrealized gains and losses of the +RNG commodity based derivative transactions for natural gas marketing activities +are included in gas sales from marketing activities or cost of gas marketing +activities, as applicable. +Oil and gas well drilling +operations . Our drilling segment recognizes revenue from +drilling contracts with sponsored drilling programs using the percentage of +completion method based upon the percentage of contract costs incurred to date +to the estimated total contract costs for each contract. We utilize +this method since reasonably dependable estimates of the total estimated costs +can be made and recognized revenues are subject to revisions as a contract +progresses, the term of which can range from three to twelve +months. In addition, we offer our drilling services under two types +of contractual arrangements, cost-plus or footage-based service contracts, which +result in differing risk and reward relationships and, consequently, different +revenue reporting policies pursuant to Emerging Issues Task Force, or EITF, +Issue No. 99-19, Reporting +Revenue Gross as a Principal versus Net as an Agent . +The first +cost-plus drilling service arrangement was entered into in late 2005 with +drilling activity commencing in the first quarter of 2006. Due to the +fixed-fee-percentage nature of our revenues from these services, we have +determined that, in substance, we are acting as an agent, without risk of loss +during the performance of the drilling activities. Accordingly, our +services provided under the cost-plus drilling agreements are reported on a net +basis. We entered into our second and third cost-plus drilling +arrangements in September 2006 and August 2007 and commenced drilling +immediately. +Footage-based +contracts provide for the drilling, completion and equipping of wells at footage +rates and are generally completed within nine to twelve months after the +commencement of drilling. We provide geological, engineering, and +drilling supervision on the drilling and completion process and use +subcontractors to perform drilling and completion services at a fixed +footage-based rate and accordingly have the risk of loss in performing services +under these arrangements. Accordingly, we report revenue under these +agreements gross of related expenses. Anticipated losses, if any, on +uncompleted contracts are recorded at the time that the estimated total costs +exceed the estimated total contract revenue. At December 31, 2007 and +2006, the loss contract reserve was $0.2 million and $0.3 million, +respectively. +Well operations and pipeline +income . Well operations and pipeline income are recognized +when persuasive evidence of an arrangement exists, services have been rendered, +collection of revenues is reasonably assured and the sales price is fixed or +determinable. We are paid a monthly operating fee for each well we +operate for outside owners including the limited partnerships we +sponsor. The fee covers monthly operating and accounting costs, +insurance and other recurring costs. We may also receive additional +compensation for special non-recurring activities, such as reworks and +recompletions. +Accounting +for Derivatives Contracts at Fair Value +We use +derivative instruments to manage our commodity and financial market +risks. We currently do not use hedge accounting treatment for our +derivatives. +Derivatives +are reported on our accompanying consolidated balance sheets at fair value on a +gross asset and liability basis. Changes in fair value of derivatives +are recorded in oil and gas price risk management, net, in our accompanying +consolidated statements of income. The measurement of fair value is +based on actively quoted market prices, if available. Otherwise, +validation of a contract's fair value is performed internally and, while we use +common industry practices to develop our valuation techniques, changes in our +pricing methodologies or the underlying assumptions could result in +significantly different fair values. If pricing information from +external sources is not available, measurement involves our judgment and +estimates. These estimates are based on valuation methodologies we +consider appropriate. For individual contracts, the use of different +assumptions could have a material effect on the contract's estimated fair +value. +Oil +and Gas Properties +We +account for our oil and gas properties under the successful efforts method of +accounting. Costs of proved developed producing properties, +successful exploratory wells and development dry hole costs are capitalized and +depreciated or depleted by the unit-of-production method based on estimated +proved developed producing oil and natural gas reserves. Property +acquisition costs are depreciated or depleted on the unit-of-production method +based on estimated proved oil and gas reserves. +54 +Table of Contents +Our +estimates of proved reserves are based on quantities of oil and natural gas that +engineering and geological analysis demonstrates, with reasonable certainty, to +be recoverable from established reservoirs in the future under current operating +and economic conditions. Annually, we engage independent petroleum +engineers to prepare a reserve and economic evaluation of all our properties on +a well-by-well basis as of December 31. Additionally, we adjust our +oil and gas reserves for major acquisitions, new drilling and divestitures +during the year as needed. The process of estimating and evaluating +oil and natural gas reserves is complex, requiring significant decisions in the +evaluation of available geological, geophysical, engineering and economic +data. The data for a given property may also change substantially +over time as a result of numerous factors, including additional development +activity, evolving production history and a continual reassessment of the +viability of production under changing economic conditions. As a +result, revisions in existing reserve estimates occur from time to +time. Although every reasonable effort is made to ensure that reserve +estimates reported represent our most accurate assessments possible, the +subjective decisions and variances in available data for various properties +increase the likelihood of significant changes in these +estimates. Because estimates of reserves significantly affect our +DD&A expense, a change in our estimated reserves could have an effect on our +net income. +Exploration +costs, including geological and geophysical expenses and delay rentals, are +charged to expense as incurred. Exploratory well drilling costs, +including the cost of stratigraphic test wells, are initially capitalized but +charged to expense if the well is determined to be nonproductive. The +status of each in-progress well is reviewed quarterly to determine the proper +accounting treatment under the successful efforts method of +accounting. Exploratory well costs continue to be capitalized as long +as the well has found a sufficient quantity of reserves to justify our +completion as a producing well and we are making sufficient progress assessing +our reserves and economic and operating viability. If an in-progress +exploratory well is found to be unsuccessful (referred to as a dry hole) prior +to the issuance of the financial statements, the costs are expensed to +exploration costs. If we are unable to make a final determination +about the productive status of a well prior to issuance of the financial +statements, the well is classified as “suspended well costs” until we have had +sufficient time to conduct additional completion or testing operations to +evaluate the pertinent geological and engineering data obtained. At +the time when we are able to make a final determination of a well’s productive +status, the well is removed from the suspended well status and the proper +accounting treatment is recorded. At December 31, 2007, suspended +well costs included in oil and gas properties on our accompanying consolidated +financial statements was $2.3 million. +The +acquisition costs of unproved properties are capitalized when incurred, until +such properties are transferred to proved properties or charged to expense when +expired, impaired or amortized. Unproved oil and gas properties with +individually significant acquisition costs are periodically assessed, and any +impairment in value is charged to exploration expense. The amount of +impairment recognized on unproved properties which are not individually +significant is determined by amortizing the costs of such properties within +appropriate fields based on our historical experience, acquisition dates and +average lease terms. The valuation of unproved properties is +subjective and requires us to make estimates and assumptions which, with the +passage of time, may prove to be materially different from actual realizable +values. +In +accordance with SFAS No. 144, Accounting for the Impairment or +Disposal of Long-Lived Assets , we assess our oil and gas properties for +possible impairment by comparing net capitalized costs to estimated undiscounted +future net cash flows on a field-by-field basis using estimated production based +upon prices at which we reasonably estimate the commodity to be +sold. The estimates of future prices may differ from current market +prices of oil and natural gas. Any downward revisions in estimates to +our reserve quantities, expectations of falling commodity prices or rising +operating costs could result in a reduction in undiscounted future net cash +flows and an impairment of our oil and gas properties. Although our +cash flow estimates are based on the relevant information available at the time +the estimates are made, estimates of future cash flows are, by nature, highly +uncertain and may very significantly from actual results. +Deferred +Income Tax Asset Valuation Allowance +Deferred +income tax assets are recognized for deductible temporary differences, net +operating loss carry-forwards, and credit carry-forwards if it is more likely +than not that the tax benefits will be realized. To the extent a +deferred tax asset is not expected to be realized under the preceding criteria, +a valuation allowance is established. The factors which we consider +in assessing whether we will realize the value of deferred income tax assets +involve judgments and estimates of both amount and timing, which could differ +from actual results, achieved in future periods. +The +judgments used in applying the above policies are based on our evaluation of the +relevant facts and circumstances as of the date of the financial +statements. Actual results may differ from those +estimates. +Accounting +for Acquisitions Using Purchase Accounting +We +account for acquisitions utilizing the purchase method as prescribed by SFAS No. +141, Business +Combinations . Pursuant to purchase method accounting, the +acquiring company must allocate the cost of the acquisition to assets acquired +and liabilities assumed based on fair values as of the acquisition +date. The purchase price allocations are based on appraisals, +discounted cash flows, quoted market prices and estimates by +management. In addition, when appropriate, we review comparable +purchases and sales of oil and gas properties within the same regions, and use +that data as a basis for fair market value; for example, the amount a willing +buyer and seller would enter into an exchange for such +properties. Any excess of purchase price over amounts assigned to +assets and liabilities is recorded as goodwill. The amount of +goodwill recorded in any particular business combination can vary significantly +depending upon the value attributed to assets acquired and liabilities +assumed. In each of our acquisitions it was finally determined that +the purchase price did not exceed the fair value of the net assets +acquired. Therefore, no goodwill was ultimately +recorded. +55 +Table of Contents +In +estimating the fair values of assets acquired and liabilities assumed we made +various assumptions. The most significant assumptions relate to the +estimated fair values assigned to proved developed producing, proved developed +non-producing, proved undeveloped and unproved oil and gas +properties. To estimate the fair values of these properties, we +prepared estimates of oil and gas reserves. We estimated future +prices to apply to the estimated reserve quantities acquired, and estimated +future operating and development costs, to arrive at estimates of future net +revenues. For estimated proved reserves, the future net revenues were +discounted using a market-based weighted average cost of capital rate determined +appropriate at the time of the acquisition. The market-based weighted +average cost of capital rate was subjected to additional project-specific +risking factors. To compensate for the inherent risk of estimating +and valuing unproved properties, the discounted future net revenues of probable +and possible reserves were reduced by additional risk-weighting +factors. +Deferred +taxes must be recorded for any differences between the assigned values and tax +basis of assets and liabilities. Estimated deferred taxes are based +on available information concerning the tax basis of assets acquired and +liabilities assumed and loss carryforwards at the acquisition date, although +such estimates may change in the future as additional information becomes +known. +Recent +Accounting Standards +See Note 1 , Summary of Significant Accounting +Policies - Recent Accounting Standards , to our accompanying consolidated +financial statements. +ITEM 7A . QUANTITATIVE AND QUALITATIVE DISCLOSURE +ABOUT MARKET RISK. +Market-Sensitive +Instruments and Risk Management +We are +exposed to market risks associated with interest rates, commodity prices and +credit exposure. Management has established risk management processes +to monitor and manage these market risks. +See Item +7, Management’s Discussion and Analysis of Financial Condition and Results of +Operation, Critical +Accounting Policies and Estimates-Accounting for Derivatives Contracts at Fair +Value , for +further discussion of the accounting for derivative contracts. +Interest +Rate Risk +We are +exposed to risk resulting from changes in interest rates primarily as it relates +to interest we earn on our cash, cash equivalents and designated cash and +interest we pay on borrowings under our revolving credit +facility. Interest-bearing cash and cash equivalents includes money +market funds, short-term certificates of deposit and checking and savings +accounts with various banks. The amount of interest-bearing cash and +cash equivalents as of December 31, 2007, is $108.5 million with an average +interest rate of 3.69%. +Based on +a sensitivity analysis of the credit facility borrowings as of +December 31, 2007, it was estimated that if market interest rates average 1% +higher (lower) in 2008 than in 2007, interest expense, net of tax, would +increase (decrease) by approximately $1.5 million. On February 8, +2008, we completed the issuance and sale of $203 million aggregate principal +amount of 12% senior notes due 2018. This fixed-price debt +transaction will lower our sensitivity to interest rate +fluctuations. +Commodity Price +Risk +We are +exposed to the effect of market fluctuations in the prices of oil and natural +gas as they relate to our oil and natural gas sales and marketing +activities. Price risk represents the potential risk of loss from +adverse changes in the market price of oil and natural gas +commodities. We employ established policies and procedures to manage +the risks associated with these market fluctuations using commodity +derivatives. Our policy prohibits the use of oil and natural gas +derivative instruments for speculative purposes. +Validation +of a contract’s fair value is performed internally and while we use common +industry practices to develop our valuation techniques, changes in our pricing +methodologies or the underlying assumptions could result in significantly +different fair values. +56 +Table of Contents +Economic Hedging +Strategies. Our results of operations and operating cash flows +are affected by changes in market prices for oil and natural gas. To +mitigate a portion of the exposure to adverse market changes, we have entered +into various derivative instruments. As of December 31, 2007, our oil +and natural gas derivative instruments were comprised of futures, swaps and +collars. These instruments generally consist of NYMEX-traded natural +gas futures contracts and option contracts for Appalachian and Michigan +production, Panhandle-based contracts for NECO production and CIG-based +contracts for other Colorado production and NYMEX-based swaps for our Colorado +and North Dakota oil production. +· +For +swap instruments, we receive a fixed price for the hedged commodity and +pay a floating market price to the counterparty. The +fixed-price payment and the floating-price payment are netted, resulting +in a net amount due to or from the +counterparty. +· +Collars +contain a fixed floor price (put) and ceiling price (call). If +the market price exceeds the call strike price or falls below the fixed +put strike price, we receive the fixed price and pay the market +price. If the market price is between the call and the put +strike price, no payments are due from either +party. +We +purchase puts and set collars for our own and affiliate partnerships’ production +to protect against price declines in future periods while retaining much of the +benefits of price increases. RNG enters into fixed-price physical +purchase and sale agreements that are derivative contracts. In order +to offset these fixed-price physical derivatives, we enter into financial +derivative instruments that have the effect of locking in the prices we will +receive or pay for the same volumes and period, offsetting the physical +derivative. While these derivatives are structured to reduce our +exposure to changes in price associated with the derivative commodity, they also +limit the benefit we might otherwise have received from price changes in the +physical market. We believe our derivative instruments continue to be +highly effective in achieving the risk management objectives for which they were +intended. +The +following table presents monthly average CIG and NYMEX closing prices for +natural gas and oil in 2007 and 2006, as well as average sales prices we +realized for the respective commodity. +Year +Ended December 31, +2007 +2006 +Average +Index Closing Price +Natural +Gas (per MMbtu) +CIG +$ +3.97 +$ +5.63 +NYMEX +6.89 +7.23 +Oil +(per Barrel) +NYMEX +69.79 +64.73 +Average +Sales Price +Natural +Gas +5.33 +5.91 +Oil +60.65 +59.33 +Based on +a sensitivity analysis as of December 31, 2007, it was estimated that a 10% +increase in oil and natural gas prices over the entire period for which we have +derivatives currently in place would have resulted in an increase in unrealized +losses of $7.3 million and a 10% decrease in oil and natural gas prices would +have resulted in a decrease in unrealized losses of $7.3 million. +See Note 1 , Summary of Significant Accounting +Policies , and Note 15 , Derivative Financial +Instruments , to our consolidated financial statements included in this +report for additional disclosure regarding derivative instruments including, but +not limited to, a summary of the open derivative option and purchase and sales +contracts for us and RNG as of December 31, 2007. +Credit Risk +Credit +risk represents the loss that we would incur if a counterparty fails to perform +under its contractual obligations. To reduce credit exposure, we seek +to enter into netting agreements with counterparties that permit us to offset +receivables and payables with such counterparties. We attempt to +further reduce credit risk by diversifying our counterparty exposure and +entering into transactions with high-quality counterparties. Where +exposed to credit risk, we analyze the counterparties’ financial condition prior +to entering into an agreement, establish credit limits and monitor the +appropriateness of those limits on an ongoing basis. There were no +counterparty defaults during the years ended December 31, 2007, 2006 and +2005. +57 +Table of Contents +Disclosure +of Limitations +Because +the information above included only those exposures that exist at December 31, +2007, it does not consider those exposures or positions which could arise after +that date. As a result, our ultimate realized gain or loss with +respect to interest rate and commodity price fluctuations will depend on the +exposures that arise during the period, our hedging strategies at the time, and +interest rates and commodity prices at the time. +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY +DATA +The +response to this Item is set forth herein in a separate section of this Report, +beginning on Page F-1. +Index to financial +statements. +ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS +ON ACCOUNTING AND FINANCIAL DISCLOSURE. +Previous +Independent Registered Public Accounting Firm +As +previously reported on Form 8-K filed with the SEC on May 31, 2007, the Audit +Committee of our Board of Directors recommended, and the Board of Directors +ratified, the dismissal of KPMG LLP, or KPMG, as our principal accountants on +May 24, 2007. +The audit +reports of KPMG on our consolidated financial statements as of and for the years +ended December 31, 2006 and 2005, contained no adverse opinion or disclaimer of +opinion, nor were such reports qualified or modified as to uncertainty, audit +scope or accounting principles, except as follows: +The audit +report of KPMG on our consolidated financial statements as of December 31, 2006, +and for the year then ended, dated May 22, 2007, indicated that, as described in +Note 1, Summary of Significant +Accounting Policies , to such consolidated financial statements, we +adopted the provisions of Statement of Financial Accounting Standards No. +123(R), Share-Based Payment, +and we changed our method of quantifying errors based on SEC Staff +Accounting Bulletin No. 108, Considering the Effects of Prior +Year Misstatements when Quantifying Misstatements in Current Year Financial +Statements , in 2006. +The audit +reports of KPMG on management's assessment of the effectiveness of internal +control over financial reporting and the effectiveness of internal control over +financial reporting as of December 31, 2006 and 2005, did not contain any +adverse opinion or disclaimer of opinion, nor were they qualified or modified as +to uncertainty, audit scope, or accounting principles, except that: +(1) +KPMG's report as of December 31, +2006, includes an explanatory paragraph stating that “The Company acquired +Unioil on December 6, 2006, and management excluded from its assessment of +the effectiveness of the Company's internal control over financial +reporting as of December 31, 2006, Unioil’s internal control over +financial reporting associated with total assets of $26.1 million and +total revenues of $0.3 million included in the consolidated financial +statements of the Company as of and for the year ended December 31, +2006. Our audit of internal control over financial reporting of +the Company also excluded an evaluation of the internal control over +financial reporting of +Unioil.” +(2) +KPMG’s reports indicate that we +did not maintain effective internal control over financial reporting as of +December 31, 2006 and 2005, because of the effect of material weaknesses +on the achievement of the objectives of the control criteria as described +below: +Material Weaknesses as of +December 31, 2006 +· +The +Company did not have effective policies and procedures to ensure the +timely reconciliation, review and adjustment of significant balance sheet +and income statement accounts. As a result, material +misstatements were identified during the Company's closing process in +certain significant balance sheet and income statement accounts of the +Company’s 2006 consolidated financial statements. This +deficiency resulted in a more than remote likelihood that a material +misstatement of the Company’s annual or interim financial statements would +not be prevented or detected. +58 +Table of Contents +· +The +Company did not have effective policies and procedures, or personnel with +sufficient technical expertise to ensure proper accounting for derivative +instruments. Specifically, the Company’s internal control +processes did not ensure the completeness of all derivative contracts +related to oil and gas sales, and also did not ensure the determination of +the fair value of certain derivatives. As a result, +misstatements were identified in the fair value of derivatives and related +income statement accounts of the Company’s 2006 consolidated financial +statements. This deficiency resulted in a more than remote +likelihood that a material misstatement of the Company’s annual or interim +financial statements would not be prevented or +detected. +· +The +Company did not have effective policies and procedures to ensure proper +accounting for oil and gas properties. Specifically, the +Company’s review procedures were not sufficient to ensure that the +calculations of depreciation and depletion were performed accurately and +that the capitalization of costs was performed in accordance with the +applicable authoritative accounting guidance. As a result, +misstatements were identified in 2006 in depreciation, depletion and +amortization expense of the Company’s consolidated financial +statements. This deficiency resulted in a more than remote +likelihood that a material misstatement of the Company’s annual or interim +financial statements would not be prevented or +detected. +Material Weaknesses as of +December 31, 2005 +We did +not have effective policies and procedures, and were not adequately staffed with +accounting personnel possessing an appropriate level of technical expertise in +U.S. generally accepted accounting principles, as further described +below: +· +The +Company did not have effective policies and procedures, or personnel with +sufficient technical expertise, to properly account for derivative +transactions in accordance with generally accepted accounting principles. +Specifically, the Company's policies and procedures relating to +derivatives transactions were not designed effectively to ensure that each +of the requirements for hedge accounting was evaluated appropriately with +respect to the Company's commodity based +derivatives. Additionally, the Company's policies and +procedures relating to the derivative transactions entered into on behalf +of affiliated partnerships were not adequate to ensure these transactions +were recorded properly in the financial statements. As a +result, a misstatement was identified in the fair value of derivatives and +the oil and gas price risk management loss accounts that was corrected +prior to the issuance of the Company's 2005 consolidated financial +statements. This deficiency results in more than a remote +likelihood that a material misstatement of the Company's annual or interim +consolidated financial statements would not be prevented or +detected. +· +The +Company did not have effective policies and procedures, or personnel with +sufficient technical expertise, to ensure compliance with appropriate +accounting principles for its oil and gas +properties. Specifically, the Company's policies and procedures +were not designed effectively to ensure that the calculation of +depreciation and depletion and the determintion of impairments were +performed in accordance with the applicable authoritative accounting +guidance. As a result, misstatements were identified in the +accumulated depreciation, depletion and amortization and the depreciation, +depletion and amortization expense accounts that was corrected prior to +the issuance of the Company's 2005 consolidated financial +statements. This deficiency results in more than a remote +likelihood that a material misstatement of the Company's annual or interim +consolidated financial statements would not be prevented or +detected. +· +The +Company did not have effective policies and procedures, or personnel with +sufficient technical expertise, to ensure proper accounting and disclosure +for income taxes. Specifically, the Company's policies and +procedures did not provide for appropriate control documentation or +supervisory review of permanent and temporary differences, or assessment +of tax reserves to ensure that they were properly reflected and disclosed +in the Company's financial statements. As a result, +misstatements were identified in the deferred income tax liability and +income tax expense accounts in the Company's preliminary 2005 consolidated +financial statements. This deficiency results in more than a +remote likelihood that a material misstatement of the Company's annual or +interim consolidated financial statements would not be prevented or +detected. +59 +Table of Contents +· +The +Company did not have effective policies and procedures, or personnel with +sufficient technical expertise, to ensure that its accounting for asset +retirement obligations complied with generally accepted accounting +principles. Specifically, the Company's policies and procedures regarding +the estimate of the fair value of the asset retirement obligations were +not designed effectively to ensure that it was estimated in accordance +with FAS No. 143, Asset +Retirement Obligations . This deficiency results in more +than a remote likelihood that a material misstatement of the Company's +annual or interim consolidated financial statements would not be prevented +or detected. +· +The +Company did not have effective policies and procedures, or personnel with +sufficient technical expertise, to provide for adequate monitoring and +assessment of the application of accounting principles, standards or rules +as it relates to proportionate consolidation in a timely +manner. As a result of this control deficiency, the Company did +not appropriately eliminate its proportionate share of transactions with +the Company sponsored limited partnerships, which resulted in the +restatement of the Company's financial statements for the first three +quarters of 2005, the years ended December 31, 2004, 2003, 2002, and 2001 +and each of the quarters in 2004 and +2003. +During +the two years ended December 31, 2006, and the subsequent interim period through +May 24, 2007, there were no: 1) disagreements with KPMG on any matter of +accounting principles or practices, financial statement disclosure, or auditing +scope or procedure that, if not resolved to KPMG’s satisfaction, would have +caused KPMG to make reference to the subject matter of the disagreement in +connection with its audit reports on our financial statements for such years, or +2) reportable events, except for the material weaknesses described +above. +KPMG has +been authorized to respond fully to the inquiries of the successor independent +registered public accounting firm concerning the subject matter of the +foregoing. +We +provided KPMG with a copy of the foregoing statements and requested that KPMG +furnish us with a letter addressed to the Securities and Exchange Commission +stating whether KPMG agreed with the foregoing statements, and, if not, stating +the respects in which KPMG did not agree. The letter from KPMG is +attached as Exhibit 16 to our Form 8-K filed with the SEC on May 31, +2007. +New +Independent Registered Public Accounting Firm +As +previously reported on Form 8-K filed with the SEC on May 31, 2007, the Audit +Committee of our Board of Directors recommended and the Board of Directors +ratified the engagement of PricewaterhouseCoopers LLP, or PwC, as our +independent registered public accounting firm the fiscal year ending December +31, 2007. +During +our two most recent fiscal years ended December 31, 2006 and 2005, and through +May 24, 2007, we did not consult with PwC regarding either (i) the application +of accounting principles to a specified transaction, either completed or +proposed, or the type of audit opinion that might be rendered on our financial +statements, and neither a written report was provided to us nor oral advice was +provided that PwC concluded was an important factor considered by us in reaching +a decision as to any of the accounting, auditing or financial reporting issues; +or (ii) any matter that was either the subject of a disagreement, as that term +is defined in paragraph 304(a)(1)(iv) of Regulation S-K, or a reportable event +required to be reported under paragraph 304(a)(1)(v) of Regulation +S-K. +ITEM 9A . CONTROLS AND PROCEDURES +Evaluation +of Disclosure Controls and Procedures +As of +December 31, 2007, we carried out an evaluation, under the supervision and with +the participation of our management, including our Chief Executive Officer and +Chief Financial Officer, of the effectiveness of the design and operation of our +disclosure controls and procedures pursuant to Securities Exchange Act Rule +13a-15(e). Based upon that evaluation, our Chief Executive Officer +and Chief Financial Officer concluded that our disclosure controls and +procedures were not effective as of December 31, 2007, to ensure that the +information required to be disclosed by the Company in the reports that we file +or submit under the Exchange Act is recorded, processed, summarized and +reported, within the time periods specified in the SEC rules and forms, and that +the information is accumulated and communicated to our management, including our +Chief Executive Officer and Chief Financial Officer, as appropriate to all +timely decisions regarding required disclosure, due to the existence of material +weaknesses described in Management’s Report on Internal +Control Over Financial Reporting included in Item 8 of this +report. +60 +Table of Contents +Changes +in Internal Control over Financial Reporting +We have +made the following changes in our internal control over financial reporting (as +such term is defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange +Act of 1934) during the quarter ended December 31, 2007, that have materially +affected or are reasonably likely to materially affect our internal control over +financial reporting. +· +Installed +new software supporting our derivative valuation process. The +new system enhanced the existing internal controls framework over +reporting more accurate information by automating a previously manual +control. +During +the third quarter of 2007, and continuing through the filing of this report, we +made the following changes in our internal control over financial reporting that +has materially affected, or is reasonably likely to materially affect our +internal controls over financial reporting: +· +Installed +new software supporting our accounts payable process as part of a broader +financial reporting system implementation. The new system +enhanced the existing internal control framework over accounts payable and +cash distribution process by automating several of the previously manual +controls. +Additionally, +during the first quarter of 2007, and continuing through the filing of this +report, we implemented the following changes in internal control over financial +reporting: +· +Reinforced +reconciliation procedures to ensure the timely reconciliation, review and +adjustments to significant balance sheet and income statement +accounts; +· +Developed +and approved extensive policies and procedures concerning the controls +over financial reporting for +derivatives; +· +Provided +additional training regarding derivatives for key personnel; +and +· +Developed +a review process to ensure proper accounting for oil and gas properties, +specifically the capitalization of costs and calculation of depreciation +and depletion. +We +continue to evaluate the ongoing effectiveness and sustainability of the changes +we have made in internal control, and, as a result of the ongoing evaluation, +may identify additional changes to improve internal control over financial +reporting. +ITEM 9B. OTHER INFORMATION +None. +PART +III +ITEM +10. DIRECTORS , EXECUTIVE OFFICERS AND CORPORATE +GOVERNANCE +The +information called for by Item 10 is incorporated by reference from information +under the captions entitled Corporate Governance , Section 16(a) Beneficial Ownership +Reporting Compliance , Election of Directors and +Executive Compensation +and other relevant portions of our definitive proxy statement to be filed +pursuant to Regulation 14A no later than 120 days after the close of our fiscal +year. +ITEM 11. EXECUTIVE COMPENSATION +The information called for by Item 11 +is incorporated by reference from information under the caption entitled Executive Compensation and +other relevant portions of our definitive proxy statement to be filed pursuant +to Regulation 14A no later than 120 days after the close of our fiscal +year. +ITEM 12 . SECURITY OWNERSHIP OF CERTAIN BENEFICIAL +OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +The +information called for by Item 12 is incorporated by reference from information +under the caption entitled Security Ownership of Certain +Beneficial Owners and Management and Related Stockholder Matters and +other relevant portions of our definitive proxy statement to be filed pursuant +to Regulation 14A no later than 120 days after the close of our fiscal +year. +61 +Table of Contents +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED +TRANSACTIONS AND DIRECTOR INDEPENDENCE +The +information called for by Item 13 is incorporated by reference from information +under the captions entitled Certain Relationships and Related +Transactions and +Director Independence in our definitive proxy statement to be +filed pursuant to Regulation 14A no later than 120 days after the close of our +fiscal year. +ITEM 14. PRINCIPAL ACCOUNTANT FEES AND +SERVICES +The +information called for by Item 14 is incorporated by reference from information +under caption entitled Principal Accountant Fees and +Services and other relevant portions of our definitive proxy +statement to be filed pursuant to Regulation 14A no later than 120 days after +the close of our fiscal year. +62 +Table of Contents +PART +IV +ITEM 15. EXHIBITS , FINANCIAL STATEMENT +SCHEDULES +(a) +(1) +Financial +Statements: +See +Index to +Financial Statements and Schedules on page +F-1. +(2) +Financial +Statement Schedules: +See +Index to +Financial Statements and Schedules on page +F-1. +Schedules +and Financial Statements Omitted +All other +financial statement schedules are omitted because they are not required, +inapplicable, or the information +is included in the Financial Statements or Notes thereto. +(3) +Exhibits: +See Exhibits Index on +page 67. +63 +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. +PETROLEUM +DEVELOPMENT CORPORATION +By +/s/ +Steven R. Williams +Steven +R. Williams, +Chairman +and Chief Executive Officer +March +20, 2008 +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/ Steven R. +Williams +Chairman, +Chief Executive Officer and Director +Steven +R. Williams +(principal +executive officer) +March +20, 2008 +/s/ Richard W. +McCullough +President, +Chief Financial Officer and Director +March +20, 2008 +Richard +W. McCullough +(principal +financial officer) +/s/ Darwin L. +Stump +Chief +Accounting Officer +March +20, 2008 +Darwin +L. Stump +(principal +accounting officer) +/s/ Daniel W. +Amidon +Daniel +W. Amidon +General +Counsel, Corporate Secretary +March +20, 2008 +/s/ Jeffrey C. +Swoveland +Jeffrey +C. Swoveland +Director +March +20, 2008 +/s/ Vincent F. +D'Annunzio +Vincent +F. D'Annunzio +Director +March +20, 2008 +/s/ Kimberly Luff +Wakim +Kimberly +Luff Wakim +Director +March +20, 2008 +/s/ David C. +Parke +David +C. Parke +Director +March +20, 2008 +/s/ Anthony +J. Crisafio +Anthony +J. Crisafio +Director +March +20, 2008 +/s/ Joseph +E. Casabona +Joseph +E. Casabona +Director +March +20, 2008 +/s/ Larry +F. Mazza +Larry +F. Mazza +Director +March +20, 2008 +64 +Table of Contents +GLOSSARY OF OIL AND NATURAL GAS TERMS +The +following are abbreviations and definitions of terms commonly used in the oil +and gas industry and this Form 10-K. +Bbl +- One barrel or 42 U.S. gallons of liquid volume. +Bcf +- One billion cubic feet. +Bcfe +- One billion cubic feet of natural gas equivalents. +Completion +- The installation of permanent equipment for the production of oil or +gas. +DD&A - Refers to depreciation, +depletion and amortization of our property and equipment. +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 hydrocarbons in +sufficient quantities to justify completion as an oil or gas +well. +Exploratory +well - A well drilled to find and produce oil or natural gas reserves not +classified as proved, to find a new productive reservoir in a field previously +found to be productive of oil or natural gas in another reservoir or to extend a +known reservoir. +Extensions and discoveries - +As to any period, the increases to proved reserves from all sources other than +the acquisition of proved properties or revisions of previous +estimates. +Gross +acres or wells - Refers to the total acres or wells in which we have a +working interest. +Horizontal +drilling - A drilling technique that permits the operator to contact and +intersect a larger portion of the producing horizon than conventional vertical +drilling techniques and may, depending on the horizon, result in increased +production rates and greater ultimate recoveries of +hydrocarbons. +MBbls - One thousand +barrels. +Mcf - One thousand cubic +feet. +Mcfe - One thousand cubic feet +of natural gas equivalents, based on a ratio of 6 Mcf for each barrel of oil, +which reflects the relative energy content. +MMbtu - One million British +thermal units. One British thermal unit is the heat required to raise +the temperature of a one-pound mass of water from 58.5 to 59.5 degrees +Fahrenheit. +MMcf +- One million cubic feet. +MMcfe - One million cubic feet of +natural gas equivalents. +Natural +gas liquids - Liquid hydrocarbons that have been extracted from natural +gas, such as ethane, propane, butane and natural gasoline. +Net acres +or wells - Refers to gross acres or wells multiplied, in each case, by +the percentage working interest we own. +Net +production - Oil and gas production that we own, less royalties and +production due others. +NYMEX +- New York Mercantile Exchange, the exchange on which commodities, including +crude oil and natural gas futures contracts, are traded. +Oil +- Crude oil or condensate. +Operator +- The individual or company responsible for the exploration, development and +production of an oil or gas well or lease. +65 +Table of Contents +Present value of proved +reserves - The present value of estimated future revenues, discounted at +10% annually, to be generated from the production of proved reserves determined +in accordance with Securities and Exchange Commission guidelines, net of +estimated production and future development costs, using prices and costs as of +the date of estimation without future escalation, without giving effect to (i) +estimated future abandonment costs, net of the estimated salvage value of +related equipment, (ii) non-property related expenses such as general and +administrative expenses, debt service and future income tax expense, or (iii) +depreciation, depletion and amortization. +Proved developed non-producing +reserves - Reserves that consist of (i) proved reserves from wells which +have been completed and tested but are not producing due to lack of market or +minor completion problems which are expected to be corrected and (ii) proved +reserves currently behind the pipe in existing wells and which are expected to +be productive due to both the well log characteristics and analogous production +in the immediate vicinity of the wells. +Proved developed producing +reserves - +Proved reserves that can be expected to be recovered from currently +producing zones under the continuation of present operating +methods. +Proved +developed reserves - +The combination of proved developed producing and proved developed +non-producing reserves. +Proved +reserves - 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, i.e., prices and costs as of +the date the estimate is made. Prices include consideration of +changes in existing prices provided only by contractual arrangements, but not on +escalations based upon future conditions. +Proved +undeveloped reserves , or +PUD - Proved 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 +- A recompletion occurs when we reenter a well to complete (i.e., perforate) a +new formation different from that in which a well has previously been +completed. +Refrac, +or refracture – A refrac is when we stimulate the present producing zone +of a well to increase production, using hydraulic, acid, gravel, etc. fracture +techniques. +Reserve +replacement - Calculated by dividing the sum of reserve additions fro all +sources (revisions, extensions, discoveries and other additions and +acquisitions) by the actual production for the corresponding +period. The values used for reserve additions are derived directly +from the proved reserves table located in Note 20 , Supplemental Oil and Gas +information , to our consolidated financial statements included in this +report. We use the reserve replacement ratio as an indicator of our +ability to replenish annual production volumes and grow our reserves, thereby +providing some information on the sources of future production. It +should be noted that the reserve replacement ratio is a statistical indicator +that has limitations. As an annual measure, the ratio limited because +it typically varies widely based on the extent and timing of new discoveries and +property acquisitions. Its predictive and comparative value is also +limited for the same reasons. In addition, since the ratio does not +imbed the cost or timing of future production of new reserves, it cannot be used +as a measure of value creation. +Royalty +- An interest in an oil and gas lease that gives the owner of the interest the +right to receive a portion of the production from the leased acreage (or of the +proceeds of the sale thereof), but generally does not require the owner to pay +any portion of the costs of drilling or operating the wells on the leased +acreage. Royalties may be either landowner’s royalties, which are +reserved by the owner of the leased acreage at the time the lease is granted, or +overriding royalties, which are usually reserved by an owner of the leasehold in +connection with a transfer to a subsequent owner. +Standardized +measure of discounted future net cash flows - Present value of proved +reserves, as adjusted to give effect to (i) estimated future abandonment costs, +net of the estimated salvage value of related equipment, and (ii) estimated +future income taxes. +Undeveloped +acreage - Leased 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 proved +reserves. +Working +interest - An interest in an oil and gas lease that gives the owner of +the interest the right to drill for and produce oil and gas on the leased +acreage and requires the owner to pay a share of the costs of drilling and +production operations. The share of production to which a working +interest is entitled will be smaller than the share of costs that the working +interest owner is required to bear to the extent of any royalty +burden. +Workover +- Operations on a producing well to restore or increase +production. +66 +Table of Contents +Exhibits +Index +Exhibit +No. +Description +3.1 +Amended +and Restated Certificate of Incorporation of Petroleum Development +Corporation, filed herewith. +3.2 +Bylaws +of Petroleum Development Corporation, amended and restated effective +October 11, 2007, incorporated by reference to Exhibit 3.2 to Form 8-K +filed on October 17, 2007. +4.1 +Rights +Agreement by and between Petroleum Development Corporation and Transfer +Online, Inc., as Rights Agent, dated as of September 11, 2007, including +the forms of Rights Certificates and Summary of Stockholder Rights Plan +attached thereto as Exhibits A and B, incorporated by reference to Exhibit +4.1 to Form 8-K filed September 14, 2007. +4.2 +Indenture +dated as of February 8, 2008, by and among Petroleum Development +Corporation and The Bank of New York, incorporated by reference to Exhibit +4.1 to Form 8-K filed on February 12, 2008. +4.3 +First +Supplemental Indenture dated as of February 8, 2008, by and among +Petroleum Development Corporation and the Bank of New York, incorporated +by reference to Exhibit 4.2 to Form 8-K filed on February 12, +2008. +4.4 +Form +of 12% Senior Note due 2018, incorporated by reference to Exhibit 4.2 to +Form 8-K filed on February 12, 2008. +10.1 +Amended +and Restated Credit Agreement, dated as of November 4, 2005, Petroleum +Development Corporation, as borrower and JPMorgan Chase Bank, N.A and BNP +Paribas, as lenders, incorporated by reference to Exhibit 10.2 to Form 8-K +dated November 4, 2005. +10.2 +First +Amendment to Amended and Restated Credit Agreement, dated as of August 9, +2007, by an among Petroleum Development Corporation, certain of its +subsidiaries, JPMorgan Chase Bank, N.A., BNP Paribas and Wachovia Bank, +N.A., incorporated by reference to Exhibit 10.1 to Form 8-K filed August +15, 2007. +10.3 +Second +Amendment to Amended and Restated Credit Agreement, dated as of October +16, 2007, by and among Petroleum Development Corporation, certain of its +subsidiaries, JPMorgan Chase Bank, N.A., BNP Paribas, Wachovia Bank, N.A., +Guaranty Bank, FSB, Bank of Oklahoma and Morgan Stanley Bank, incorporated +by reference to Exhibit 10.1 to Form 8-K filed October 22, +2007. +10.4 +Limited +Consent and Waiver, Borrowing Base Increase and Aggregate Revolving +Commitment Increase relating to the Amended and Restated Credit Agreement, +dated as of November 21, 2007, by and among Petroleum Development +Corporation, certain of its subsidiaries, JPMorgan Chase Bank, N.A., BNP +Paribas, Wachovia Bank, N.A., Guaranty Bank, FSB, Bank of Oklahoma and +Morgan Stanley Bank, incorporated by reference to Exhibit 10.1 to Form 8-K +filed November 28, 2007. +10.5 +Employment +Agreement with Steven R. Williams, Chief Executive Officer and Chairman, +dated as of March 7, 2003 and amended December 29, 2005, incorporated by +reference in Exhibit 10.2 to Form 10-K filed on March 7, 2003 +and Exhibit 99.1 to Form 8-K filed January 4, 2006. +10.6 +Employment +Agreement with Darwin L. Stump, Chief Accounting Officer, dated as of +January 5, 2004 and amended December 29, 2005, incorporated by reference +to Exhibit 99.4 Form 10-K dated January 5, 2004, and Exhibit 99.4 to Form +8-K filed January 4, 2006. +10.7 +Employment +Agreement with Thomas E. Riley, President, dated as of January 5, 2004, +and amended December 29, 2005, incorporated by reference to Exhibit 99.6 +Form 10-K dated January 5, 2004, and Exhibit 99.2 to Form 8-K filed +January 4, 2006. +10.8 +Employment +Agreement with Eric R. Stearns, Executive Vice President, dated as of +January 5, 2004, and amended December 29, 2005, incorporated by reference +to Exhibit 99.5 Form 10-K dated January 5, 2004, and Exhibit 99.3 to Form +8-K filed January 4, 2006. +67 +Table of Contents +10.9 +Employment +Agreement with Richard W. McCullough, Chief Financial Officer, dated as of +November 13, 2006, incorporated by reference to Exhibit 10.6 to Form 10-K +filed on May 23, 2007. +10.10 +The +Petroleum Development Corporation 401(k) & Profit Sharing Plan, +incorporated by reference to Exhibit 4.1 to Form S-8, SEC File No. +333-137836. +10.11 +2007 +Compensation Arrangements with Executive Officers, incorporated by +reference to Form 8-K dated February 20, 2007. +10.12 +2007 +Long-Term Incentive Program, incorporated by reference to Exhibit 10.1 to +Form 8-K dated February 20, 2007 +10.13 +2007 +Short-Term Incentive Program, incorporated by reference to Form 8-K dated +April 2, 2007. +10.14 +2005 +Non-Employee Director Restricted Stock Plan, incorporated by reference to +Exhibit 99.1 to Form S-8, SEC File No. 333-126444 filed on July 7, +2005. +10.15 +2004 +Long-Term Equity Compensation Plan, incorporated by reference to Exhibit +99.1 to Form S-8, SEC File No. 333-118215, filed on August 13, +2004. +10.16 +Non-Employee +Director Deferred Compensation Plan, incorporated by reference Exhibit +99.1 to Form S-8, SEC File No. 333-118222, filed on August 13, +2004. +10.17 +1999 +Incentive Stock Option and Non-Qualified Stock, incorporated by reference +to Exhibit 99.1 to Form S-8, SEC File No. 333-111825, filed on January 9, +2004. +10.18 +Indemnification +Agreement with Directors and Officers, incorporated by reference to +Exhibit 10.1 to Form 10-Q filed August 9, 2007. +10.19 +2007 +Long-Term Incentive Program, incorporated by reference to Exhibit 10.1 to +Form 8-K filed on April 13, 2007. +10.20 +2006 +Long-Term Equity Compensation Grants to Executive Officers, incorporated +by reference to Form 8-K filed on April 10, 2007. +10.21 +Purchase +and Sale Agreement by and between Petroleum Development Corporation and +Marathon Oil Company dated July 20, 2006, incorporated by reference to +Exhibit 10.1 to Form 10-Q filed on August 8, 2006. +10.22 +Purchase +and Sale Agreement between EXCO Resources, Inc., as Seller, and Petroleum +Development Corporation, as Buyer, dated effective October 1, 2006, +incorporated by reference to Exhibit 10.1 to Form 8-K filed on January 11, +2007. +10.23 +Purchase +Agreement dated as of February 1, 2008, by and among Petroleum Development +Corporation and the Initial Purchasers of 12% senior notes due 2018 named +therein, incorporated by reference to Exhibit 10.1 to Form 8-K filed on +February 7, 2008 +10.24 +Registration +Rights Agreement dated as of February 8, 2008, by and among Petroleum +Development Corporation and the Initial Purchasers of 12% senior notes due +2018 named therein, incorporated by reference to Exhibit 10-1 to Form 8-K +filed on February 12, 2008. +14.1 +Code +of Business Conduct and Ethics, incorporated by reference to Exhibit 3.1 +to Form 10-K for the year ended December 31, 2002, SEC File No. 0-07246 +filed on March 7, 2003. +21.1 +Subsidiaries, +filed herewith. +23.1 +Consent +of PricewaterhouseCoopers LLP, filed herewith. +23.2 +Consent +of KPMG LLP, filed herewith. +23.3 +Consent +of Wright & Company, Inc., Petroleum Consultants, filed +herewith. +23.4 +Consent +of Ryder Scott Company, L.P., Petroleum Consultants, filed +herewith. +68 +Table of Contents +31.1 +Certification +by Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the +Exchange Act Rules, as adopted pursuant to Section 302 of the +Sarbanes-Oxley Act of 2002, filed herewith. +31.2 +Certification +by Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the +Exchange Act Rules, as adopted pursuant to Section 302 of the +Sarbanes-Oxley Act of 2002, filed herewith. +32.1 +Certifications +by Chief Executive Officer and Chief Financial Officer pursuant to Title +18 U.S.C. Section 1350, as adopted pursuant to Section 906 of +Sarbanes-Oxley Act of 2002, filed +herewith. +69 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +Index +to Consolidated Financial Statements and Financial Statement +Schedule +Management's Report on Internal Control Over +Financial Reporting +F-2 +Financial +Statements: +Reports of Independent Registered Public +Accounting Firms +F-3 +Consolidated Balance Sheets - December 31, 2007 +and 2006 +F-5 +Consolidated Statements of Income - Years Ended +December 31, 2007, 2006 and 2005 +F-6 +Consolidated Statements of Shareholders' Equity - +Years Ended December 31, 2007, 2006 and 2005 +F-7 +Consolidated Statements of Cash Flows - Years +Ended December 31, 2007, 2006 and 2005 +F-8 +Notes to Consolidated Financial +Statements +F-9 +Financial +Statement Schedule: +Schedule +II – Valuation and Qualifying Accounts and +Reserves +F-46 +F-1 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +Management's Report on +Internal Control Over Financial Reporting +Management +is responsible for establishing and maintaining adequate internal control over +financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) of +the Exchange Act. 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. 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 policies +or procedures may deteriorate. +Management +has assessed the effectiveness of the Company’s internal control over financial +reporting as of December 31, 2007, based upon the criteria established in +“Internal Control – Integrated Framework” issued by the Committee of Sponsoring +Organizations of the Treadway Commission (“COSO”). Based on this +evaluation, management concluded that the Company did not maintain effective +internal control over financial reporting as of December 31, 2007 because of the +material weaknesses discussed below. A material weakness is a +deficiency, or a combination of deficiencies, in internal control over financial +reporting, such that there is a reasonable possibility that a material +misstatement of the Company's annual or interim financial statements will not be +prevented or detected on a timely basis. The Company’s assessment, as +of December 31, 2007, identified the following material weaknesses: +· +The +Company did not maintain effective controls to ensure the completeness, +accuracy, validity and restricted access of certain key financial +statement spreadsheets that support all significant balance sheet and +income statement accounts. Specifically, the Company has +inadequate controls over: 1) the security and integrity of the data used +in the various spreadsheets, 2) access to the spreadsheets, 3) changes to +spreadsheet functionality and the related approval process and +documentation, and 4) management's review of the +spreadsheets. These spreadsheets are used in the financial +close and reporting process to perform calculations, generate financial +data supporting all significant processes and key manual controls, and to +compile information to post entries into the general ledger +system. This control deficiency resulted in an audit adjustment +to the Company's consolidated financial statements for the year ended +December 31, 2007. This control deficiency could result in a +misstatement of any of our financial statement accounts and disclosures +that would result in a material misstatement of the annual or interim +financial statements that would not be prevented or detected in a timely +manner. +· +The +Company did not have effective policies and procedures, or personnel with +sufficient technical expertise to record derivative activities in +accordance with generally accepted accounting +principles. Specifically, the Company’s internal control +processes did not ensure the completeness and accuracy of the derivative +activities in the fourth quarter. The lack of documented +policies and procedures, and the turnover in key personnel, including +ineffective management review process, resulted in an audit adjustment to +the Company's consolidated financial statements for the year ended +December 31, 2007. This control deficiency could result in a +misstatement of any of our derivative financial statement accounts and +disclosures that would result in a material misstatement of the annual or +interim financial statements that would not be prevented or detected in a +timely manner. +The +effectiveness of Petroleum Development Corporation's internal control over +financial reporting as of December 31, 2007, has been audited by +PricewaterhouseCoopers LLP, an independent registered public accounting firm, as +stated in their report which appears herein. +PETROLEUM +DEVELOPMENT CORPORATION +/s/ +Steven R. Williams +Steven +R. Williams +Chairman +and Chief Executive Officer +/s/ +Richard W. McCullough +Richard +W. McCullough +President +and Chief Financial Officer +F-2 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +Report of Independent +Registered Public Accounting Firm +To the +Board of Directors and Shareholders +of +Petroleum Development Corporation +In our +opinion, the consolidated financial statements listed in the accompanying index +present fairly, in all material respects, the financial position of Petroleum +Development Corporation and its subsidiaries at December 31, 2007, and the +results of their operations and their cash flows for the year then ended +December 31, 2007 in conformity with accounting principles generally accepted in +the United States of America. In addition, in our opinion, the +financial statement schedule listed in the accompanying index presents fairly, +in all material respects, the information set forth therein when read in +conjunction with the related consolidated financial statements. Also +in our opinion, the Company did not maintain, in all material respects, +effective internal control over financial reporting 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 (COSO) +because material weaknesses in internal control over financial reporting related +to spreadsheets used in the financial reporting process and accounting for +derivative activities existed as of that date. A material weakness is +a deficiency, or a combination of deficiencies, in internal control over +financial reporting, such that there is a reasonable possibility that a material +misstatement of the annual or interim financial statements will not be prevented +or detected on a timely basis. The material weaknesses referred to above are +described in the accompanying Management's Report on Internal Control Over +Financial Reporting. We considered these material weaknesses in +determining the nature, timing, and extent of audit tests applied in our audit +of the 2007 consolidated financial statements, and our opinion regarding the +effectiveness of the Company’s internal control over financial reporting does +not affect our opinion on those consolidated financial +statements. The Company's management is responsible for these +financial statements and financial statement schedule, for maintaining effective +internal control over financial reporting and for its assessment of the +effectiveness of internal control over financial reporting included in +management's report referred to above. Our responsibility is to +express opinions on these financial statements, on the financial statement +schedule, and on the Company's internal control over financial reporting based +on our integrated 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 and whether effective internal control over financial +reporting was maintained in all material respects. Our audit of the +financial statements included examining, on a test basis, evidence supporting +the amounts and disclosures in the financial statements, assessing the +accounting principles used and significant estimates made by management, and +evaluating the overall financial statement presentation. Our audit of +internal control over financial reporting included obtaining an understanding of +internal control over financial reporting, assessing the risk that a material +weakness exists, and testing and evaluating the design and operating +effectiveness of internal control based on the assessed risk. Our +audit also included performing such other procedures as we considered necessary +in the circumstances. We believe that our audit provides a reasonable basis for +our opinions. +As +discussed in Note 6 to the consolidated financial statements, the Company +changed the manner in which it accounts for uncertain tax positions in +2007. +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 (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 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. +/s/ +PricewaterhouseCoopers LLP +Pittsburgh, +Pennsylvania +March 20, +2008 +F-3 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +Report of Independent +Registered Public Accounting Firm +The Board +of Directors and Shareholders +Petroleum +Development Corporation: +We have +audited the accompanying consolidated balance sheet of Petroleum Development +Corporation and subsidiaries as of December 31, 2006, and the related +consolidated statements of income, shareholders' equity, and cash flows for each +of the years in the two-year period ended December 31, 2006. In connection with +our audits of the consolidated financial statements, we also have audited the +related financial statement schedule. These consolidated financial statements +and financial statement schedule are the responsibility of the Company's +management. Our responsibility is to express an opinion on these consolidated +financial statements and financial statement schedule 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, the consolidated financial statements referred to above present fairly, +in all material respects, the financial position of Petroleum Development +Corporation and subsidiaries as of December 31, 2006, and the results of their +operations and their cash flows for each of the years in the two-year period +ended December 31, 2006, in conformity with U. S. generally accepted accounting +principles. Also in our opinion, the related financial statement schedule, when +considered in relation to the basic consolidated financial statements taken as a +whole, presents fairly, in all material respects, the information set forth +therein. +As +discussed in Note 1 to the consolidated financial statements, the Company +adopted the provisions of Statement of Financial Accounting Standards No. +123(R), (“Share-Based Payment”), in 2006. +As +discussed in Note 1 to the consolidated financial statements, the Company +changed its method of quantifying errors based on SEC Staff Accounting Bulletin +No. 108 (“Considering the Effects of Prior Year Misstatements when Quantifying +Misstatements in Current Year Financial Statements”) in 2006. +KPMG +LLP +Pittsburgh, +Pennsylvania +May 22, +2007 +F-4 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +Consolidated +Balance Sheets +(in +thousands, except share and per share data) +December +31, +2007 +2006 +Assets +Current +assets: +Cash +and cash equivalents +$ +84,751 +$ +194,326 +Restricted +cash - current +14,773 +519 +Accounts +receivable, net +60,024 +42,600 +Accounts +receivable - affiliates +11,537 +9,235 +Inventories +2,248 +3,345 +Fair +value of derivatives +4,817 +15,012 +Other +current assets +13,643 +5,977 +Total +current assets +191,793 +271,014 +Properties +and equipment, net +845,864 +394,217 +Restricted +cash - long term +1,294 +192,451 +Goodwill +- +6,783 +Other +assets +11,528 +19,822 +Total +Assets +$ +1,050,479 +$ +884,287 +Liabilities +and Shareholders' Equity +Current +liabilities: +Accounts +payable +$ +88,502 +$ +67,675 +Accounts +payable - affiliates +3,828 +7,595 +Short +term debt +- +20,000 +Production +tax liability +21,330 +11,497 +Other +accrued expenses +12,913 +9,685 +Deferred +gain on sale of leaseholds +- +8,000 +Federal +and state income taxes payable +901 +28,698 +Fair +value of derivatives +6,291 +2,545 +Advances +for future drilling contracts +68,417 +54,772 +Funds +held for distribution +39,823 +31,367 +Total +current liabilities +242,005 +241,834 +Long-term +debt +235,000 +117,000 +Deferred +gain on sale of leaseholds +- +17,600 +Other +liabilities +19,968 +19,400 +Deferred +income taxes +136,490 +116,393 +Asset +retirement obligation +20,731 +11,916 +Total +liabilities +654,194 +524,143 +Commitments +and contingent liabilities +Minority +interest in consolidated limited liability company +759 +- +Shareholders' +equity: +Common +shares, par value $.01 per share; authorized 50,000,000 shares; issued +14,907,679 in 2007 and 14,834,871 in 2006 +149 +148 +Additional +paid-in capital +2,559 +64 +Retained +earnings +393,044 +360,102 +Treasury +shares at cost, 5,894 shares in 2007 and 4,706 in 2006 +(226 +) +(170 +) +Total +shareholders' equity +395,526 +360,144 +Total +Liabilities and Shareholders' Equity +$ +1,050,479 +$ +884,287 +See accompanying Notes to +Consolidated Financial Statements . +F-5 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +Consolidated +Statements of Income +(in +thousands, except per share data) +Year +Ended December 31, +2007 +2006 +2005 +Revenues: +Oil +and gas sales +$ +175,187 +$ +115,189 +$ +102,559 +Sales +from natural gas marketing activities +103,624 +131,325 +121,104 +Oil +and gas well drilling operations +12,154 +17,917 +99,963 +Well +operations and pipeline income +9,342 +10,704 +8,760 +Oil +and gas price risk management gain (loss), net +2,756 +9,147 +(9,368 +) +Other +2,172 +2,221 +2,180 +Total +revenues +305,235 +286,503 +325,198 +Costs +and expenses: +Oil +and gas production and well operations cost +49,264 +29,021 +20,400 +Cost +of natural gas marketing activities +100,584 +130,150 +119,644 +Cost +of oil and gas well drilling operations +2,508 +12,617 +88,185 +Exploration +expense +23,551 +8,131 +11,115 +General +and administrative expense +30,968 +19,047 +6,960 +Depreciation, +depletion, and amortization +70,844 +33,735 +21,116 +Total +costs and expenses +277,719 +232,701 +267,420 +Gain +on sale of leaseholds +33,291 +328,000 +7,669 +Income +from operations +60,807 +381,802 +65,447 +Interest +income +2,662 +8,050 +898 +Interest +expense +(9,279 +) +(2,443 +) +(217 +) +Income +before income taxes +54,190 +387,409 +66,128 +Provision +for income taxes +20,981 +149,637 +24,676 +Net +income +$ +33,209 +$ +237,772 +$ +41,452 +Basic +earnings per common share +$ +2.25 +$ +15.18 +$ +2.53 +Diluted +earnings per common share +$ +2.24 +$ +15.11 +$ +2.52 +See accompanying Notes to +Consolidated Financial Statements . +F-6 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +Consolidated +Statements of Shareholders' Equity +(in +thousands, except per share data) +Year +Ended December 31, +2007 +2006 +2005 +Common +stock, par value $.01 per share - shares issued: +Shares +at beginning of year +14,834,871 +16,281,923 +16,589,824 +Adjust +prior conversion of predecessor shares +- +59,546 +- +Exercise +of stock options +38,000 +8,000 +3,000 +Issuance +of stock awards, net of forfeitures +46,828 +112,902 +20,895 +Retirement +of treasury shares +(12,020 +) +(1,627,500 +) +(331,796 +) +Shares +at end of year +14,907,679 +14,834,871 +16,281,923 +Treasury +stock: +Shares +at beginning of year +(4,706 +) +- +- +Purchase +of treasury shares +(12,020 +) +(1,627,500 +) +(331,796 +) +Retirement +of treasury shares +12,020 +1,627,500 +331,796 +Non-employee +directors' deferred compensation plan +(1,188 +) +(4,706 +) +- +Shares +at end of year +(5,894 +) +(4,706 +) +- +Common +shares outstanding +14,901,785 +14,830,165 +16,281,923 +Common +stock, $.01 par: +Balance +at beginning of year +$ +148 +$ +163 +$ +166 +Exercise +of stock options +- +- +- +Issuance +of stock awards, net of forfeitures +1 +1 +- +Retirement +of treasury shares +- +(16 +) +(3 +) +Balance +at end of year +149 +148 +163 +Additional +paid-in capital: +Balance +at beginning of year +64 +30,423 +37,684 +Reclassification +of unearned compensation pursuant to the adoption of SFAS No. +123(R) +- +(825 +) +- +Exercise +of stock options +183 +31 +12 +Issuance +of stock awards, net of forfeitures +(1 +) +(1 +) +- +Stock +based compensation expense +2,286 +1,516 +603 +Retirement +of treasury shares +(646 +) +(31,150 +) +(7,876 +) +Excess +tax benefit of stock based compensation +673 +70 +- +Balance +at end of year +2,559 +64 +30,423 +Retained +earnings: +Balance +at beginning of year +360,102 +158,504 +117,052 +Cumulative +effect adjustment for the adoption of SAB 108, net of tax +- +(1,021 +) +- +FIN +48 adoption +(267 +) +- +- +Retirement +of treasury shares +- +(35,153 +) +- +Net +income +33,209 +237,772 +41,452 +Balance +at end of year +393,044 +360,102 +158,504 +Unamortized +stock award +Balance +at beginning of year +- +(825 +) +(882 +) +Issuance +of stock awards +- +- +(603 +) +Amortization +of stock awards +- +- +660 +Reclassification +of unearned compensation pursuant to the adoption of SFAS No. +123(R) +- +825 +- +Balance +at end of year +- +- +(825 +) +Treasury +stock, at cost: +Balance +at beginning of year +(170 +) +- +- +Purchase +of treasury shares +(646 +) +(66,319 +) +(7,879 +) +Retirement +of treasury shares +646 +66,319 +7,879 +Non-employee +directors' deferred compensation plan +(56 +) +(170 +) +- +Balance +at end of year +(226 +) +(170 +) +- +Total +shareholders' equity +$ +395,526 +$ +360,144 +$ +188,265 +See accompanying Notes to +Consolidated Financial Statements . +F-7 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +Consolidated +Statements of Cash Flows +(in +thousands) +Year +Ended December 31, +2007 +2006 +2005 +Cash +flows from operating activities: +Net +income +$ +33,209 +$ +237,772 +$ +41,452 +Adjustments +to net income to reconcile to net cash provided by operating +activities: +Deferred +income taxes +12,201 +86,431 +3,351 +Depreciation, +depletion and amortization +70,844 +33,735 +21,116 +Amortization +of debt issuance costs +394 +- +- +Impairment +of oil and gas properties +1,485 +1,519 +- +Accretion +of asset retirement obligation +999 +515 +465 +Exploratory +dry hole costs +1,775 +1,790 +11,115 +Gain +from sale of leaseholds +(33,291 +) +(328,000 +) +(7,669 +) +(Gain) +loss from sale of assets +(31 +) +9 +(207 +) +Expired +and abandoned leases +1,786 +2,169 +48 +Stock +based compensation +2,286 +1,516 +660 +Unrealized +losses (gains) on derivative transactions +4,642 +(7,620 +) +3,226 +Excess +tax benefits from stock-based compensation +(673 +) +(70 +) +- +Changes +in current assets and liabilities: +(Increase) +decrease in restricted cash +(14,254 +) +982 +(836 +) +(Increase) +in accounts receivable +(16,456 +) +(9,935 +) +(11,811 +) +(Increase) +in accounts receivable - affiliates +(2,302 +) +(194 +) +(5,319 +) +Decrease +(increase) in inventories +1,285 +1,987 +(3,398 +) +Decrease +(increase) in other current assets +4,839 +(2,106 +) +3,482 +Increase +(decrease) in production tax liability +10,802 +(261 +) +3,317 +(Decrease) +increase in accounts payable and accrued expenses +(10,869 +) +13,010 +19,440 +(Decrease) +increase in accounts payable - affiliates +(3,099 +) +6,116 +112 +Increase +in advances for future drilling contracts +13,645 +4,773 +7,502 +(Decrease) +increase in federal and state income taxes payable +(27,124 +) +19,950 +8,473 +Increase +(decrease) in funds held for future distribution +7,488 +(575 +) +18,505 +Other +723 +3,877 +(652 +) +Net +cash provided by operating activities +60,304 +67,390 +112,372 +Cash +flows from investing activities: +Capital +expenditures +(238,988 +) +(146,180 +) +(97,390 +) +Acquisition +of oil and gas properties, net of cash acquired +(255,661 +) +(18,512 +) +- +Investment +in drilling partnerships +- +(7,151 +) +(7,160 +) +Exploration +costs +- +(765 +) +(1,918 +) +Decrease +(increase) in restricted/designated cash +191,156 +(192,416 +) +- +Proceeds +from sale of leases to partnerships +1,371 +1,798 +2,829 +Proceeds +from sale of leaseholds/assets +34,701 +353,600 +9,597 +Net +cash used in investing activities +(267,421 +) +(9,626 +) +(94,042 +) +Cash +flows from financing activities: +Proceeds +from debt +352,000 +302,000 +91,000 +Proceeds +from short-term debt +- +20,000 +- +Payment +of long-term debt +(254,000 +) +(209,000 +) +(88,000 +) +Payment +of debt issuance costs +(1,468 +) +(160 +) +(423 +) +Proceeds +from issuance of stock +183 +31 +12 +Excess +tax benefits from stock-based compensation +673 +70 +- +Minority +interest investment +800 +- +- +Purchase +of treasury stock +(646 +) +(66,489 +) +(7,879 +) +Net +cash provided by (used in) financing activities +97,542 +46,452 +(5,290 +) +Net +(decrease) increase in cash and cash equivalents +(109,575 +) +104,216 +13,040 +Cash +and cash equivalents, beginning of period +194,326 +90,110 +77,070 +Cash +and cash equivalents, end of period +$ +84,751 +$ +194,326 +$ +90,110 +See accompanying Notes to +Consolidated Financial Statements . +Supplemental +Cash Flow information See Note 18 . +F-8 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS +NOTE +1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +General +Petroleum +Development Corporation ("PDC," "we," "us" or "the Company") is an independent +energy company engaged primarily in the drilling and development, production and +marketing of natural gas and oil. Since we began oil and gas +operations in 1969, we have grown primarily through drilling and development +activities, the acquisition of producing natural gas and oil wells and the +expansion of our natural gas marketing activities. As of December 31, +2007, we operate approximately 4,354 wells located in the Appalachian Basin, +Michigan Basin, and the Rocky Mountain Region. All of our oil and gas +wells are located in West Virginia, Tennessee, Pennsylvania, Michigan, North +Dakota, Colorado, Kansas, Texas and Wyoming. Our operations are +divided into four business segments: oil and gas sales, natural gas marketing, +oil and gas well drilling operations and well operations and pipeline +income. See Note 17 . +Principles of +Consolidation +The +consolidated financial statements of PDC include the accounts of our wholly +owned subsidiaries and WWWV, LLC, an entity in which we have a controlling +financial interest. All material intercompany accounts and +transactions have been eliminated in consolidation. We account for +our investment in interests in oil and gas limited partnerships under the +proportionate consolidation method. Under this method, our +consolidated financial statements include our investments in the partnerships +recorded by our working interest in each well thereby accumulating our pro rata +share of assets, liabilities and revenues and expenses respectively of the +limited partnerships in which we participate. Our proportionate share +of all significant transactions between us and the limited partnerships is +eliminated. +Cash +Equivalents +For +purposes of the statement of cash flows, we consider all highly liquid debt +instruments with original maturities of three months or less to be cash +equivalents. +Restricted +and Designated Cash +In July +2006, we established a trust in the amount of $300 million with a qualified +intermediary in conjunction with our sale of undeveloped leaseholds and +corresponding "like-kind exchange" agreement. As of December 31, +2006, $300 million remained in the trust, with $109 million reflected in cash +and cash equivalents as a current asset in our consolidated balance sheet and +the remaining $191 million reflected as designated cash – property acquisitions, +a non-current asset. The $191 million represented the amounts paid in +January 2007 for the acquisition of oil and gas properties qualifying for +"like-kind exchange" treatment. Interest earned on the trust account +in 2006 of $5.5 million along with the $109 million not utilized for "like-kind +exchange" purchases, is reflected in cash and cash equivalents, a current asset, +at December 31, 2006, which was available to us for operating purposes in +January 2007 and is no longer subject to a "like-kind exchange." We +terminated the trust in January 2007 following the acquisitions of suitable +like-kind properties, see Note 2 . +In +December 2006, we had paid a deposit of $0.5 million, reflected in our +consolidated balance sheet as designated cash, a non-current asset, for the +acquisition of oil and gas properties subsequently closed in January +2007. +In June +2007, we funded an escrow account in the amount of $14.1 million for amounts due +to the limited partners of our sponsored drilling partnerships as a result of us +over withholding estimated production taxes in years prior to 2007, which is +included, along with interest earned of $0.4 million, in restricted cash, +current, in our consolidated balance sheet as of December 31, 2007. +We are +required to maintain margin deposits with brokers for outstanding derivative +contracts. As of December 31, 2007 and 2006, cash in the amount of +$0.3 million and $0.5 million, respectively, was on deposit and reflected in our +consolidated balance sheets as restricted cash, a current asset. +We are +required by various government agencies or joint venture agreements to maintain +a bond or cash account for the plugging and abandonment of wells. As +of December 31, 2007 and 2006, we had bonds in the form of certificates of +deposit for plugging and abandonment of wells totaling $1.3 million and $1 +million, respectively, which are reflected in restricted/designated cash, a +non-current asset. +F-9 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Inventories +Materials, +supplies and commodity inventories are stated at the lower of average cost or +market and removed at carrying value. +Derivative +Financial Instruments +We +account for derivative financial instruments in accordance with Statement of +Financial Accounting Standards ("SFAS") No. 133, Accounting for Derivative +Instruments and Certain Hedging Activities , as amended. +During +2007, 2006 and 2005, none of our derivative instruments qualified for use of +hedge accounting under the terms of SFAS No. 133. Accordingly, we +recognize all derivative instruments as either assets or liabilities on our +consolidated balance sheets at fair value, and changes in the derivatives' fair +values are recorded in our consolidated statements of income in oil and gas +price risk management, net for our oil and gas commodities (derivatives related +to our production only), in gas sales from marketing activities for RNG’s gas +sales, in cost of gas marketing activities for RNG’s gas +purchases. See Note 15 . +In our +consolidated balance sheets, we record the fair value of derivatives entered +into on behalf of the affiliated partnerships and records an offsetting +receivable from or payable to the partnerships. See Note 15 . +Properties +and Equipment +Oil +and Gas Properties. +We +account for our oil and gas properties under the successful efforts method of +accounting. Costs of proved developed producing properties, +successful exploratory wells and development dry hole costs are capitalized and +depreciated or depleted by the unit-of-production method based on estimated +proved developed producing oil and natural gas reserves. Property +acquisition costs are depreciated or depleted on the unit-of-production method +based on estimated proved oil and gas reserves. +Our +estimates of proved reserves are based on quantities of oil and natural gas that +engineering and geological analysis demonstrates, with reasonable certainty, to +be recoverable from established reservoirs in the future under current operating +and economic conditions. Annually, we engage independent petroleum +engineers to prepare a reserve and economic evaluation of all our properties on +a well-by-well basis as of December 31. Additionally, we adjust our +oil and gas reserves for major acquisitions, new drilling and divestitures +during the year as needed. The process of estimating and evaluating +oil and natural gas reserves is complex, requiring significant decisions in the +evaluation of available geological, geophysical, engineering and economic +data. The data for a given property may also change substantially +over time as a result of numerous factors, including additional development +activity, evolving production history and a continual reassessment of the +viability of production under changing economic conditions. As a +result, revisions in existing reserve estimates occur from time to +time. Although every reasonable effort is made to ensure that reserve +estimates reported represent our most accurate assessments possible, the +subjective decisions and variances in available data for various properties +increase the likelihood of significant changes in these +estimates. Because estimates of reserves significantly affect our +depreciation, depletion and amortization ("DD&A") expense, a change in our +estimated reserves could have an effect on our net income. +Exploration +costs, including geological and geophysical expenses and delay rentals, are +charged to expense as incurred. Exploratory well drilling costs, +including the cost of stratigraphic test wells, are initially capitalized but +charged to expense if the well is determined to be nonproductive. The +status of each in-progress well is reviewed quarterly to determine the proper +accounting treatment under the successful efforts method of +accounting. Exploratory well costs continue to be capitalized as long +as the well has found a sufficient quantity of reserves to justify our +completion as a producing well and we are making sufficient progress assessing +our reserves and economic and operating viability. If an in-progress +exploratory well is found to be unsuccessful (referred to as a dry hole) prior +to the issuance of the financial statements, the costs are expensed to +exploration costs. If we are unable to make a final determination +about the productive status of a well prior to issuance of the financial +statements, the well is classified as “suspended well costs” until we have had +sufficient time to conduct additional completion or testing operations to +evaluate the pertinent geological and engineering data obtained. At +the time when we are able to make a final determination of a well’s productive +status, the well is removed from the suspended well status and the proper +accounting treatment is recorded. At December 31, 2007, suspended +well costs included in oil and gas properties on our accompanying consolidated +financial statements was $2.3 million. See Note 4 . +F-10 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +The +acquisition costs of unproved properties are capitalized when incurred, until +such properties are transferred to proved properties or charged to expense when +expired, impaired or amortized. Unproved oil and gas properties with +individually significant acquisition costs are periodically assessed, and any +impairment in value is charged to exploratory expense. The amount of +impairment recognized on unproved properties which are not individually +significant is determined by amortizing the costs of such properties within +appropriate fields based on our historical experience, acquisition dates and +average lease terms. In 2007, the aggregate impairment resulting from +individually significant unproved properties and insignificant unproved +properties was $1.5 million (which includes the liquidated damages of $1.1 +million related to the abandonment of an exploration agreement with an +unaffiliated party) and $1.8 million, respectively. In 2006, the +impairment resulting from individually significant unproved properties and +insignificant unproved properties was $0.5 million and $0.2 million, +respectively. In 2005, impairment charges for individually +significant and insignificant unproved properties were +immaterial. These impairment costs are included in the statements of +income as a component of exploration cost. The valuation of unproved +properties is subjective and requires us to make estimates and assumptions +which, with the passage of time, may prove to be materially different from +actual realizable values. +In +accordance with SFAS No. 144, Accounting for the Impairment or +Disposal of Long-Lived Assets , we assess our oil and gas properties for +possible impairment quarterly by comparing net capitalized costs to estimated +undiscounted future net cash flows on a field-by-field basis using estimated +production based upon prices at which we reasonably estimate the commodity to be +sold. The estimates of future prices may differ from current market +prices of oil and natural gas. Any downward revisions in estimates to +our reserve quantities, expectations of falling commodity prices or rising +operating costs could result in a reduction in undiscounted future net cash +flows and an impairment of our oil and gas properties. If net +capitalized costs exceed undiscounted future net cash flows, the measurement of +impairment is based on estimated fair value which would consider future +discounted cash flows. We recognized impairment losses on proved oil +and gas properties of $1.5 million in 2006 in our Nesson Field in North Dakota, +which is included in the statements of income as a component of exploration +cost. No impairments were recorded in 2007 or 2005. +Upon sale +or retirement of significant portions of or complete fields of depreciable or +depletable property, the net book value thereof, less proceeds or salvage value, +is credited or charged to income. Upon sale of individual wells, the +proceeds are credited to property costs. +Other +Property and Equipment. +Transportation Equipment, Pipelines +and Other Equipment . Transportation equipment, pipelines and +other equipment are carried at cost. Depreciation is provided +principally on the straight-line method over the assets estimated useful +lives. In accordance with SFAS No. 144 , Accounting for the Impairment or +Disposal of Long-Lived Assets , long-lived assets, such as property, plant +and equipment, are reviewed for impairment whenever events or changes in +circumstances indicate that the carrying amount of an asset may not be +recoverable. Recoverability of assets to be held and used is measured +by a comparison of the carrying amount of an asset to estimated undiscounted +future cash flows expected to be generated by the asset. If the +carrying amount of an asset exceeds our estimated future cash flows, an +impairment charge is recognized in the amount by which the carrying amount of +the asset exceeds the fair value of the asset. No impairments were +recorded in 2007, 2006, or 2005. +Maintenance +and repairs are charged to expense as incurred. Major renewals and +improvements are capitalized. Upon the sale or other disposition of +assets, the cost and related accumulated depreciation, depletion and +amortization are removed from the accounts, the proceeds are applied thereto and +any resulting gain or loss is reflected in income. +Buildings. Buildings +are carried at cost and depreciated on the straight-line method over their +estimated useful lives. +The +following table sets forth the estimated useful lives of our other property and +equipment. +Pipelines +and related facilities +10 +- 17 years +Transportation +and other equipment +3 - +20 years +Buildings +30 +- 40 years +Total +depreciation expense related to other property and equipment was $4.3 million, +$2 million and $2 million in 2007, 2006 and 2005, respectively. +F-11 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Capitalized +Interest +Interest +costs are capitalized as part of the historical cost of acquiring +assets. Oil and gas investments in unproved properties and major +development projects, on which DD&A expense is not currently recorded and on +which exploration or development activities are in progress, qualify for +capitalization of interest. Major construction projects also qualify +for interest capitalization until the asset is ready for +service. Capitalized interest is calculated by multiplying our +weighted-average interest rate on our debt by the qualifying +costs. Interest capitalized may not exceed gross interest expense for +the period. As the qualifying asset is moved to the DD&A pool, +the related capitalized interest is also transferred and is amortized over the +useful life of the asset. Interest costs of $3 million and $1.6 +million were capitalized for the year 2007 and 2006, respectively. No +interest costs were capitalized during 2005. +Production +Tax Liability +Production +tax liability represents estimated taxes, primarily severance and property, to +be paid to the states and counties in which we produce oil and +gas. Our share of these taxes is expensed to oil and gas production +and well operations cost. +Advances +for Future Drilling Contracts +Advances +for future drilling contracts represent funds received from our sponsored +drilling partnerships for drilling activities which have not been completed, a +portion of which will be recognized as revenue in accordance with our revenue +recognition policies. +Income +Taxes +We +account for income taxes under the asset and liability method. We +recognize deferred tax assets and liabilities for the future tax consequences +attributable to differences between the financial statement carrying amounts of +existing assets and liabilities and their respective tax +bases. Deferred tax assets and liabilities are measured using enacted +tax rates expected to apply to taxable income in the years in which those +temporary differences are expected to be recovered or settled. The +effect on deferred tax assets and liabilities of a change in tax rates is +recognized in income in the period that includes the enactment +date. If we determine that it is more likely than not that some +portion or all of the deferred tax assets will not be realized, we record a +valuation allowance thereby reducing the deferred tax assets to what we consider +realizable. No valuation allowance was recorded at December 31, 2007 +or 2006. +Asset +Retirement Obligations +We +account for asset retirement obligations by recording the fair value of our +plugging and abandonment obligations when incurred, which is at the time the +well is completely drilled. Upon initial recognition of an asset +retirement obligation, we increase the carrying amount of the long-lived asset +by the same amount as the liability. Over time, the liabilities are +accreted for the change in their present value, through charges to oil and gas +production and well operations costs. The initial capitalized costs +are depleted over the useful lives of the related assets, through charges to +depreciation, depletion and amortization. If the fair value of the +estimated asset retirement obligation changes, an adjustment is recorded to both +the asset retirement obligation and the asset retirement +cost. Revisions in estimated liabilities can result from revisions of +estimated inflation rates, escalating retirement costs and changes in the +estimated timing of settling asset retirement obligations. See Note 7 for a +reconciliation of asset retirement obligation activity. +Minority +Interest in Consolidated Limited Liability Company +In May +2007, we contributed $0.8 million for a 50% interest in WWWV, LLC ("LLC"), a +limited liability company for which we serve as the managing +member. One-sixth of the entity is owned by the Chief Executive +Officer of our Company, who paid the same unit price for his interest as was +paid by us and unrelated third parties for such interests in the +LLC. The LLC's only asset is an aircraft and the LLC was formed for +the purpose of owning and operating the aircraft. +The +minority interest portion of pre-tax expense incurred by and belonging to the +minority interest holders of the consolidated limited liability company is not +material and included in our consolidated statement of income as an offset to +DD&A expense. +F-12 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Retirement +of Treasury Shares +We +have historically retired all treasury share purchases, with the exception of +shares purchased in accordance with our non-employee deferred compensation plan +for non-employee directors, see Note 9 . As +treasury shares are retired, we charge any excess of cost over the par value +entirely to additional paid-in-capital, to the extent we have amounts in +paid-in-capital, with any remaining excess cost being charged to retained +earnings. +Revenue +Recognition +Oil and natural gas +sales . Sales of oil are recognized when persuasive evidence of +a sales arrangement exists, the oil is verified as produced and is delivered to +a purchaser, collection of revenue from the sale is reasonably assured and the +sales price is determinable. We are currently able to sell all the +oil that we can produce under existing sales contracts with petroleum refiners +and marketers. We do not refine any of our oil +production. Our crude oil production is sold to purchasers at or near +our wells under short-term purchase contracts at prices and in accordance with +arrangements that are customary in the oil industry. +Sales of +natural gas are recognized when natural gas has been delivered to a custody +transfer point, persuasive evidence of a sales arrangement exists, the rights +and responsibility of ownership pass to the purchaser upon delivery, collection +of revenue from the sale is reasonably assured and the sales price is fixed or +determinable. Natural gas is sold by us under contracts with terms +ranging from one month to three years. Virtually all of our contract +pricing provisions are tied to a market index, with certain adjustments based +on, among other factors, whether a well delivers to a gathering or transmission +line, quality of natural gas and prevailing supply and demand conditions, so +that the price of the natural gas fluctuates to remain competitive with other +available natural gas supplies. As a result, our revenues from the +sale of natural gas will suffer if market prices decline and benefit if they +increase. We believe that the pricing provisions of our natural gas +contracts are customary in the industry. +We +currently use the "net-back" method of accounting for transportation +arrangements of our natural gas sales. We sell gas at the wellhead +and collect a price and recognize revenues based on the wellhead sales price +since transportation costs downstream of the wellhead are incurred by the +customers and reflected in the wellhead price. +Natural gas marketing +activities . Natural gas marketing is reported on the gross +accounting method, based on the nature of the agreements between RNG, our +suppliers and our customers. RNG, our marketing subsidiary, purchases +gas from many small producers and bundles the gas together to sell in larger +amounts to purchasers of natural gas for a price advantage. RNG has +latitude in establishing price and discretion in supplier and purchaser +selection. Natural gas marketing revenues and expenses reflect the +full cost and revenue of those transactions because RNG takes title to the gas +it purchases from the various producers and bears the risks and rewards of that +ownership. Both the realized and unrealized gains and losses of the +RNG commodity based derivative transactions for natural gas marketing activities +are included in gas sales from marketing activities or cost of gas marketing +activities, as applicable. +Oil and gas well drilling +operations . Our drilling segment recognizes revenue from +drilling contracts with sponsored drilling programs using the percentage of +completion method based upon the percentage of contract costs incurred to date +to the estimated total contract costs for each contract. We utilize +this method since reasonably dependable estimates of the total estimated costs +can be made and recognized revenues are subject to revisions as a contract +progresses, the term of which can range from three to twelve +months. In addition, we offer our drilling services under two types +of contractual arrangements, cost-plus or footage-based service contracts, which +result in differing risk and reward relationships, and consequently, different +revenue reporting policies pursuant to Emerging Issues Task Force ("EITF") Issue +No. 99-19, Reporting Revenue +Gross as a Principal versus Net as an Agent . +The first +cost-plus drilling service arrangement was entered into in late 2005 with +drilling activity commencing in the first quarter of 2006. Due to the +fixed-fee-percentage nature of our revenues from these services, we have +determined that, in substance, we are acting as an agent, without risk of loss +during the performance of the drilling activities. Accordingly, our +services provided under the cost-plus drilling agreements are reported on a net +basis. We entered into our second and third cost-plus drilling +arrangements in September 2006 and August 2007 and commenced drilling +immediately. +Footage-based +contracts provide for the drilling, completion and equipping of wells at footage +rates and are generally completed within nine to twelve months after the +commencement of drilling. We provide geological, engineering, and +drilling supervision on the drilling and completion process and use +subcontractors to perform drilling and completion services and accordingly has +the risk of loss in performing services under these +arrangements. Accordingly, we report revenue under these agreements +gross of related expenses. Anticipated losses, if any, on uncompleted +contracts are recorded at the time that the estimated total costs exceed the +estimated total contract revenue. At December 31, 2007 and 2006, the +loss contract reserve was $0.2 million and $0.3 million, +respectively. +F-13 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Well operations and pipeline +income . Well operations and pipeline income are recognized +when persuasive evidence of an arrangement exists, services have been rendered, +collection of revenues is reasonably assured and the sales price is fixed or +determinable. We are paid a monthly operating fee for each well we +operate for outside owners including the limited partnerships we +sponsored. The fee covers monthly operating and accounting costs, +insurance and other recurring costs. We may also receive additional +compensation for special non-recurring activities, such as reworks and +recompletions. +Stock-Based +Compensation +Effective +January 1, 2006, we adopted SFAS No. 123R, Share-Based Payment (revised +2004) . We elected the modified prospective method of adoption, +and accordingly, prior period financial statements have not been +restated. Pursuant to SFAS No. 123R we are required to recognize in +our financial statements, based on fair value, compensation expense for all +unvested stock options and other equity-based awards as of January 1, +2006. For all unvested options outstanding as of January 1, 2006 the +previously measured but unrecognized compensation expense, based on the fair +value at the original grant date, will be recognized in the financial statements +over the remaining requisite service period for each separately vesting +portion. For equity-based compensation awards granted or modified +subsequent to January 1, 2006, compensation expense, based on the fair value on +the date of grant or modification, will be recognized in the financial +statements on a straight-line basis over the vesting period for the entire +award. To the extent compensation cost relates to employees directly +involved in oil and natural gas acquisition, exploration and development +activities, such amounts are capitalized to properties and +equipment. Amounts not capitalized to properties and equipment are +recognized in the appropriate cost and expense line item in the statement of +income. For the year ended December 31, 2007 and 2006, we recognized +stock-based compensation expense of $2.3 million and $1.5 million related to +stock awards, respectively. Compensation capitalized as part of +properties and equipment was immaterial in 2007 and 2006. +For +periods prior to the adoption of SFAS No. 123(R), we accounted for +our share-based compensation awards using the intrinsic value based method as +prescribed by Accounting Principles Board Opinion ("APB") No. 25, Accounting for Stock Issued to +Employees , and related interpretations. Under the intrinsic +value based method, compensation expense for option awards was recorded on the +date of grant only if the then-current market price of the underlying stock +exceeded the exercise price. The following table illustrates the +effect on net income and earnings per share had we applied the fair value +recognition provisions of SFAS No. 123(R), as amended, to stock-based employee +compensation during 2005 (in thousands, except per share data): +Year +ended December 31, 2005 +(in thousands, except +per share data) +Net +income, as reported: +$ +41,452 +Stock-based +compensation expense included in reported net income, net of +tax +414 +Total +stock-based compensation expense determined under fair value method +for all awards, net of tax +(509 +) +Pro +forma net income +$ +41,357 +Earnings +per share: +Basic +earnings per share, as reported and pro forma +$ +2.53 +Diluted +earnings per share, as reported and pro forma +$ +2.52 +Earnings +Per Share +Our basic +earnings per share ("EPS") amounts have been computed based on the average +number of shares of common stock outstanding for the period. Diluted +EPS amounts include the effect of our outstanding stock options, unamortized +portion of restricted stock and shares held pursuant to our non-employee +director deferred compensation plan using the treasury stock method if including +such potential shares of common stock is dilutive. See Note 12 . +F-14 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Use +of Estimates +The +preparation of our consolidated financial statements in accordance with +generally accepted accounting principles in the United States of America +requires us to make estimates and assumptions that affect the amounts reported +in our consolidated financial statements and accompanying +notes. Actual results could differ from those +estimates. Estimates which are particularly significant to our +consolidated financial statements include estimates of oil and gas reserves, +future cash flows from oil and gas properties, valuation of derivative +instruments and valuation of deferred income tax assets. +Fair +Value of Financial Instruments +The +carrying values of our receivables, payables and debt obligations approximate +fair value as of December 31, 2007 and 2006, due to the short-term maturity of +these instruments. +Recent +Accounting Standards +Recently Adopted Accounting +Standards +In +December 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS No. +123(R), Share-Based +Payment . In March 2005, the Securities and Exchange Commission +(“SEC”) issued Staff Accounting Bulletin (“SAB”) No. 107, Share-Based Payment , +regarding the interaction between SFAS No. 123(R) and certain SEC rules and +regulations. Effective January 1, 2006, we adopted SFAS No. 123(R). +We elected to use the modified prospective method for adoption, which requires +compensation expense to be recognized in the statement of income for all +unvested stock options and other equity-based compensation beginning in the +first quarter of adoption. Prior to the adoption of SFAS No. 123(R), +we followed the intrinsic value method in accordance with APB No. 25 (as +amended) to account for employee stock-based compensation. The +adoption of SFAS No. 123(R) required the unamortized stock award recorded under +APB No. 25 related to stock-based compensation awards as of January 1, 2006, in +the amount of $0.8 million to be eliminated against additional +paid-in-capital. See Stock-Based Compensation policy above and Note 9 +for further discussion of the Company's accounting for share-based compensation +awards. +In +September 2006, the SEC issued SAB No. 108, Considering the Effects of Prior +Year Misstatements when Quantifying Misstatements in Current Year Financial +Statements . SAB No. 108 provides guidance on how the effects +of prior year misstatements should be considered in quantifying misstatements in +the current year financial statements. SAB No. 108 requires +registrants to quantify misstatements using both the income statement +(“rollover”) and balance sheet (“iron curtain”) approach and evaluate whether +either approach results in a misstatement that, when all relevant quantitative +and qualitative factors are considered, is material. Historically, we +evaluated uncorrected misstatements using the “rollover” method which resulted +in an accumulation of quantitatively and qualitatively immaterial misstatements +to our consolidated financial statements. SAB No. 108 provides for a +one time transitional adjustment to retained earnings for errors which were not +deemed material to prior year financial statements, but which is material under +guidance of SAB No. 108. We adopted SAB No. 108 during the fourth +quarter of 2006 and recorded a one time adjustment to reduce retained earnings +by $1.0 million. +In June +2006, the FASB issued EITF No. 06-3, How Taxes Collected from Customers +and Remitted to Governmental Authorities Should be Presented in the Income +Statement (That Is, Gross versus Net Presentation) . EITF 06-3 +addresses the income statement presentation of any tax collected from customers +and remitted to a government authority and concludes that the presentation of +taxes on either a gross basis or a net basis is an accounting policy decision +that should be disclosed pursuant to APB No. 22, Disclosures of Accounting +Policies . For taxes that are reported on a gross basis +(included in revenues and costs), EITF 06-3 requires disclosure of the amounts +of those taxes in interim and annual financial statements, if those amounts are +significant. EITF 06-3 became effective for interim and annual +reporting periods beginning after December 15, 2006. The adoption of +the standard, effective January 1, 2007, did not have a significant effect on +our consolidated financial statements. Our existing accounting +policy, which was not changed upon the adoption of EITF 06-3, is to present +taxes within the scope of EITF 06-3 on a net basis. +In July +2006, the FASB issued FASB Interpretation ("FIN") No. 48, Accounting for Uncertainty in Income +Taxes - an Interpretation of FASB Statement 109 , which prescribes a +comprehensive model for accounting for uncertainty in tax +positions. FIN No. 48 provides that the tax effects from an uncertain +tax position can be recognized in the financial statements, only if the position +is more likely than not of being sustained on audit by the Internal Revenue +Service ("IRS"), based on the technical merits of the position. The +provisions of FIN No. 48 became effective for us on January 1, +2007. The cumulative effect of applying the provisions of FIN No. 48 +has been accounted for as an adjustment to retained earnings in the first +quarter of 2007. The adoption of FIN No. 48 resulted in a $0.3 +million cumulative effect adjustment (see Note 6 for further +discussion). +F-15 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +In May +2007, the FASB issued FASB Staff Position FIN No. 48-1, Definition of Settlement in FASB +Interpretation No. 48 ("FIN No. 48-1"). FIN No. 48-1 amends +FIN No. 48 to provide guidance on how an entity should determine whether a tax +position is effectively settled for the purpose of recognizing previously +unrecognized tax benefits. The term "effectively settled" replaces +the term "ultimately settled" when used to describe recognition, and the terms +"settlement" or "settled" replace the terms "ultimate settlement" or "ultimately +settled" when used to describe measurement of a tax position under FIN No. +48. FIN No. 48-1 clarifies that a tax position can be effectively +settled upon the completion of an examination by a taxing authority without +being legally extinguished. For tax positions considered effectively +settled, an entity would recognize the full amount of tax benefit, even if the +tax position is not considered more likely than not to be sustained based solely +on the basis of its technical merits and the statute of limitations remains +open. The adoption of FIN No. 48-1, effective January 1, 2007, did +not have an incremental effect on our consolidated financial +statements. +Recently Issued Accounting +Standards +In +September 2006, the FASB issued SFAS No. 157, Accounting for Fair Value +Measurements . SFAS No. 157 defines fair value, establishes a +framework for measuring fair value within generally accepted accounting +principles and expands required disclosure about fair value +measurements. SFAS No. 157 does not expand the use of fair value in +any new circumstances. SFAS No. 157 is effective for financial +statements issued for fiscal years beginning after November 15, +2007. However, on February 12, 2008, the FASB issued FASB Staff +Position ("FSP") FAS 157-2, Effective Date of FASB Statement No. +157 , which delayed the effective date of SFAS No. 157 for all +nonfinancial assets and nonfinancial liabilities, except those that are +recognized or disclosed at fair value in the financial statements on a recurring +basis (at least annually). This FSP partially defers the effective +date of SFAS No. 157 to fiscal years beginning after November 15, 2008, and +interim periods within those fiscal years for items within the scope of this +FSP. Effective January 1, 2008, we will adopt SFAS No. 157 except as +it applies to those nonfinancial assets and nonfinancial liabilities as noted in +FSP FAS 157-b. We are evaluating the effect that these new standards +will have, if any, on our consolidated financial statements when +adopted. +In +February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial +Assets and Financial Liabilities . SFAS No. 159 permits +entities to choose to measure, at fair value, many financial instruments and +certain other items that are not currently required to be measured at fair +value. The objective is to improve financial reporting by providing +entities with the opportunity to mitigate volatility in reported earnings caused +by measuring related assets and liabilities differently without having to apply +complex hedge accounting provisions. SFAS No. 159 establishes +presentation and disclosure requirements designed to facilitate comparisons +between entities that choose different measurement attributes for similar types +of assets and liabilities. The statement will be effective as of the +beginning of an entity's first fiscal year beginning after November 15, +2007. We are evaluating the effect that SFAS No. 159 will have, if +any, in our consolidated financial statements when it is adopted in +2008. +In April +2007, the FASB issued FSP FIN No. 39-1, Amendment of FASB Interpretation No. +39 ("FIN No. 39-1'), to amend certain portions of Interpretation +39. FIN No. 39-1 replaces the terms "conditional contracts" and +"exchange contracts" in Interpretation 39 with the term "derivative instruments" +as defined in Statement 133. FIN No. 39-1 also amends Interpretation +39 to allow for the offsetting of fair value amounts for the right to reclaim +cash collateral or receivable, or the obligation to return cash collateral or +payable, arising from the same master netting arrangement as the derivative +instruments. FIN No. 39-1 applies to fiscal years beginning after +November 15, 2007, with early adoption permitted. We are evaluating +the effect that FIN No. 39-1 will have, if any, on our consolidated financial +statements when adopted in 2008. +In +December 2007, FASB issued SFAS No. 141 (revised 2007), Business Combinations ("SFAS +No. 141R"), which replaces FASB Statement No. 141. SFAS No. 141R +establishes principles and requirements for how an acquirer recognizes and +measures in its financial statements the identifiable assets acquired, the +liabilities assumed, any non-controlling interest in the acquiree and the +goodwill acquired. This statement also establishes disclosure +requirements which will enable users to evaluate the nature and financial +effects of the business combination. SFAS No. 141R is effective as of +the beginning of an entity’s fiscal year beginning after December 15, +2008. We are evaluating the potential effect that the adoption of +SFAS No. 141R will have, if any, on our consolidated financial statements when +adopted in 2008. +In +December 2007, the FASB issued SFAS No. 160, Non-controlling Interests in +Consolidated Financial Statement—An Amendments of ARB No. 51 ("SFAS No. +160"). SFAS No. 160 states that accounting and reporting for minority +interests will be recharacterized as non-controlling interests and classified as +a component of equity. Additionally, SFAS No. 160 establishes +reporting requirements that provide sufficient disclosures which clearly +identify and distinguish between the interests of the parent and the interests +of the non-controlling owners. SFAS No. 160 is effective as of the +beginning of an entity’s first fiscal year beginning after December 15, +2008. We are currently evaluating the potential effect that the +adoption of SFAS No. 160 will have, if any, on our consolidated financial +statements. +F-16 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +NOTE +2 – ACQUISITIONS +2007 +Acquisitions +Acquisition +of Internal Revenue Code Section 1031 – Like-Kind Exchange +Properties +During +the first quarter of 2007, we completed the acquisition of suitable like-kind +properties in accordance with the like-kind exchange ("LKE") agreement we +entered into in connection with our sale of undeveloped leaseholds located in +Grand Valley Field, Garfield County, Colorado in July 2006. We +acquired, for cash, qualifying oil and gas properties totaling $188.9 million, +including costs of acquisition, as described below. +EXCO +Properties. On January 5, 2007, we completed the purchase of +producing properties and undeveloped drilling locations and acreage in the +Wattenberg Field of the DJ Basin, Colorado from EXCO Resources Inc., an +unaffiliated party. The acquisition included substantially all of +EXCO’s assets in the area and encompassed 144 oil and natural gas wells +(approximating 25.5 Bcfe proved developed reserves as of December 31, 2005) and +8,160 acres of leasehold interests. The wells and leases acquired are +located in Weld, Adams, Larimer, and Broomfield Counties, +Colorado. We operate the assets and hold a majority working interest +in the properties . +Company Sponsored +Partnerships . On January 10, 2007, we completed the purchase +of the remaining working interests in 44 of our sponsored +partnerships. The transaction resulted in an increase in our +ownership in 718 gross (423 net) wells that we currently operate. The +wells are located primarily in the Appalachian Basin and Michigan. +The +following table presents the adjusted purchase price for the like-kind exchange +property acquisitions described above as of December 31, 2007. +EXCO +Partnerships +(in +thousands) +Cash +consideration paid +$ +128,672 +$ +57,776 +Plus: +direct costs of acquisition +1,662 +1,664 +Less: +acquisition cost adjustments +(119 +) +(2,792 +) +Total acquisition +cost +$ +130,215 +$ +56,648 +The +following table presents, as of the respective date of acquisition, the final +allocations of the purchase prices based on estimates of fair +value. +EXCO +Partnerships +(in +thousands) +Current +assets acquired +$ +91 +$ +- +Proved +oil and gas properties +117,099 +45,813 +Unproved +oil and gas properties +14,960 +13,268 +Asset +retirement obligation +(422 +) +(2,433 +) +Other +liabilities assumed +(1,513 +) +- +Preliminary +acquisition cost +$ +130,215 +$ +56,648 +The +assessment of fair value of proved oil and gas properties acquired was based +primarily on projections of expected discounted future cash flows of acquired +oil and natural gas reserves. To compensate for the inherent risk of +estimating and valuing unproved properties, the discounted future net revenues +of probable reserves were reduced by additional risk-weighting factors in that +valuation. +Other. In January +2007, we acquired from unaffiliated parties other like-kind undeveloped +leaseholds in Erath County, Texas for $2.1 million, including costs of +acquisition. Acreage in this area is prospective for development of +oil and natural gas reserves in the Barnett Shale. +F-17 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Other +Acquisitions +On +February 22, 2007, we acquired, from an unaffiliated party, 28 producing wells +and associated undeveloped acreage located in Colorado (Wattenberg Field) for a +purchase price of $12 million, which was allocated to oil and gas +properties. +On +October 30, 2007, with an effective date of October 1, 2007, we purchased from +unrelated parties, Castle Gas Company, et.al., a majority working interest in +762 natural gas wells located in southwestern Pennsylvania for approximately $54 +million. We estimated that the acquisition included approximately 47 +Bcfe of reserves, or 31 Bcfe of proved reserves and 16 Bcfe of unproved +reserves. The purchase also included associated pipelines, equipment, +real estate and undeveloped acreage. +The +following table presents the adjusted purchase price for the Castle acquisition +described above as of December 31, 2007. +(in +thousands) +Cash +consideration paid +$ +53,041 +Plus: +direct costs of acquisition +443 +Plus: +acquisition cost adjustments +583 +Total acquisition +cost +$ +54,067 +The +following table presents, as of the respective date of acquisition, the final +preliminary allocation of the purchase price based on estimates of fair +value. +(in +thousands) +Current +assets acquired +$ +185 +Proved +oil and gas properties +55,778 +Unproved +oil and gas properties +217 +Real +estate and equipment, and other assets +2,115 +Non +current assets +783 +Asset +retirement obligation +(4,043 +) +Other +liabilities assumed +(968 +) +Preliminary +acquisition cost +$ +54,067 +The +assessment of fair value of proved oil and gas properties acquired was based +primarily on projections of expected discounted future cash flows of acquired +oil and natural gas reserves. To compensate for the inherent risk of +estimating and valuing unproved properties, the discounted future net revenues +of probable reserves were reduced by additional risk-weighting factors in that +valuation. +Pro +Forma Financial Information +The +results of operations for all of the above acquisitions have been included in +our consolidated financial statements from the dates of +acquisition. The pro forma effect of the inclusion in our +consolidated statement of income for the year ended December 31, 2007, of the +results of operations for the January and February 2007 acquisitions described +above, individually and in the aggregate, was not material. +The +following unaudited pro forma financial information presents a summary of our +consolidated results of operations for the years ended December 31, 2007 and +2006, assuming the acquisitions of the EXCO properties, our sponsored +partnerships and the Castle properties had been completed as of January 1, 2006, +including adjustments to reflect the allocation of the purchase price to the +acquired net assets. The pro forma effect of the inclusion of the +results of operations for all of the other acquisitions described above, +individually and in the aggregate, was not material. +F-18 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Year +Ended December 31, +2007 +2006 +(in +thousands, except per share data) +Total +revenues +$ +310,351 +$ +315,492 +Net +income +34,571 +243,105 +Earnings +per common share: +Basic +$ +2.34 +$ +15.52 +Diluted +$ +2.33 +$ +15.44 +The pro +forma results of operations are not necessarily indicative of what our results +of operations would have been had the EXCO properties, our sponsored +partnerships and the Castle properties been acquired at the beginning of the +periods indicated, nor does it purport to represent our results of operations +for any future periods. +2006 +Acquisitions +On +December 6, 2006, we completed our cash tender offer and purchased approximately +95.5% or 9,112,750 shares of the outstanding common stock of Unioil, an +independent energy company with properties in northern Colorado and southern +Wyoming. The acquisition of more than 90% of the outstanding shares +of common stock allowed us to effect a short-form merger of Unioil and one of +our wholly owned subsidiaries, resulting in the acquisition of the remaining +428,719 shares of Unioil. Each share of Unioil common stock not +tendered through the offer was converted into the right to receive $1.91 in +cash, the same consideration paid for shares in the tender offer. The +total price paid for 100% of Unioil’s outstanding common stock was $18.6 +million, including $0.4 million in direct costs of the acquisition. The +preliminary acquisition cost allocation included $6.8 million goodwill, in +which was re-allocated to properties and equipment in the first quarter of 2007 +as part of our process of finalizing the allocation of the preliminary purchase +price. Further, as a result of this reclass, the deferred tax liabilities +increased and thus increased property and equipment. +The +following table presents the adjusted purchase price for the Unioil acquisition +described above as of December 31, 2007. +(in +thousands) +Cash +consideration paid +$ +18,224 +Plus: +direct costs of acquisition +382 +Total acquisition +cost +$ +18,606 +The +following table presents the final allocations of the purchase price based on +estimates of fair value. +(in +thousands) +Current +assets acquired +$ +660 +Properties +and equipment acquired +25,839 +Deferred +tax liability +(6,783 +) +Other +liabilities assumed +(968 +) +Preliminary +acquisition cost +$ +18,748 +NOTE 3 – ACCOUNTS +RECEIVABLE +Accounts +receivable is presented on our consolidated balance sheets net of allowance for +doubtful accounts. Accounts receivable are reviewed to determine +which are doubtful of collection. In making the determination of the +appropriate allowance for doubtful accounts, we consider our historical +write-offs, relationships and overall credit worthiness of our customers, +additional consideration is given to well production data for receivables +related to well operations. The allowance as reflected in the +accompanying balance sheets is our best estimate of the amount of probable +credit losses in our existing accounts receivable. Our allowance for +doubtful accounts as of December 31, 2007 and 2006, was $0.4 million and $0.4 +million, respectively. +F-19 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +The +nature of the independent oil and gas industry involves a concentration of oil +and gas sales to a few customers. We sell oil and natural gas to +various public utilities, gas marketers and industrial customers. The +following table identifies significant customers as a percent of total oil and +gas sales and total revenues for each of the years presented. +Oil +and Gas Sales +Total +Revenue +Year +Ended December 31, +Year +Ended December 31, +2007 +2006 +2005 +2007 +2006 +2005 +Customer +Tepco +Crude Oil, LLC +14.8 +% +14.9 +% +10.5 +% +13.5 +% +12.9 +% +6.9 +% +Williams +Production RMT Company +14.1 +% +8.7 +% +4.7 +% +12.9 +% +7.5 +% +3.1 +% +DCP +Midstream, LP +7.8 +% +10.6 +% +10.6 +% +7.1 +% +9.1 +% +6.9 +% +Integrys +(formerly WPS, Energy) +6.9 +% +9.4 +% +12.9 +% +6.3 +% +8.1 +% +8.4 +% +Sempra +Energy Trading +6.0 +% +10.3 +% +15.2 +% +5.5 +% +8.9 +% +9.9 +% +NOTE +4 – PROPERTIES AND EQUIPMENT +December +31, +December +31, +2007 +2006 +(in +thousands) +Properties +and equipment, net: +Oil +and gas properties (successful efforts method of +accounting) +Proved +$ +953,904 +$ +473,451 +Unproved +41,023 +27,055 +Total +oil and gas properties +994,927 +500,506 +Pipelines +and related facilities +22,408 +12,673 +Transportation +and other equipment +23,669 +7,870 +Land +and buildings +11,303 +11,620 +Construction +in progress (1) +2,929 +4,801 +1,055,236 +537,470 +Accumulated +depreciation, depletion and amortization ("DD&A") +(209,372 +) +(143,253 +) +$ +845,864 +$ +394,217 +(1) +At +December 31, 2007, includes cost primarily related to a new integrated oil and +gas financial software system. +Suspended +Well Costs +The +following table sets forth the capitalized exploratory well costs, which are +pending the determination of proved reserves, included in oil and gas +properties. +2007 +2006 +2005 +(in +thousands) +Beginning +balance at January 1 +$ +765 +$ +1,918 +$ +4,170 +Additions +to capitalized exploratory well costs pending the determination of proved +reserves +3,953 +12,016 +6,441 +Reclassifications +to wells, facilities and equipment based on the determination of proved +reserves +(878 +) +(13,169 +) +(4,523 +) +Capitalized +exploratory well costs charged to expense +(1,540 +) +- +(4,170 +) +Ending +balance at December 31 +$ +2,300 +$ +765 +$ +1,918 +As of +December 31, 2007, the three wells awaiting the determination of proved reserves +have not been capitalized for a period greater than one year. +F-20 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +NOTE +5 - LONG-TERM DEBT +We have a +credit facility with JPMorgan Chase Bank, N.A. ("JPMorgan") and BNP Paribas, as +amended, dated as of November 4, 2005, with an activated commitment of $295 +million as of December 31, 2007. The credit facility, through a +series of amendments, includes commitments from Wachovia Bank, N.A., Bank of +Oklahoma, Allied Irish Banks p.l.c., Guaranty Bank, BSB, Royal Bank of Canada +and The Royal Bank of Scotland, plc. The maximum allowable commitment +under the current credit facility is $400 million. The credit +facility is subject to and secured by required levels of oil and natural gas +reserves. The credit facility requires an aggregated security of a +value no less than 80% of the value of the direct interests included in the +borrowing base properties. We are required to pay a commitment fee of +0.25% to 0.375% per annum on the unused portion of the activated credit +facility. Interest accrues at an alternative base rate ("ABR") or +adjusted LIBOR at our discretion. The ABR is the greater of +JPMorgan's prime rate, an adjusted secondary market rate for a three-month +certificate of deposit plus 1% or the federal funds effective rate plus +0.5%. ABR borrowings are assessed an additional margin spread up to +0.375% and adjusted LIBOR borrowings are assessed an additional margin spread of +1.125% to 1.875%, based upon the outstanding balance under the credit +facility. The credit agreement requires, among other things, the +maintenance of certain working capital and tangible net worth +ratios. No principal payments are required until the credit agreement +expires on November 4, 2010. +The +credit facility contains covenants customary for agreements of this type, +including, but not limited to, limitations on our ability to: (a) incur +additional indebtedness and guarantees, (b) create liens and other encumbrances +on our assets, (c) consolidate, merge or sell assets, (d) pay dividends and +other distributions, (e) make certain investments, loans and advances, (f) enter +into sale/leaseback transactions, (g) enter into transactions with our +affiliates, (h) change the character of our business, (i) engage in hedging +activities unless certain requirements are satisfied, (j) issue certain types of +stock, and (k) make certain amendments to our organizational +documents. The credit facility also requires us to execute and +deliver specified mortgages and other evidences of security and to deliver +specified opinions of counsel and other evidences of title. In +addition, we are required to comply with certain financial tests and maintain +certain financial ratios. The financial tests and ratios include requirements +to: (a) maintain a minimum ratio of consolidated current assets to consolidated +current liabilities, or working capital ratio, and (b) not to exceed a maximum +leverage ratio. +Effective +August 9, 2007, the first amendment to our credit facility waived our working +capital covenant until the earlier of (i) a debt or equity transaction resulting +in net proceeds, as defined, to us of at least $200 million or (ii) July 1, +2008, which was further extended to October 1, 2008, effective October 16, +2007. In accordance with the first amendment, the ABR rate was +increased by 0.375% as long as the waiver of the working capital covenant is in +effect. +On +February 8, 2008, we completed the issuance and sale of $203 million aggregate +principal amount of 12% senior notes due 2018 for net proceeds received of +approximately $196 million (see Note +19 ). In accordance with the senior credit agreement, upon the +issuance of any senior notes, the borrowing base then in effect on our credit +facility will automatically be reduced by $300 for each $1,000 in stated +principal amount of such senior notes issued by us. Accordingly, +effective February 8, 2008, our borrowing base under the credit facility was +reduced from $295 million to $234.1 million. Further, our notes +issuance meets the requirements of a debt transaction described above, and thus, +the testing of our working capital covenant will resume with our quarter ending +March 31, 2008. +The +indenture governing our senior notes contains covenants that, among other +things, limit our ability and the ability of our restricted subsidiaries to +incur additional debt; make certain investments or pay dividends or +distributions on our capital stock or purchase or redeem or retire capital +stock; sell assets, including capital stock of our restricted subsidiaries; +restrict dividends or other payments by restricted subsidiaries; create liens +that secure debt; enter into transactions with affiliates; and merge or +consolidate with another company. +As of +December 31, 2007, the outstanding balance under our credit facility was $235 +million compared to $117 million, excluding the overline note discussed below, +as of December 31, 2006. The borrowing rate on the outstanding +balance was 7.07% and 7.79% at December 31, 2007, and December 31, 2006, +respectively. Amounts outstanding under the credit facility were +secured by substantially all of our properties. We were in compliance +with all covenants at December 31, 2007. +On +December 19, 2006, we executed, pursuant to our credit facility, an overline +note in the amount of $20 million to be repaid on January 31, +2007. Interest on the overline note accrued at a per annum rate equal +to the alternate base rate plus 0.8% until December 22, 2006, at which time the +rate converted to a Eurodollar borrowing for a one month period and at a per +annum rate equal to an adjusted LIBOR rate plus 2.30%. The overline +note was paid in full in accordance with its terms in January 2007. +F-21 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +NOTE +6 - INCOME TAXES +In +both 2007 and 2006, we utilized our tax election to currently expense +approximately $44 million and $55 million, respectively, of intangible drilling +costs ("IDC"). This election substantially reduced our current tax +expense but resulted in a correspondingly higher deferred tax expense as shown +below. Additionally, in 2006, we had a substantial taxable gain from +the sale of undeveloped oil and gas properties (see Note +16 ). We have chosen to use the favorable deferral aspects of +the Internal Revenue Code ("IRC") Section 1031, LKE to defer the tax +liability on a portion of the gain utilized by purchasing replacement properties +(see Note +2 ). Accordingly, our current and deferred provision for income +taxes increased proportionately in 2006 due to the current and deferred tax +associated with this large taxable gain. The components of our tax +expense consisted of the following: +2007 +2006 +2005 +(in +thousands) +Current: +Federal +$ +7,579 +$ +54,467 +$ +17,894 +State +1,201 +8,739 +3,431 +Total +current income taxes +8,780 +63,206 +21,325 +Deferred: +Federal +11,074 +74,003 +2,834 +State +1,127 +12,428 +517 +Total +deferred income taxes +12,201 +86,431 +3,351 +Total +income taxes +$ +20,981 +$ +149,637 +$ +24,676 +Income +tax expense differed from the amounts computed by applying the U.S. federal +income tax rate of 35%. +2007 +2006 +2005 +(in +thousands) +Computed +"expected" tax +$ +18,966 +$ +135,594 +$ +23,145 +State +income tax (net) +1,907 +13,744 +2,566 +Percentage +depletion +(624 +) +(545 +) +(771 +) +Domestic +production activities deduction +(374 +) +- +(399 +) +Other +1,106 +844 +135 +$ +20,981 +$ +149,637 +$ +24,676 +In order +to reduce current income taxes payable, we elected to expense, for income tax +purposes, a large amount of IDC in 2007, our domestic production activities +deduction, which in 2007 was statutorily equal to six percent of our qualified +production activity income (QPAI), was $1.1 million. In 2006, due to +our decision to expense $55 million of IDC, our domestic production deduction, +which in 2006 was statutorily equal to three percent of QPAI, was +zero. In addition, the amount in "Other" for 2007, was primarily +nondeductible tax penalties. +The +Internal Revenue Service ("IRS") examination of our federal tax returns for the +2003 and 2004 tax years was concluded on July 31, 2007. There was no +significant affect on 2007 tax expense from the conclusion of this examination +as most of the tax adjustments had been previously agreed to and accrued for at +December 31, 2006. We have received notice from the IRS that they +will be beginning the examination of our 2005 and 2006 returns in the near +future. +The tax +effects of temporary differences that give rise to significant portions of the +deferred tax assets and deferred tax liabilities at December 31, 2007 and 2006, +are presented below. +F-22 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +2007 +2006 +(in +thousands) +Deferred +tax assets: +Allowance +for doubtful accounts +$ +138 +$ +161 +Drilling +notes +31 +46 +Allowance +for lease impairment +912 +- +Litigation +allowance +578 +- +Deferred +revenue related to cash withheld for future plugging cost +1,011 +929 +Deferred +compensation +2,058 +2,105 +Asset +retirement obligations +7,782 +4,428 +Unrealized +loss - Derivatives +703 +- +Employee +benefits +456 +798 +Other +16 +- +Total +gross deferred tax assets +13,685 +8,467 +Less +valuation allowance +- +- +Deferred +tax assets +13,685 +8,467 +Deferred +tax liabilities: +Properties +and equipment, principally due to differences in depreciation and +amortization +(75,663 +) +(58,790 +) +Like +kind exchange - deferred gain +(69,836 +) +(63,783 +) +Unrealized +gains - derivatives +(55 +) +(1,203 +) +Total +gross deferred tax liabilities +(145,554 +) +(123,776 +) +Net +deferred tax liability +$ +(131,869 +) +$ +(115,309 +) +Classification +in the Consolidated Balance Sheets: +Net +current deferred tax assets* +$ +4,621 +$ +1,084 +Net +non-current deferred tax liability +(136,490 +) +(116,393 +) +Net +deferred tax liability +$ +(131,869 +) +$ +(115,309 +) +*included +in other current assets +As noted +above, deferred tax liabilities for properties and equipment increased in 2007 +and 2006 primarily as a result of our election to expense $44 million and $55 +million of IDC for income tax purposes. Deferred tax liabilities also +increased substantially in 2006 due to our utilization of the like-kind exchange +tax deferral for a portion of the taxable gain on the undeveloped land sale +( Note +16 ). In addition, approximately $9.8 million of the deferred +liability for properties and equipment is due to the Unioil +acquisition. +In +assessing whether a valuation allowance for the deferred tax assets should be +recorded, we consider whether it is more likely than not that some portion or +all of the deferred tax assets will not be realized. The ultimate +realization of deferred tax assets is dependent upon the generation of future +taxable income during the periods in which those temporary differences become +deductible. Based upon the level of historical taxable income and +projections for future taxable income over the periods in which the deferred tax +assets are deductible, we believe it is more likely than not that we will +realize the benefits of these deductible differences. The amount of +the deferred tax asset considered realizable, however, could be reduced in the +near term if estimates of future taxable income during the carryforward period +are reduced. +We +adopted the provisions of FIN No. 48 on January 1, 2007. As a result +of adoption, retained earnings decreased by $0.3 million, deferred income taxes +payable decreased by $0.9 million, current income taxes payable increased by +$0.2 million and the liability for unrecognized tax benefit increased by $1.0 +million. +F-23 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +The +following table sets forth a reconciliation of the total amounts of unrecognized +tax benefits for 2007: +(in +thousands) +Balance, +January 1, 2007 +$ +952 +Gross +increases for tax positions of prior years +819 +Gross +decrease for tax positions of prior years +(883 +) +Settlements +- +Lapses +of applicable statute of limitation +- +Unrecognized +tax benefits at Balance, December 31, 2007 +$ +888 +Interest +and penalties related to uncertain tax positions are recognized in income tax +expense. As of January 1, 2007, and December 31, 2007 we have +approximately $0.3 million and $0.1 million of accrued interest related to +uncertain tax positions, respectively. In addition, at December 31, +2007, $0.2 million of income tax penalties were accrued while no income tax +penalties were accrued at January 1, 2007. The total amount of +unrecognized tax benefits that would affect the effective tax rate, if +recognized, is $0.4 million as of December 31, 2007 and zero as of January 1, +2007. We expect the unrecognized tax benefit at December 31, 2007, to +decrease in the next twelve months because of the IRS examination of our 2005 +and 2006 tax years that will be conducted in 2008. It is currently +estimated that the decrease in our unrecognized tax benefits will be between +$0.4 million and $0.9 million primarily due to settlements. +The +statute of limitations for tax years 2003-2006 remains open for both federal and +state taxing jurisdictions for the tax years 2003-2006. However, due +to the recent July 31, 2007 completion date of the federal examination of our +2003 and 2004 tax years, we believe that certain tax positions related to these +tax years have been “effectively settled” for federal tax purposes. +Our +subsidiary, Unioil Inc., which was acquired on December 6, 2006, filed separate +tax returns for years prior to the acquisition date. Unioil’s +2003-2006 tax returns remain open to examination at December 31, +2007. Any unrecognized tax benefit associated with Unioil's tax +returns is included in the above table amount. +NOTE +7 - ASSET RETIREMENT OBLIGATIONS +Changes +in carrying amounts of the asset retirement obligations associated with our +working interest in oil and gas properties are as follows: +2007 +2006 +(in +thousands) +Balance +at beginning of year +$ +11,966 +$ +8,333 +Obligations +assumed with development activities and acquisitions +7,909 +1,264 +Obligations +discharged with disposed properties and asset retirements +(93 +) +(115 +) +Accretion +expense +999 +515 +Revisions +to estimated cash flows +- +1,969 +Balance +at end of year +$ +20,781 +$ +11,966 +If the +fair value of the estimated asset retirement obligation changes, an adjustment +is recorded to both the asset retirement obligation and the asset retirement +cost. Approximately $0.1 million of the asset retirement obligations +were classified as short-term and included in other accrued expenses as of +December 31, 2007 and 2006. +F-24 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +NOTE +8 - COMMITMENTS AND CONTINGENCIES +Drilling and Development +Agreements . We are a party to a pipeline expansion agreement +with an unrelated third party, which is also currently the purchaser of the +majority of our Wattenberg Field natural gas production. Pursuant to +the agreement, we have agreed to invest a minimum of $65 million to develop +specified acreage in the Wattenberg Field, during a three-year period ending +December 31, 2009. Such capital spending will include costs to drill +new wells and the cost to recomplete existing wells in this +area. Should we not meet the minimum commitment by December 31, 2009, +we will be required to pay liquidated damages of $2 million, prorated based on +our actual capital investment made to date. As of December 31, 2007, +our total capital expenditures pursuant to the agreement were $27.5 million, +resulting in a maximum potential obligation of $1.2 million. +In +connection with the sale of undeveloped leaseholds in July 2006, we were +obligated to either drill 16 wells on specifically identified acreage over the +next three years or pay liquidated damages of $1.6 million per undrilled well +for a total contingent obligation of $25.6 million, which was reflected as a +deferred gain on sale of leaseholds in our consolidated balance sheet at +December 31, 2006. On May 31, 2007, we entered into a letter +agreement amending the original purchase and sale agreement. The +letter agreement relieved us of the obligation, in its entirety, to either drill +16 wells or pay liquidated damages, resulting in the recognition of the +remaining $25.6 million deferred gain on sale of leaseholds in the quarter ended +June 30, 2007. +Pursuant +to the above letter agreement, we are obligated to drill six wells on +specifically identified acreage. These wells will be drilled on the +unaffiliated party's leasehold for its benefit and at its cost. In +addition, the unaffiliated party will return 160 acres of leasehold property +acquired from us pursuant to the purchase and sale agreement. As of +the date of this report, we have drilled the six wells and received the 160 +acres of leasehold property. +In +connection with the acquisition of oil and gas properties in October 2007, we +are obligated to drill 100 wells in the Appalachian Basin by January +2016. We will retain a majority interest in each well +drilled. For each well we fail to drill, we are obligated to pay to +the seller liquidated damages of $25,000 per undrilled well for a total +contingent obligation of $2.5 million or reassign to the seller the interest +acquired in the number of undrilled well locations. As of December +31, 2007, no wells had been drilled pursuant to this agreement. +Partnership Repurchase +Provision . Substantially all of our drilling programs contain +a repurchase provision where investing partners may request that we purchase +their partnership units at any time beginning with the third anniversary of the +first cash distribution. The provision provides that we are obligated +to purchase an aggregate of 10% of the initial subscriptions per calendar year +(at a minimum price of four times the most recent 12 months' cash +distributions), if repurchase is requested by investors, and subject to our +financial ability to do so. The maximum annual repurchase obligation +as of December 31, 2007, was approximately $6.7 million. We have +adequate liquidity to meet this obligation. During 2007 and 2006, we +paid $1.6 million and $0.8 million, respectively, under this provision for the +repurchase of partnership units. As of December 31, 2007, outstanding +repurchase offers to investing partners totaled $0.5 million, principally all of +which were consummated in 2008 prior to expiration. +Performance +Supplements . Our drilling programs formed from 1996 through +the second quarter of 2005 contain a performance supplement that provides for +changes in the distribution of partnership profits if certain levels of +performance are not met. The terms of this provision in the +partnership agreements are not a guarantee of a rate of return on an investment +in the partnership. Under those specific conditions, such changes can +result in our share of an affected partnership’s profits being reduced by up to +one half of the amount to which we otherwise would be entitled in the affected +period. In no event would we be obligated to assume a +disproportionate share of losses in such partnerships; should the partnerships +which contain this provision in the partnership agreements incur a loss, our +share of such losses would be unaffected by the terms of this +provision. In accordance with these provisions, our share of +partnership profits was reduced by an aggregate of $0.6 million, $1 million and +$0.7 million during 2007, 2006 and 2005, respectively. As of December +31, 2007 and 2006, based on production through December 31 of the corresponding +year, we had accrued $0.2 million and $0.4 million, respectively. +Partnership Casualty +Losses. As Managing General Partner of 33 partnerships, we +have liability for any potential casualty losses in excess of the partnership +assets and insurance. We believe the casualty insurance coverage that +we and our subcontractors carry is adequate to meet this potential +liability. +F-25 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Drilling Rig +Contracts. In order to secure the services for drilling rigs, +we made commitments to the drilling contractors, which call for a minimum +commitment of $12,500 daily for a specified amount of time if we cease to use +the drilling rigs, an event that is not anticipated to occur, and a maximum +commitment of $40,680 daily for a specified amount of time for daily use of the +drilling rigs. As of December 31, 2007, commitments for these two +separate contracts expire in August 2009 and July 2010. As +of December 31, 2007, we have an outstanding minimum commitment for $6.4 million +and an outstanding maximum commitment for $24.7 million. +Litigation . We are +involved in various legal proceedings that we consider normal to our +business. Although the results cannot be known with certainty, we +believe that we have properly accrued reserves and that the ultimate results of +such proceedings, will not have a material adverse effect on our financial +position or results of operations. +On May +29, 2007, Glen Droegemueller, individually and as representative plaintiff on +behalf of all others similarly situated, filed a class action complaint against +the Company in the District Court, Weld County, Colorado alleging that we +underpaid royalties on natural gas produced from wells operated by us in the +State of Colorado (the "Droegemueller Action"). The plaintiff seeks +declaratory relief and to recover an unspecified amount of compensation for +underpayment of royalties paid by us pursuant to leases. We removed +the case to Federal Court on June 28, 2007, and on July 10, 2007, we filed its +answer and affirmative defenses. A second similar Colorado class +action suit was filed against the Company in the U.S. District Court for the +District of Colorado on December 3, 2007, by Ted Amsbaugh et al. On +December 31, 2007, plaintiff in this second action filed a motion to consolidate +the case with the Droegemueller Action above. On January 28, 2008, +the Court granted plaintiff’s motion to consolidate the action with the +Droegemueller Action. On February 29, 2008, the court approved a 90 +day stay in proceedings while the parties pursue mediation of the +matter. Given the preliminary stage of this proceeding and the +inherent uncertainty in litigation, we are unable to predict the ultimate +outcome of this suit at this time. We believe that the ultimate +outcome of the proceedings will not have a material adverse effect on our +financial condition or results of operations. +Litigation +similar to the preceding actions has recently been commenced against several +other companies in other jurisdictions where we conduct +business. While our business model differs from that of the parties +involved in such other litigation, and although the Company has not been named +as a party in such other litigation, there can be no assurance that the Company +will not be named as a party to such other litigation in the +future. +Employment Agreements with Executive +Officers . We have employment agreements with our Chief +Executive Officer, Chief Financial Officer, Chief Accounting Officer and other +executive officers. The employment agreements provide for base annual +base salaries, eligibility for performance bonus compensation, and other various +benefits, including retirement and termination benefits. +In the +event of termination without cause or if an executive officer terminates +employment for good reason, the executive officer is entitled to receive a +payment in the amount of three times the sum of his highest base salary during +the previous two years of employment immediately preceding the termination date +and his highest bonus received during the same two year period. The +executive officer is also entitled to (i) vesting of any unvested equity +compensation, (ii) reimbursement for any unpaid expenses, (iii) retirement +benefits earned under the current and/or previous agreements, (iv) continued +coverage under our medical plan for up to 18 months, and (v) payment of any +earned and unpaid bonus amounts. In addition, the executive officer +is entitled to receive any benefits that he would have otherwise been entitle to +receive under our 401(k) and profit sharing plan, although those benefits are +not increased or accelerated. See Note 19 for a +discussion regarding the departure of our President for good +reason. +In the +event that an executive officer is terminated for just cause, we are required to +pay the executive officer his base salary through the termination date plus any +bonus (only for periods completed and accrued, but not paid), incentive, +deferred, retirement or other compensation, and to provide any other benefits, +which have been earned or become payable as of the termination date but which +have not yet been paid or provided. +In the +event that an executive officer voluntarily terminates his employment for other +than good reason, he is entitled to receive (i) his base salary, bonus and +incremental retirement payment prorated for the portion of the year that the +executive officer is employed, (ii) any incentive, deferred or other +compensation which has been earned or has become payable, but which has not yet +been paid under the schedule originally contemplated in the agreement under +which they were granted or in full without discount within 60 days of the +termination date at our discretion, (iii) any unpaid expense reimbursement upon +presentation by the executive officer of an accounting of such expenses in +accordance with our normal practices, and (iv) any other payments for benefits +earned under the employment agreement or our plans. +F-26 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Derivative +Contracts . We would be exposed to oil and natural gas price +fluctuations on underlying purchase and sale contracts should the counterparties +to our derivative instruments or the counterparties to our gas marketing +contracts not perform. Nonperformance is not +anticipated. There were no counterparty default losses in 2007, 2006 +or 2005. +NOTE +9 - COMMON STOCK +Stock-Based +Compensation Plans +As +approved by the shareholders in June 2004, we maintain a long-term equity +compensation plan for officers and certain key employees of (the "2004 +Plan"). In accordance with the plan, awards may be issued in the form +of stock options, stock appreciation rights, restricted stock or performance +shares. A total of 750,000 new shares of common stock have been +reserved for issuance. Awards pursuant to the plan vest over periods +set at the discretion of the Compensation Committee of our Board of Directors +(“Board”) and have a maximum exercisable period of ten years. As of +December 31, 2007, 468,984 common shares remain available for future +awards. +As +approved by the shareholders in June 2005, we also maintain a restricted stock +plan for non-employee directors. A total of 40,000 new shares of +common stock have been reserved for issuance under the plan. During +2007, 2006 and 2005, 12,710, 6,551 and 6,895 common shares, respectively, +were awarded in accordance with the plan. Compensation expense for +each of the years ended December 31, 2007, 2006 and 2005, related to these +restricted shares was $0.2 million, $0.1 million and $0.1 million, +respectively. As of December 31, 2007, 13,844 common shares remain +available for future awards. +In August +1999, the shareholders approved the 1999 Incentive Stock Option and +Non-Qualified Stock Option Plan. A total of 500,000 shares of our +common stock were reserved for issuance upon the exercise of stock +options. All shares authorized to be awarded pursuant to this plan +were awarded in years prior to 2002. At December 31, 2007, options +for 11,000 common shares remain outstanding and exercisable through 2011, at +which time the options will expire. +The +following table provides a summary of the effect of our stock based compensation +plans on the results of operations for the periods presented. Prior +to the adoption of SFAS No. 123R, we did not recognize stock based compensation +expense in our financial statements. +Year +Ended December 31, +2007 +2006 +(in +thousands) +Total +stock based compensation expense +$ +2,286 +$ +1,516 +Income +tax benefit +(882 +) +(585 +) +Net +income impact +$ +1,404 +$ +931 +Stock Option +Awards. We granted stock options in previous years under +several stock compensation plans. Outstanding options expire ten +years from the date of grant and become exercisable ratably over a four year +period. We did not grant any stock option awards in 2007 or +2006. The fair values of stock options granted during the year ended +December 31, 2006, were estimated at the date of grant using a Black-Scholes +option-pricing model assuming no dividends and the following weighed average +assumptions: +2006 +Expected +volatility +40.4 +% +Expected +term (in years) +6.0 +Risk-free +interest rate +4.2 +% +Weighted-average +grant date fair +value per share +$ +20.30 +F-27 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Expected +volatilities are based on our historical volatility. The expected +life of an award is estimated using historical exercise behavior +data. The risk-free interest rate is based on the U.S. Treasury +yields in effect at the time of grant and extrapolated to approximate the +expected life of the award. We do not expect to pay dividends, nor do +we expect to declare dividends in the foreseeable future. +The +following table provides a summary of our stock option award activity for the +year ended December 31, 2007: +Weighted +Weighted +Average +Number +of +Average +Remaining +Shares +Exercise +Contractual +Underlying +Price +Term +Options +Per +Share +(years) +Outstanding +at December 31, 2006 +89,567 +$ +21.36 +5.6 +Exercised +(38,000 +) +4.81 +Outstanding +at December 31, 2007 +51,567 +33.55 +6.4 +Vested +and expected to vest at December 31, 2007 +46,340 +32.51 +6.2 +Exercisable +at December 31, 2007 +29,582 +26.30 +5.1 +Year +Ended December 31, +(in +millions) +2007 +2006 +2005 +Total +intrinsic value of options exercised +$ +1.7 +$ +0.3 +$ +0.1 +Total +intrinsic value of options outstanding +1.3 +2.0 +1.6 +Total +intrinsic value of options exercisable +1.0 +1.9 +1.6 +The +intrinsic value of options exercised represents the amount by which the market +value of our stock at date of exercise exceeds the exercise price of the +option. The intrinsic values of the options outstanding and +exercisable represent the amount by which the closing market price of our common +stock at the last trading day of the year exceeds the exercise price of the +options. +Total +unrecognized compensation cost related to stock options granted under the 2004 +Plan was $0.2 million as of December 31, 2007. This cost is expected +to be recognized over a weighted average period of 2.2 years. +Restricted +Stock Awards +We began +issuing shares of restricted common stock to employees in 2004. Our +restricted stock awards have been awarded with vesting conditions that are +either time-based or market-based. +Time-Based +Awards . The fair value +of the time-based awards is amortized ratably over the requisite service period, +primarily over four years. +The +following table sets forth the changes in non-vested time-based awards for the +year ended December 31, 2007: +Shares +Weighted +Average Grant-Date Fair Value +Non-vested +at December 31, 2006 +131,730 +$ +39.87 +Granted +79,595 +48.09 +Vested +(37,341 +) +36.63 +Forfeited +(2,139 +) +40.07 +Non-vested +at December 31, 2007 +171,845 +$ +44.38 +F-28 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Year +Ended December 31, +(in +millions) +2007 +2006 +2005 +Total +intrinsic value of time-based awards vested +$ +2.2 +$ +0.8 +$ +0.2 +Total +intrinsic value of time-based awards non-vested +10.2 +5.7 +1.3 +The +intrinsic value above is based upon the closing market price of our common stock +on the last trading date of the year, $59.13. +The total +compensation cost related to non-vested time-based awards not yet recognized as +of December 31, 2007, is $5.3 million. This cost is expected to be +recognized over a weighted-average period of 2.7 years. +Market-Based +Awards . The fair value of the market-based awards is amortized +ratably over the requisite service period, primarily over three years for +market-based awards. The market-based shares vest only upon the +achievement of certain per share price thresholds and continuous employment +during the vesting period. All compensation cost related to the +market based-awards will be recognized if the requisite service period is +fulfilled, even if the market condition is not achieved. +The +weighted average grant date fair value of each market-based share was computed +using the Monte Carlo pricing model and the following weighted average +assumptions: +Expected +term of award +3 +years +Risk-free +interest rate +4.7 +% +Volatility +44.0 +% +The +following table sets forth the changes in non-vested marked-based awards for the +year ended December 31, 2007: +Shares +Weighted +Average Grant-Date Fair Value +Non-vested +at December 31, 2006 +- +$ +- +Granted +31,972 +36.07 +Vested +- +- +Forfeited +- +- +Non-vested +at December 31, 2007 +31,972 +$ +36.07 +The +intrinsic value of market-based awards outstanding at December 31, 2007, was +$1.9 million, based upon the closing market price of our common stock on the +last trading date of the year, $59.13. +The total +compensation cost related to non-vested market-based awards not yet recognized +as of December 31, 2007, is $0.4 million. This cost is expected to be +recognized over a weighted-average period of 2 years. +Treasury +Share Purchases +In +January 2006, we announced that our Board authorized the purchase of up to 10% +(1,627,500 shares) of our common stock during 2006. Stock purchases +under this program were made in the open market or in private transactions, at +times and in amounts that we deemed appropriate. In October 2006, we +completed our January 2006 program. Total shares purchased pursuant +to the program were 1,627,500 common shares at a cost of $66.3 million ($40.75 +average price paid per share), including 100,000 shares from one of our +executive officers at a cost of $4.1 million ($40.66 price paid per +share). All shares purchased in accordance with the program have +subsequently been retired. +F-29 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +On +October 16, 2006, our board of directors of approved a second 2006 purchase +program authorizing us to purchase up to 10% (1,477,109 shares) of our then +outstanding common stock through April 2008. Stock purchases under +this program may be made in the open market or in private transactions, at times +and in amounts that we deem appropriate. Shares are generally +purchased at fair market value based on the closing price on the date of +purchase. Total shares purchased in 2007 pursuant to the program were +12,020 common shares at a cost of $0.6 million ($53.78 average price paid per +share), including 5,187 shares from our executive officers at a cost of $0.3 +million ($57.93 price paid per share). Shares purchased pursuant to +the plan were primarily to satisfy the statutory minimum tax withholding +requirement for restricted stock that vested in 2007. All shares were +subsequently retired. +Pursuant to our senior notes indenture entered on February 8, +2008, any future purchases are limited, see Note 19, Subsequent Events , to our accompanying +consolidated financial statements. +On +February 25, 2008, pursuant to a separation agreement, we purchased 50,000 +shares of our common stock from one of our executive officers at a cost of $3.4 +million, or $67.92 per share. See Note 19 , Subsequent Events , to our +consolidated financial statements +NOTE 10 - SHAREHOLDERS' RIGHTS +AGREEMENT +On +September 11, 2007, we entered into a rights agreement, with Transfer Online, +Inc., as rights agent. The rights agreement is designed to improve +the ability of our board of directors to protect the interest of our +shareholders in the event of an unsolicited takeover attempt. Our +board declared a dividend of one right for each outstanding share of our common +stock. The right dividend was paid to shareholders of record on +September 14, 2007. A "distribution date," as defined in the rights +agreement, can occur after any individual shareholder exceeds 15% ownership of +our outstanding common stock. After the occurrence of a "distribution +date," the right entitles each registered holder (other than the acquiring +shareholder who triggered the "distribution date"), to purchase shares of our +common stock (or, in certain circumstances, cash, property or other securities) +having a then-current value equal to two times the exercise price of the right +(i.e., for the $240 exercise price, the rights holder receives $480 worth of +common stock). The exercise price is subject to adjustment for +various corporate actions which affect all shareholders, such as a stock +split. The rights agreement and all rights will expire on September +11, 2017. +NOTE +11 - EMPLOYEE BENEFIT PLANS +We +sponsor a qualified deferred compensation plan covering substantially all of our +employees. The plan consists of a 401(k) retirement plan with a +profit sharing component. The plan enables eligible employees to +contribute a portion of their compensation through payroll deductions in +accordance with specific guidelines. We provide a discretionary +matching contribution based on a percentage of the employees' contributions up +to certain limits. Our contribution to the profit sharing component +is discretionary. Our total combined expense for to both 401(k) and +profit sharing in 2007, 2006 and 2005, were $1.4 million, $3.1 million and $0.9 +million, respectively. +We +provide a supplemental retirement benefit of deferred compensation under terms +of the various employment agreements with certain executive +officers. During 2007, 2006 and 2005, we charged $0.4 million, $0.3 +million and $0.2 million related to this plan to general and administrative +expenses, respectively, and we have recorded a related liability in the amount +$2.2 million and $1.9 million as of December 31, 2007 and 2006, +respectively. +In +addition to the supplemental retirement benefit of deferred compensation, we +offer a supplemental healthcare benefit covering certain executive officers and +their spouses in accordance with each officer's employment +agreement. Expense incurred during 2007 related to this plan was +immaterial. As of December 31, 2007, we had a recorded liability of +$0.6 million. +We +maintain a non-qualified deferred compensation plan for our non-employee +directors. The amount of compensation deferred by each participant is +based on participant elections. The amounts deferred pursuant to the +plan are invested in our common stock, maintained in a rabbi trust and are +classified in the accompanying balance sheet as treasury shares as a component +of shareholders' equity. The plan may be settled in either cash or +shares as requested by the participant. As of December 31, 2007, we +had recorded a long-term liability of $0.3 million, which is included in other +liabilities in our consolidated balance sheet. +F-30 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +NOTE +12 - EARNINGS PER SHARE +The +following is a reconciliation of the numerators and denominators used in the +calculation of basic and diluted earnings per share for the years ended December +31: +2007 +2006 +2005 +(in +thousands, except per share data) +Weighted +average common shares outstanding +14,744 +15,660 +16,362 +Dilutive +effect of share-based compensation: (1) +Unamortized +portion of restricted stock +44 +22 +13 +Stock +options +48 +55 +52 +Non +employee director deferred compensation +5 +4 +- +Weighted +average common and common equivalent shares outstanding +14,841 +15,741 +16,427 +Net +income +$ +33,209 +$ +237,772 +$ +41,452 +Basic +earnings per common share +$ +2.25 +$ +15.18 +$ +2.53 +Diluted +earnings per common share +$ +2.24 +$ +15.11 +$ +2.52 +(1) Excludes the effect of average +anti-dilutive common share equivalents related to out-of-the-money options and +unvested restricted shares of zero and 18,004 in 2007, 23,687 and zero in 2006 +and 16,880 and zero in 2005, respectively. +NOTE +13 - TRANSACTIONS WITH AFFILIATES +Funds +held for future distribution on our consolidated balance sheets represent +amounts owed to affiliated partnerships for production proceeds received by us +on their behalf and undistributed as of December 31, 2007 and 2006. +Amounts +due from/to the affiliated partnership are primarily related to derivative +positions, unbilled well lease operating expenses, and costs resulting from +audit and tax preparation services. +Our +natural gas marketing segment manages the marketing of oil and natural gas for +our affiliated partnerships in the Appalachian Basin. Our sales from +of natural gas marketing activities includes $9.3 million, $17.6 million and +$22.2 million in 2007, 2006 and 2005, respectively, related to the marketing of +oil and natural gas on behalf of our affiliated +partnerships. Included in our cost of natural gas marketing +activities is $9.1 million, $17.3 million and $22.2 million for 2007, 2006 and +2005, respectively, related to these sales . +We +provided oil and gas well drilling services to our affiliated +partnerships. Pursuant to our cost-plus drilling arrangements and our +corresponding net presentation, we performed drilling services for our +affiliated partnerships totaling $68.4 million and $87 million in 2007 and 2006, +for which we recognized $11.4 million and $12.4 million in oil and gas well +drilling operations revenue, respectively. Pursuant to our +footage-based drilling arrangements and our corresponding gross presentation, in +2005, we billed our affiliated partnerships for drilling services and recognized +oil and gas well drilling operations revenue of $100 +million. Further, we provide well operations and pipeline services to +our affiliated partnerships. Substantially all of our revenue and +expenses related to oil and gas well drilling operations and revenues from well +operations and pipeline income are associated with services provided to our +affiliated partnerships. +Revenues +from oil and gas well drilling operations and costs of oil and gas well drilling +operations each include $0.1 million and $0.2 million during 2006 and 2005, +respectively, related to investments made by executive officers for working +interests in wells drilled during the respective years. Amounts +invested by the executive officers during 2007 were immaterial. +Management +fees collected from the affiliated partnerships amounted to $1.3 million in 2007 +and 2006 and $1.7 million in 2005, respectively, which are included in other +income on our consolidated statements of income. +Through +our wholly-owned subsidiary, PDC Securities Incorporated, we act as +Dealer-Manager of the drilling partnerships. PDC Securities receives +the applicable commissions and marketing allowances from the Escrow Agent of the +drilling program and distributes them to the soliciting broker/dealers who sell +the programs. The commissions and marketing allowances received by +PDC Securities are included in other income net of the commissions distributed +to the soliciting broker/dealer. The commissions and marketing +allowances retained by PDC Securities were $0.5 million, $0.6 million and $0.5 +million and those distributed to the soliciting broker/dealers amounted to $8.3 +million, $8.8 million and $11.4 million for the years ended December 31, 2007, +2006 and 2005, respectively. +F-31 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +NOTE +14 - LEASE OBLIGATIONS +We +have entered into operating leases principally for the leasing of natural gas +compressors, our Denver office space, and general office +equipment. The future minimum lease payments under these +non-cancelable operating leases as of December 31, 2007, are as +follows: +Year +(in +thousands) +2008 +$ +1,850 +2009 +1,131 +2010 +534 +2011 +430 +2012 +92 +Thereafter +- +$ +4,037 +Lease +operating expense for the years ended December 31, 2007, 2006 and 2005 was $1.5 +million, $0.4 million and $0.3 million, respectively. +NOTE +15 – DERIVATIVE FINANCIAL INSTRUMENTS +We +are exposed to the effect of market fluctuations in the prices of oil and +natural gas as they relate to our oil and natural gas sales and natural gas +marketing segments. Price risk represents the potential risk of loss +from adverse changes in the market price of oil and natural gas +commodities. We employ established policies and procedures to manage +the risks associated with these market fluctuations using commodity +derivatives. Our policy prohibits the use of oil and natural gas +derivative instruments for speculative purposes. +Validation +of a contract’s fair value is performed internally and while we use common +industry practices to develop our valuation techniques, changes in our pricing +methodologies or the underlying assumptions could result in significantly +different fair values. +Economic Hedging +Strategies . Our results of operations and operating cash flows +are affected by changes in market prices for oil and natural gas. To +mitigate a portion of the exposure to adverse market changes, we have entered +into various derivative instruments. As of December 31, 2007, our oil +and natural gas derivative instruments were comprised of futures, swaps and +collars. These instruments generally consist of New York Mercantile +Exchange ("NYMEX") -traded natural gas futures contracts and option contracts +for Appalachian and Michigan production, Panhandle-based contracts and +NYMEX-traded contracts for NECO production and Colorado Interstate Gas Index +("CIG") -based contracts for other Colorado production and NYMEX-based swaps for +our Colorado and North Dakota oil production. +· +For +swap instruments, we receive a fixed price for the hedged commodity and +pay a floating market price to the counterparty. The +fixed-price payment and the floating-price payment are netted, resulting +in a net amount due to or from the +counterparty. +· +Collars +contain a fixed floor price (put) and ceiling price (call). If +the market price exceeds the call strike price or falls below the fixed +put strike price, we receive the fixed price and pay the market +price. If the market price is between the call and the put +strike price, no payments are due from either +party. +We +purchase puts and set collars and swaps for our own and affiliate partnerships’ +production to protect against price declines in future periods while retaining +much of the benefits of price increases. RNG enters into fixed-price +physical purchase and sale agreements that are derivative +contracts. In order to offset these fixed-price physical derivatives, +we enter into financial derivative instruments that have the effect of locking +in the prices we will receive or pay for the same volumes and period, offsetting +the physical derivative. While these derivatives are structured to +reduce our exposure to changes in price associated with the derivative +commodity, they also limit the benefit we might otherwise have received from +price changes in the physical market. We believe our derivative +instruments continue to be highly effective in achieving the risk management +objectives for which they were intended. +F-32 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +The net +fair value of the commodity based derivatives was $(1.4) million of which $0.2 +million is included in other long term assets at December 31, +2007. The net fair value of the commodity based derivatives was $13.6 +million of which $1.1 million is included in other long term assets at December +31, 2006. We recognized in the statement of income unrealized losses +on commodity based derivatives of $4.6 million in 2007, unrealized gains of $7.6 +million in 2006, and unrealized losses of $3.2 million in 2005. +At +December 31, 2007 and 2006, we had the following open commodity based derivative +instruments designed as an economic hedge for a portion of our oil and natural +gas production for periods after December 2007: +Petroleum +Development Corporation +Open +Derivative Positions +(dollars +in thousands, except average price data) +Quantity +Weighted +Total +Gas-MMbtu +Average +Contract +Commodity +Type +Oil-Barrels +Price +Amount +Fair +Value +Total +Positions as of December 31, 2007 +Natural +Gas +Cash +Settled Option Sales +14,500,000 +$ +10.69 +$ +155,044 +$ +(293 +) +Natural +Gas +Cash +Settled Option Purchases +16,360,000 +5.76 +94,283 +3,366 +Oil +Cash +Settled Futures/Swaps Purchases +585,600 +84.20 +49,308 +(5,097 +) +$ +(2,024 +) +Positions +maturing in 12 months following December 31, 2007 +Natural +Gas +Cash +Settled Option Sales +14,500,000 +$ +10.69 +$ +155,044 +$ +(293 +) +Natural +Gas +Cash +Settled Option Purchases +16,360,000 +5.76 +94,283 +3,366 +Oil +Cash +Settled Futures/Swaps Purchases +585,600 +84.20 +49,308 +(5,097 +) +$ +(2,024 +) +The +maximum term for the derivative contracts listed above is 12 +months. +Total +Positions as of December 31, 2006 +Natural +Gas +Cash +Settled Option Sales +17,390,000 +$ +5.56 +$ +96,613 +$ +12,597 +Natural +Gas +Cash +Settled Option Purchases +2,155,000 +10.34 +22,287 +(14 +) +Oil +Cash +Settled Option Purchases +300,000 +50.00 +15,000 +155 +$ +12,738 +F-33 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Riley +Natural Gas +Open +Derivative Positions +(dollars +in thousands, except average price data) +Weighted +Total +Quantity +Average +Contract +Commodity +Type +Gas-MMbtu +Price +Amount +Fair +Value +Total +Positions as of December 31, 2007 +Natural +Gas +Cash +Settled Futures/Swaps Purchases +588,950 +$ +7.79 +$ +4,586 +$ +(246 +) +Natural +Gas +Cash +Settled Futures/Swaps Sales +2,085,400 +8.50 +17,722 +1,236 +Natural +Gas +Cash +Settled Basis Swap Purchases +397,500 +0.54 +214 +3 +Natural +Gas +Physical +Purchases +2,085,400 +8.51 +17,748 +(473 +) +Natural +Gas +Physical +Sales +518,951 +8.50 +4,409 +129 +$ +649 +Positions +maturing in 12 months following December 31, 2007 +Natural +Gas +Cash +Settled Futures/Swaps Purchases +588,950 +$ +7.79 +$ +4,586 +$ +(246 +) +Natural +Gas +Cash +Settled Futures/Swaps Sales +1,568,400 +8.54 +13,391 +1,318 +Natural +Gas +Cash +Settled Basis Swap Purchases +397,500 +0.54 +214 +3 +Natural +Gas +Physical +Purchases +1,568,400 +8.32 +13,044 +(655 +) +Natural +Gas +Physical +Sales +518,951 +8.50 +4,409 +129 +$ +549 +The +maximum term for the derivative contracts listed above is 48 +months. +Total +Positions as of December 31, 2006 +Natural +Gas +Cash +Settled Futures/Swaps Purchases +246,900 +$ +7.34 +$ +1,811 +$ +(304 +) +Natural +Gas +Cash +Settled Futures/Swaps Sales +1,952,150 +8.42 +16,444 +2,815 +Natural +Gas +Cash +Settled Basis Swap Purchases +90,000 +0.42 +38 +(12 +) +Natural +Gas +Cash +Settled Basis Swap Sales +20,000 +0.50 +10 +4 +Natural +Gas +Cash +Settled Option Purchases +220,000 +5.50 +1,210 +64 +Natural +Gas +Cash +Settled Option Sales +110,000 +10.10 +1,111 +(39 +) +Natural +Gas +Physical +Purchases +1,964,150 +8.27 +16,244 +(1,974 +) +Natural +Gas +Physical +Sales +114,974 +9.62 +1,106 +310 +Natural +Gas +Physical +Basis Purchases +20,000 +0.45 +9 +(3 +) +Natural +Gas +Physical +Basis Sales +90,000 +0.44 +39 +14 +$ +875 +In +addition to including the gross assets and liabilities related to our share of +oil and gas production, the above tables and our consolidated balance sheets +include the gross assets and liabilities related to derivative contracts we +entered into on behalf of the affiliate partnerships as the managing general +partner. Our consolidated balance sheets include the fair value of +derivatives and a corresponding net receivable from the partnerships of $1.5 +million at December 31, 2007, and a corresponding net payable to the +partnerships of $7.5 million as of December 31, 2006. +We are +required to maintain margin deposits with brokers for outstanding futures +contracts. As of December 31, 2007 and 2006, restricted cash in the +amount of $0.3 million and $0.5 million was on deposit. +F-34 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +The +following table identifies the fair value of commodity based derivatives as +classified in our consolidated balance sheets. +December +31, +December +31, +2007 +2006 +(in +thousands) +Classification +in the Condensed Consolidated Balance Sheets: +Fair +value of derivatives - current asset +$ +4,817 +$ +15,012 +Other +assets - long-term asset +193 +1,146 +5,010 +16,158 +Fair +value of derivatives - current liability +6,291 +2,545 +Other +liabilities - long-term liability +93 +- +6,384 +2,545 +Net +fair value of commodity based derivatives - (liability) +asset +$ +(1,374 +) +$ +13,613 +The +following changes in the fair value of commodity based derivatives are reflected +in our consolidated statements of income (in millions): +Twelve +Months Ended December 31, +2007 +2006 +2005 +Statement +of income line item +Realized +Unrealized +Realized +Unrealized +Realized +Unrealized +(in +thousands, gain/(loss)) +Oil +and gas price risk management gain (loss), net +(1) +$ +7,173 +$ +(4,417 +) +$ +1,895 +$ +7,252 +$ +(6,367 +) +$ +(3,001 +) +Sales +from natural gas marketing activities +(2) +3,870 +(1,736 +) +2,592 +12,291 +(5,643 +) +(8,472 +) +Cost +of natural gas marketing activities +(2) +(482 +) +1,511 +(1,908 +) +(11,923 +) +(1,266 +) +8,247 +__________ +(1) +Includes +realized and unrealized gains and losses on commodity based derivative +instruments related to PDC. +(2) +Includes +realized and unrealized gains and losses on commodity based derivatives +instruments related to RNG only. +Pursuant +to SFAS No. 133, at this time our derivatives do not qualify for designation as +cash flow hedges. Changes in the fair value of these non-qualifying +derivatives that occur prior to their maturity (i.e., temporary fluctuations in +value) are reported currently in our consolidated statements of operations as +unrealized gains (losses). Oil and gas price risk management gain +(loss), net includes realized and unrealized gains and losses on commodity based +derivatives related to our oil and gas sales. Gas sales from +marketing activities and cost of gas marketing activities includes realized and +unrealized gains and losses on commodity based derivatives related to the RNG +gas sales and gas purchases, respectively. +NOTE +16 - SALE OF OIL AND GAS PROPERTIES +Grand +Valley Field Properties +In July +2006, we sold to an unaffiliated company a portion of our undeveloped leasehold +located in Grand Valley Field, Garfield County, Colorado. The sale +encompassed 100% of the working interest in approximately 8,700 acres, including +approximately 6,400 acres of the Chevron leasehold and 2,300 acres of the +Puckett Land Company leasehold. We retained approximately 475 +undeveloped locations on 10 acre spacing on the Grand Valley Field leasehold in +addition to all of our producing properties in the field. The +proceeds from the sale were $353.6 million. We recorded a gain on +sale of leaseholds of $328 million and a deferred gain on sale of leaseholds of +$25.6 million. +Pursuant +to the purchase and sale agreement, we were obligated to either drill 16 wells +on specifically identified acreage over the next three years or pay liquidated +damages of $1.6 million per un-drilled well for a total contingent obligation of +$25.6 million, which was reflected as a deferred gain on sale of leaseholds on +the balance sheet as of December 31, 2006. In May 2007, we entered +into a letter agreement amending the original purchase and sale +agreement. The letter agreement relieved us of the obligation, in its +entirety, to either drill 16 wells or pay liquidated damages, resulting in the +recognition of the remaining $25.6 million deferred gain on sale of leaseholds +in the second quarter of 2007. Pursuant to the letter agreement, we +were obligated to drill six wells on specifically identified +acreage. As of December 31, 2007, we had drilled all six wells, which +were drilled on the unaffiliated party's leasehold for its benefit and at its +cost. +F-35 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +In +conjunction with the purchase and sale agreement described above, we entered +into a LKE agreement, in accordance with Section 1031 of the Internal Revenue +Code, with a “qualified intermediary.” Proceeds in the amount of $300 +million were transferred directly to the qualified intermediary to be held in +trust pursuant to the terms of the LKE agreement. We had until +mid-January 2007 to close any acquisition of suitable like-kind property, +allowing us to take advantage of the income tax deferral benefits of a LKE +transaction. +In +December 2007, we sold to the same unaffiliated party above a portion of our +North Dakota properties for approximately $34.7 million. The +properties, located in Dunn, Williams and McKenzie Counties, North Dakota, +include interests in five producing Bakken wells and approximately 72,000 net +undeveloped acres. The reduction in our production and proved +reserves as a result of this transaction is not material. We recorded +a gain on sale of leaseholds of $7.7 million in the fourth quarter of +2007. The proceeds from the sale were used to pay down +debt. Following the sale, we retain ownership in three producing +wells in Dunn County, ten producing wells in Burke County and approximately +60,000 acres of undeveloped leasehold in Burke County. +During +2005, we sold a portion of an undeveloped leasehold in the Grand Valley Field to +an unaffiliated entity. The proceeds of the sale were $6.2 million +and our carrying value of the property was zero. The gain of $6.2 +million was recognized in 2005 and is included in gain on sale of leaseholds in +our consolidated statement of income. +Appalachian +Basin Properties +Additionally, +in 2005, we completed the sale to an unaffiliated party of 111 Pennsylvania +wells we purchased in 1998. We received proceeds of $3.4 million and +recorded a gain of $1.5 million, which is included in gain on sale of leaseholds +in our consolidated statement of income. +NOTE +17 - BUSINESS SEGMENTS +Our +operating activities can be divided into four major segments: oil and gas well +drilling operations, natural gas marketing, oil and gas sales, and well +operations and pipeline income. We drill natural gas wells for +Company-sponsored drilling partnerships and retain an interest in each +well. A wholly-owned subsidiary, Riley Natural Gas, engages in the +marketing of natural gas to commercial and industrial end-users. We +own an interest in approximately 4,354 wells from which we sell our oil and gas +production from our working interests in the wells. We charge +Company-sponsored partnerships and other third parties competitive industry +rates for well operations and gas gathering. All material +inter-company accounts and transactions between segments have been +eliminated. Segment information for the years ended December 31, +2007, 2006 and 2005 is presented below. +Year +Ended December 31, +2007 +2006 +2005 +Revenues: +(in +thousands) +Oil +and gas sales (1) +$ +177,943 +$ +124,336 +$ +93,191 +Natural +gas marketing +103,624 +131,326 +121,114 +Oil +and gas well drilling operations +12,154 +17,917 +99,963 +Well +operations and pipeline income +9,342 +10,704 +8,760 +Unallocated +amounts +2,172 +2,220 +2,170 +Total +$ +305,235 +$ +286,503 +$ +325,198 +Segment +Income Before Income Taxes: +Oil +and gas sales (2) +$ +42,068 +$ +61,868 +$ +46,095 +Natural +gas marketing +3,822 +1,816 +1,737 +Oil +and gas well drilling operations +9,646 +5,300 +11,778 +Well +operations and pipeline income (3) +3,136 +2,823 +3,539 +Unallocated +amounts (4)(5) +(4,482 +) +315,602 +2,979 +Total +$ +54,190 +$ +387,409 +$ +66,128 +F-36 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +As +of December 31, +2007 +2006 +2005 +Segment +Assets: +Oil +& gas sales +$ +862,237 +$ +394,952 +$ +251,897 +Natural +gas marketing +40,269 +39,899 +56,518 +Oil +and gas well drilling operations +4,959 +87,746 +89,030 +Well +operations and pipeline income +26,156 +28,895 +31,407 +Unallocated +amounts (6) +116,858 +332,795 +15,509 +Total +$ +1,050,479 +$ +884,287 +$ +444,361 +Year +ended December 31, +Expenditures +for Segment Long-Lived Assets: +Oil +& gas sales +$ +226,801 +$ +133,401 +$ +92,907 +Natural +gas marketing +- +- +1 +Oil +and gas well drilling operations +- +- +- +Well +operations and pipeline income +6,715 +1,419 +3,949 +Unallocated +amounts +5,472 +12,125 +2,452 +Total +$ +238,988 +$ +146,945 +$ +99,309 +(1) +Includes +oil and gas price risk management gain (loss), +net. +(2) +Includes +$23.6, $8.1 and $11.1 million in exploration costs and $68.1, $31.3 and +$19.3 million in DD&A expense in 2007, 2006 and 2005, +respectively. +(3) +Includes +$1.2, $1.9 and $1.5 million in DD&A expense in 2007, 2006 and 2005, +respectively. +(4) +Includes +interest income for PDC operations, $0.8, $0.6 and $0.3 million in +interest income allocated to natural gas marketing in 2007, 2006 and 2005, +respectively, in addition to partnership management +fees. +(5) +Includes +$1.6, $0.5, and $0.3 million in DD&A expense in 2007, 2006 and 2005 +respectively. +(6) +The +December 31, 2006, amount was expended in early 2007 in LKE transactions; +the assets and liabilities of which have been included in the oil and gas +sales segment. +NOTE 18 – SUPPLEMENTAL CASH +FLOW +Year +Ended December 31, +2007 +2006 +2005 +(in +thousands) +Cash +paid for: +Interest +$ +12,557 +$ +3,011 +$ +101 +Income +taxes +43,785 +46,735 +10,675 +Non-cash +investing activities: +Change +in deferred tax liability resulting from reallocation of acquisition +purchase price +4,188 +- +- +Changes +in accounts payable - affiliates related to acquisition of +partnerships +668 +- +- +Changes +in accounts payable related to purchases of properties and +equipment +32,820 +1,800 +- +Changes +related to investment in drilling partnership +18,712 +(7,151 +) +(7,160 +) +Asset +retirement obligation, with a corresponding increase to oil and gas +properties, net of disposals +7,850 +3,164 +(3 +) +NOTE +19 – SUBSEQUENT EVENTS +Issuance +and Sale of Senior Notes +On +February 8, 2008, we completed the issuance and sale of $203 million aggregate +principal amount of 12% senior notes due 2018. The senior notes were +offered and sold in private transactions pursuant to Rule 144A and Regulation S +under the Securities Act of 1933, as amended. The offer and sale of +the senior notes were not registered under the Securities Act. +The +senior notes accrue interest from February 8, 2008, at a rate of 12% per year +and interest is payable semi-annually in arrears on February 15 and August 15 of +each year, commencing on August 15, 2008. The notes are senior +unsecured obligations and rank, in right of payment, equally with all of our +existing and future senior unsecured indebtedness and senior to any of our +existing and future subordinated indebtedness. The notes are +effectively subordinated to any of our existing or future secured indebtedness +to the extent of the assets securing such indebtedness. +F-37 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +We may, +at our option, redeem all or part of the notes, at any time prior to February +15, 2013, at a make-whole price, and on or after February 15, 2013, at fixed +redemption prices, plus accrued and unpaid interest, if any, to the date of +redemption. +At any +time, which may be more than once, before February 15, 2011, we may redeem up to +35% of the outstanding notes with proceeds from one or more equity offerings at +a redemption price of 112% of the principal amount of the notes redeemed, plus +accrued and unpaid interest, as long as: +· +at +least 65% of the aggregate principal amount of the notes issued on +February 8, 2008, remains outstanding after each such redemption; +and +· +the +redemption occurs within 180 days after the closing of the equity +offering. +The +indenture governing the senior notes contains covenants that, among other +things, limit our ability and the ability of our restricted subsidiaries to +incur additional debt; make certain investments or pay dividends or +distributions on our capital stock or purchase or redeem or retire capital +stock; sell assets, including capital stock of our restricted subsidiaries; +restrict dividends or other payments by restricted subsidiaries; create liens +that secure debt; enter into transactions with affiliates; and merge or +consolidate with another company. +Additionally, +if we experience certain kinds of changes of control, we must give holders of +the notes the opportunity to sell to us their notes at 101% of their principal +amount, plus accrued and unpaid interest. +We used +the net proceeds from the sale of the senior notes to repay debt outstanding +under our revolving credit facility and for general corporate +purposes. +Registration +Rights Agreement +On +February 8, 2008, we entered into a registration rights agreement with the +initial purchasers named therein, pursuant to which we agreed to use our +commercially reasonable efforts to (i) file with the SEC a registration +statement on an appropriate form under the Securities Act relating to a +registered exchange offer for the notes described above under the Securities Act +and (ii) cause the exchange offer registration statement to be declared +effective under the Securities Act within 365 days following February 8, +2008. If we fail to comply with certain obligations under the +registration rights agreement, we will be required to pay liquidated damages to +the holders of our senior notes in accordance with the provisions of the +registration rights agreement. We do not believe it is probable that +we will be required to make such payments; therefore, have not recorded a +liability at this time. +Departure +of Executive Officer +On +February 8, 2008, we accepted the resignation for good reason of Thomas E. Riley +as our President and Director. In accordance with the provisions of +his employment agreement, Mr. Riley will receive a single lump sum cash payment +of $1,877,343 as separation compensation and retirement compensation equal to +$37,500 per year for ten years beginning January 1, +2009. Additionally, a separation agreement executed on February 8, +2008, provides for the of vesting 16,123 shares of restricted stock and stock +options to purchase 4,678 shares of our common stock. We will +recognize expense of approximately $3.2 million in the first quarter of 2008 in +connection with the resignation of Mr. Riley. +F-38 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +NOTE +20 – SUPPLEMENTAL OIL AND GAS INFORMATION - UNAUDITED +Costs +Incurred in Oil and Gas Property Acquisition, Exploration and Development +Activities (Unaudited) +We +incurred costs in oil and gas property acquisition, exploration and development +are presented below. +Year +Ended December 31, +2007 +2006 +2005 +(in +thousands) +Acquisition +of properties: +Proved +properties +$ +257,330 +$ +802 +$ +1,608 +Unproved +properties +13,701 +11,926 +16,910 +Development +costs +194,031 +114,487 +68,605 +Exploration +costs: +Exploratory +drilling +12,972 +18,660 +12,943 +Geological +and Geophysical +6,299 +2,234 +- +Total +costs incurred +$ +484,333 +$ +148,109 +$ +100,066 +The +proved reserves attributable to the development costs in the above table were +216,383 MMcf and 3,700 MBbls for 2007, 64,126 MMcf and 2,955 MBbls for +2006 and 76,669 MMcf and 1,576 MBbls for 2005. Of the above +development costs incurred for the years ended December 31, 2007, 2006 and 2005, +the amounts of $37.1 million, $20.1 million and $23.8 million, respectively, +were incurred to develop proved undeveloped properties from the prior year +end. +Property +acquisition costs include costs incurred to purchase, lease or otherwise acquire +a property. Development costs include costs incurred to gain access +to and prepare development well locations for drilling, to drill and equip +development wells, recompletions and to provide facilities to extract, treat, +gather and store oil and gas. Exploration costs include costs +incurred in identifying areas that may warrant examination and in examining +specific areas that are considered to have prospects of containing oil and gas +reserves. +Capitalized +Oil and Gas Costs (Unaudited) +Aggregate +capitalized costs for related to oil and gas exploration and production +activities with applicable accumulated depreciation, depletion and amortization +are presented below: +December +31, +2007 +2006 +(in +thousands) +Proved +oil and gas properties +$ +953,904 +$ +473,451 +Unproved +oil and gas properties +41,023 +27,055 +994,927 +500,506 +Less +accumulated depreciation, depletion and amortization +196,310 +133,172 +$ +798,617 +$ +367,334 +F-39 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Results +of Operations for Oil and Gas Producing Activities (Unaudited) +The +results of operations for oil and gas producing activities (excluding marketing) +are presented below. +Year +Ended December 31, +2007 +2006 +2005 +(in +thousands) +Revenue: +Oil +and gas sales +$ +175,187 +$ +115,189 +$ +102,559 +Oil +and gas price risk management gain (loss), net +2,756 +9,147 +(9,368 +) +177,943 +124,336 +93,191 +Expenses: +Production +costs +44,238 +20,855 +16,194 +Depreciation, +depletion and amortization +68,086 +30,988 +19,322 +Exploration +costs +23,551 +8,131 +11,115 +135,875 +59,974 +46,631 +Results +of operations for oil and gas producing activities before provision for +income taxes +42,068 +64,362 +46,560 +Provision +for income taxes +16,280 +24,818 +18,112 +Results +of operations for oil and gas producing activities (excluding corporate +overhead and interest costs) +$ +25,788 +$ +39,544 +$ +28,448 +Production +costs include those costs incurred to operate and maintain productive wells and +related equipment, including costs such as labor, repairs, maintenance, +materials, supplies, fuel consumed, insurance and production and severance +taxes. In addition, production costs include administrative expenses +and depreciation applicable to support equipment associated with these +activities. Depreciation, depletion and amortization expense includes those +costs associated with capitalized acquisition, exploration and development +costs, but does not include the depreciation applicable to support +equipment. The provision for income taxes is computed +using effective tax rates. +Net +Proved Oil and Gas Reserves (Unaudited) +Our +proved oil and natural gas reserves have been estimated by independent petroleum +engineers. Wright & Company prepared for us reserve reports +estimating our proved reserves at December 31, 2007 and 2006, in the Appalachian +and Michigan Basins. Ryder Scott Company, L.P. prepared for us +reserve reports estimating our proved reserves at December 31, 2007 and 2006, in +the Rocky Mountain Region. Wright & Company prepared reserve +reports for us estimating all of our reserves at December 31, 2005, with the +exception of our North Dakota wells, which were prepared by Ryder Scott Company, +L.P. These reserve estimates have been prepared in compliance with +professional standards and the reserves definitions prescribed by the +SEC. +Proved +reserves are the estimated quantities of oil and natural gas that geologic and +engineering data demonstrate with reasonable certainty to be recoverable in +future years from known reservoirs under existing economic and operating +conditions. Estimates of proved reserves may change, either +positively or negatively, as additional information becomes available and as +contractual, economic and political conditions change. The Company's +net proved reserve estimates have been adjusted as necessary to reflect all +contractual agreements, royalty obligations and interests owned by others at the +time of the estimate. +Proved +developed reserves are the quantities of oil and natural gas expected to be +recovered through existing wells with existing equipment and operating +methods. In some cases, proved undeveloped reserves may require +substantial new investments in additional wells and related +facilities. +F-40 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +An +analysis of the change in estimated quantities of oil and gas reserves, all of +which are located within the United States, is shown below. +Oil +(MBbl) +Gas +(MMcf) +Total +(MMcfe) +Proved +Reserves: +Proved +reserves, January 1, 2005 +3,316 +197,548 +217,444 +Revisions +of previous estimates +80 +(6,894 +) +(6,414 +) +Extensions, +discoveries and other additions +Rocky +Mountain Region +1,576 +76,669 +86,125 +Purchases +of reserves +Appalachian +basin +- +434 +434 +Michigan +Basin +- +47 +47 +Rocky +Mountain region +5 +71 +101 +Dispositions +to partnerships +- +(9,556 +) +(9,556 +) +Production +(439 +) +(11,031 +) +(13,665 +) +Proved +reserves, December 31, 2005 +4,538 +247,288 +274,516 +Revisions +of previous estimates +226 +(21,721 +) +(20,365 +) +Extensions, +discoveries and other additions +Michigan +Basin +- +225 +225 +Rocky +Mountain Region +2,955 +63,901 +81,631 +Purchases +of reserves +Appalachian +basin +- +222 +222 +Michigan +Basin +- +35 +35 +Rocky +Mountain region +276 +3,504 +5,160 +Dispositions +to partnerships +(92 +) +(1,215 +) +(1,767 +) +Production +(631 +) +(13,161 +) +(16,947 +) +Proved +reserves, December 31, 2006 +7,272 +279,078 +322,710 +Revisions +of previous estimates +1,375 +14,177 +22,427 +Extensions, +discoveries and other additions +Appalachian +Basin +- +5,493 +5,493 +Michigan +Basin +- +488 +488 +Rocky +Mountain Region +3,700 +210,402 +232,602 +Purchases +of reserves +Appalachian +basin +2 +63,014 +63,026 +Michigan +Basin +- +6,059 +6,059 +Rocky +Mountain region +4,490 +39,239 +66,179 +Dispositions +to partnerships +(591 +) +(1,874 +) +(5,420 +) +Production +(910 +) +(22,513 +) +(27,973 +) +Proved +reserves, December 31, 2007 +15,338 +593,563 +685,591 +Proved +Developed Reserves, As of: +January +1, 2005 +3,190 +146,152 +165,292 +December +31, 2005 +3,860 +155,354 +178,514 +December +31, 2006 +4,629 +158,978 +186,752 +December +31, 2007 +8,927 +314,123 +367,685 +2007 Activity . In +2007, we recorded an upward revision to our previous estimate of proved reserves +of approximately 22 Bcfe. The revision was primarily due to an +increase of approximately 25 Bcfe and 12 Bcfe, respectively, due to asset +performance and higher commodity prices, partially offset by a decrease of +approximately 15 Bcfe due primarily to increased operating costs, adjustments to +proved undeveloped reserve values and change in well ownership +interests. New discoveries and extensions of 239 Bcfe in 2007 are due +to the drilling of 218 net wells and the addition of new proved undeveloped +reserves. Approximately 233 Bcfe were added in the Rocky Mountain +Region, with 43 Bcfe in the Wattenberg Field, 170 Bcfe in Grand Valley Field and +19 Bcfe in the NECO area. We acquired approximately 135 Bcfe of +proved reserves through purchases of oil and natural gas +properties. In the Rocky Mountain Region approximately 66 Bcfe +of proved reserves were acquired in the Wattenberg Field, in the Appalachian +Basin approximately 75 Bcfe were acquired and approximately 6 Bcfe in the +Michigan Basin. We sold proved reserves of approximately 5 Bcfe to +unaffiliated third parties and to our sponsored partnerships for drilling +activity. +F-41 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +2006 Activity. In +2006 we recorded a downward revision to our previous estimate of proved reserves +of approximately 20 Bcfe. The revision was primarily due to a +decrease of 3 Bcfe due to asset performance and a decrease of 10 Bcfe due +to lower commodity prices and a decrease of approximately 7 Bcfe due to changes +in proved undeveloped reserve value, operating expense, and well ownership +interests. New discoveries and extensions in 2006 of approximately 82 +Bcfe were primarily due to the drilling of 91 net wells and adding new proved +undeveloped reserves in the Rocky Mountain Region. Approximately 34 +Bcfe were added in Wattenberg Field, 33 Bcfe in Grand Valley Field and 12 Bcfe +in the NECO area. We acquired approximately 5 Bcfe of proved reserves +through purchases of oil and natural gas properties in Wattenberg +Field. We sold proved reserves of approximately 2 Bcfe to our +sponsored partnerships. +2005 Activity. In +2005, we recorded a downward revision to our previous estimate of proved +reserves of approximately 6 Bcfe. The revision was primarily due to a +decrease of 15 Bcfe due to asset performance, partially offset by additions of 6 +Bcfe and 3 Bcfe, respectively, due to commodity price increases and proved +undeveloped values, operating expense changes and well ownership +interests. New discoveries and extensions in 2005 of approximately 86 +Bcfe were primarily due to the drilling of 65 net wells and additions of new +proved undeveloped reserves in the Rocky Mountain +Region. Approximately 11 Bcfe were added in Wattenberg Field, 44 Bcfe +were added in Grand Valley Field and 27 Bcfe were added in the NECO +area. We sold proved reserves of approximately 10 Bcfe to our +sponsored partnership. +Standardized +Measure of Discounted Future Net Cash Flows and Changes Therein Relating to +Proved Oil and Gas Reserves (Unaudited) +Summarized +in the following table is information with respect to the standardized measure +of discounted future net cash flows relating to proved oil and gas +reserves. Future cash inflows are computed by applying year-end +prices of oil and gas relating to our proved reserves to the year-end quantities +of those reserves. Future production, development, site restoration +and abandonment costs are derived based on current costs assuming continuation +of existing economic conditions. Future income tax expenses are +computed by applying the statutory rate in effect at the end of each year to the +future pretax net cash flows, less the tax basis of the properties and gives +effect to permanent differences, tax credits and allowances related to the +properties. +2007 +2006 +2005 +(in +thousands) +Future +estimated cash flows +$ +5,257,962 +$ +1,804,796 +$ +2,381,238 +Future +estimated production costs +(1,374,027 +) +(571,346 +) +(545,683 +) +Future +estimated development costs +(876,961 +) +(373,460 +) +(207,164 +) +Future +estimated income tax expense +(1,159,489 +) +(334,536 +) +(633,444 +) +Future +net cash flows +1,847,485 +525,454 +994,947 +10% +annual discount for estimated timing of cash flows +(1,094,414 +) +(309,792 +) +(589,517 +) +Standardized +measure of discounted future estimated net cash flows +$ +753,071 +$ +215,662 +$ +405,430 +The +following table summarizes the principal sources of change in the standardized +measure of discounted future estimated net cash flows. +2007 +2006 +2005 +(in +thousands) +Sales +of oil and gas production net of production costs +$ +(137,725 +) +$ +(94,337 +) +$ +(86,366 +) +Net +changes in prices and production costs +157,797 +(301,132 +) +188,836 +Extensions, +discoveries, and improved recovery, less related costs +317,031 +46,109 +150,654 +Sales +of reserves +(7,846 +) +(3,356 +) +(14,456 +) +Purchase +of reserves +342,792 +11,003 +1,266 +Development +costs incurred during the period +42,510 +20,051 +24,035 +Revisions +of previous quantity estimates +92,462 +(22,090 +) +4,917 +Changes +in estimated income taxes +(335,327 +) +120,818 +(112,054 +) +Accretion +of discount +38,660 +62,838 +38,241 +Timing +and other +27,055 +(29,672 +) +(19,071 +) +Total +$ +537,409 +$ +(189,768 +) +$ +176,002 +F-42 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +It is +necessary to emphasize that the data presented should not be viewed as +representing the expected cash flow from, or current value of, existing proved +reserves since the computations are based on a large number of estimates and +arbitrary assumptions. Reserve quantities cannot be measured with +precision and their estimation requires many judgmental determinations and +frequent revisions. The required projection of production and related +expenditures over time requires further estimates with respect to pipeline +availability, rates of demand and governmental control. Actual future +prices and costs are likely to be substantially different from the current +prices and costs utilized in the computation of reported amounts. Any +analysis or evaluation of the reported amounts should give specific recognition +to the computational methods utilized and the limitations inherent +therein. +The +estimated present value of future cash flows relating to proved reserves is +extremely sensitive to prices used at any measurement period. The +average December 31 price used for each commodity at December 31, 2007, 2006 and +2005 is presented below. +Average +Price +As +of December 31, +Oil +Gas +2007 +$ +80.67 +$ +6.77 +2006 +57.70 +4.96 +2005 +58.25 +8.56 +F-43 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +NOTE +21 - QUARTERLY FINANCIAL DATA (UNAUDITED) +Quarterly +financial data for the years ended December 31, 2007 and 2006, are presented +below The sum of the quarters may not equal the total of the +year's net income per share due to changes in the weighted average shares +outstanding throughout the year. +2007 +Quarter +First +Second +Third +Fourth +Year +(in +thousands, except per share data) +Revenues: +Oil +and gas sales +$ +34,016 +$ +39,246 +$ +44,437 +$ +57,488 +$ +175,187 +Sales +from natural gas marketing activities +21,987 +29,924 +19,934 +31,779 +103,624 +Oil +and gas well drilling operations +4,030 +1,739 +1,573 +4,812 +12,154 +Well +operations and pipeline income +3,298 +1,292 +2,092 +2,660 +9,342 +Oil +and gas price risk management (loss) gain, net +(5,645 +) +3,742 +6,345 +(1,686 +) +2,756 +Other +income +226 +2 +1,894 +50 +2,172 +Total +revenues +57,912 +75,945 +76,275 +95,103 +305,235 +Costs +and expenses: +Oil +and gas production costs and well operations costs +9,035 +11,628 +12,645 +15,956 +49,264 +Cost +of natural gas marketing activities +21,512 +28,780 +19,810 +30,482 +100,584 +Cost +of oil and gas well drilling operations +564 +246 +749 +949 +2,508 +Exploration +expense +2,678 +6,780 +5,337 +8,756 +23,551 +General +and administrative expense +7,424 +6,886 +7,513 +9,145 +30,968 +Depreciation, +depletion and amortization +13,074 +17,429 +20,354 +19,987 +70,844 +Total +costs and expenses +54,287 +71,749 +66,408 +85,275 +277,719 +Gain +on sale of leaseholds +- +25,600 +- +7,691 +33,291 +Income +from operations +3,625 +29,796 +9,867 +17,519 +60,807 +Interest +income +1,143 +454 +462 +603 +2,662 +Interest +expense +(831 +) +(1,450 +) +(2,544 +) +(4,454 +) +(9,279 +) +Income +before income taxes +3,937 +28,800 +7,785 +13,668 +54,190 +Income +taxes +1,436 +10,749 +3,326 +5,470 +20,981 +Net +income +$ +2,501 +$ +18,051 +$ +4,459 +$ +8,198 +$ +33,209 +Basic +earnings per common share +$ +0.17 +$ +1.22 +$ +0.30 +$ +0.56 +$ +2.25 +Diluted +earnings per common share +$ +0.17 +$ +1.21 +$ +0.30 +$ +0.55 +$ +2.24 +F-44 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +2006 +Quarter +First +Second +Third +Fourth +Year +(in +thousands, except per share data) +Revenues: +Oil +and gas sales +$ +28,332 +$ +27,992 +$ +30,577 +$ +28,288 +$ +115,189 +Sales +from natural gas marketing activities +41,942 +29,129 +30,374 +29,880 +131,325 +Oil +and gas well drilling operations +5,278 +3,745 +2,659 +6,235 +17,917 +Well +operations and pipeline income +2,290 +2,486 +2,536 +3,392 +10,704 +Oil +and gas price risk management gain, net +4,925 +1,370 +2,707 +145 +9,147 +Other +income +3 +21 +1,964 +233 +2,221 +Total +revenues +82,770 +64,743 +70,817 +68,173 +286,503 +Costs +and expenses: +Oil +and gas production and well operations costs +6,949 +6,830 +8,584 +6,658 +29,021 +Cost +of natural gas marketing activities +41,780 +28,471 +29,988 +29,911 +130,150 +Cost +of oil and gas well drilling operations +4,212 +3,278 +3,838 +1,289 +12,617 +Exploration +expense +1,208 +1,898 +2,180 +2,845 +8,131 +General +and administrative expense +3,719 +5,102 +5,357 +4,869 +19,047 +Depreciation, +depletion and amortization +6,587 +7,605 +8,300 +11,243 +33,735 +Total +costs and expenses +64,455 +53,184 +58,247 +56,815 +232,701 +Gain +on sale of leaseholds +- +- +328,000 +- +328,000 +Income +from operations +18,315 +11,559 +340,570 +11,358 +381,802 +Interest +income +392 +349 +3,475 +3,834 +8,050 +Interest +expense +(352 +) +(436 +) +(366 +) +(1,289 +) +(2,443 +) +Income +before income taxes +18,355 +11,472 +343,679 +13,903 +387,409 +Income +taxes +6,710 +4,192 +132,795 +5,940 +149,637 +Net +income +$ +11,645 +$ +7,280 +$ +210,884 +$ +7,963 +$ +237,772 +Basic +earnings per common share +$ +0.72 +$ +0.45 +$ +13.39 +$ +0.54 +$ +15.18 +Diluted +earnings per common share +$ +0.72 +$ +0.45 +$ +13.33 +$ +0.54 +$ +15.11 +F-45 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +Schedule +II -VALUATION AND QUALIFYING ACCOUNTS +Description +Beginning +Balance +January +1 +Charged +to +Costs +and Expenses +Deductions +Ending +Balance +December +31 +(in +thousands) +2007: +Allowance +for doubtful accounts +(a) +$ +415 +$ +50 +$ +108 +$ +357 +Valuation +allowance for unproved oil and gas properties +(b) +$ +596 +$ +2,183 +$ +414 +$ +2,365 +2006: +Allowance +for doubtful accounts +(a) +$ +409 +$ +7 +$ +1 +$ +415 +Valuation +allowance for unproved oil and gas properties +(b) +$ +33 +$ +653 +$ +90 +$ +596 +2005: +Allowance +for doubtful accounts +(a) +$ +409 +$ +- +$ +- +$ +409 +Valuation +allowance for unproved oil and gas properties +(b) +$ +- +$ +81 +$ +48 +$ +33 +(a) +Deductions represent the write-off of accounts receivable deemed +uncollectible. +(b) +Deductions represent amortization of expired or abandoned unproved oil +and gas properties. +F-46 \ No newline at end of file diff --git a/raw/filings/0000077877/2007/0001140361-08-007391/item13.txt b/raw/filings/0000077877/2007/0001140361-08-007391/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..218aab1fd64865eb0c649b62e464c7544113d731 --- /dev/null +++ b/raw/filings/0000077877/2007/0001140361-08-007391/item13.txt @@ -0,0 +1,9 @@ +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED +TRANSACTIONS AND DIRECTOR INDEPENDENCE +The +information called for by Item 13 is incorporated by reference from information +under the captions entitled Certain Relationships and Related +Transactions and +Director Independence in our definitive proxy statement to be +filed pursuant to Regulation 14A no later than 120 days after the close of our +fiscal year. \ No newline at end of file diff --git a/raw/filings/0000077877/2007/0001140361-08-007391/item9a.txt b/raw/filings/0000077877/2007/0001140361-08-007391/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..e2f78c948e78e3a00f96b7c2358c2f9baf3db6db --- /dev/null +++ b/raw/filings/0000077877/2007/0001140361-08-007391/item9a.txt @@ -0,0 +1,76 @@ +ITEM 9A . CONTROLS AND PROCEDURES +Evaluation +of Disclosure Controls and Procedures +As of +December 31, 2007, we carried out an evaluation, under the supervision and with +the participation of our management, including our Chief Executive Officer and +Chief Financial Officer, of the effectiveness of the design and operation of our +disclosure controls and procedures pursuant to Securities Exchange Act Rule +13a-15(e). Based upon that evaluation, our Chief Executive Officer +and Chief Financial Officer concluded that our disclosure controls and +procedures were not effective as of December 31, 2007, to ensure that the +information required to be disclosed by the Company in the reports that we file +or submit under the Exchange Act is recorded, processed, summarized and +reported, within the time periods specified in the SEC rules and forms, and that +the information is accumulated and communicated to our management, including our +Chief Executive Officer and Chief Financial Officer, as appropriate to all +timely decisions regarding required disclosure, due to the existence of material +weaknesses described in Management’s Report on Internal +Control Over Financial Reporting included in Item 8 of this +report. +60 +Table of Contents +Changes +in Internal Control over Financial Reporting +We have +made the following changes in our internal control over financial reporting (as +such term is defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange +Act of 1934) during the quarter ended December 31, 2007, that have materially +affected or are reasonably likely to materially affect our internal control over +financial reporting. +· +Installed +new software supporting our derivative valuation process. The +new system enhanced the existing internal controls framework over +reporting more accurate information by automating a previously manual +control. +During +the third quarter of 2007, and continuing through the filing of this report, we +made the following changes in our internal control over financial reporting that +has materially affected, or is reasonably likely to materially affect our +internal controls over financial reporting: +· +Installed +new software supporting our accounts payable process as part of a broader +financial reporting system implementation. The new system +enhanced the existing internal control framework over accounts payable and +cash distribution process by automating several of the previously manual +controls. +Additionally, +during the first quarter of 2007, and continuing through the filing of this +report, we implemented the following changes in internal control over financial +reporting: +· +Reinforced +reconciliation procedures to ensure the timely reconciliation, review and +adjustments to significant balance sheet and income statement +accounts; +· +Developed +and approved extensive policies and procedures concerning the controls +over financial reporting for +derivatives; +· +Provided +additional training regarding derivatives for key personnel; +and +· +Developed +a review process to ensure proper accounting for oil and gas properties, +specifically the capitalization of costs and calculation of depreciation +and depletion. +We +continue to evaluate the ongoing effectiveness and sustainability of the changes +we have made in internal control, and, as a result of the ongoing evaluation, +may identify additional changes to improve internal control over financial +reporting. \ No newline at end of file diff --git a/raw/filings/0000077877/2007/0001140361-08-007391/rp_note.txt b/raw/filings/0000077877/2007/0001140361-08-007391/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2007/0001140361-08-007391/rpt_disclosure.txt b/raw/filings/0000077877/2007/0001140361-08-007391/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..afd2d623b5ccd07d253525c60c1be8d86ab6b10a --- /dev/null +++ b/raw/filings/0000077877/2007/0001140361-08-007391/rpt_disclosure.txt @@ -0,0 +1,84 @@ +Transactions with Related Persons +The Board +has adopted a written policy for the review, approval and ratification of +transactions that involve related parties and potential conflicts of +interest. +The +related party transaction policy applies to each director and executive officer +of the Company, any nominee for election as a director, any security holder who +is known to own more than five percent of the Company's voting securities, any +immediate family member of any of the foregoing persons and any corporation, +firm or association in which one or more of the Company's directors are +directors or officers, or have a substantial financial +interest. +28 +Table of Contents +Under the +related party transaction policy a related person transaction is a transaction +or arrangement involving a related person in which the Company is a participant +or that would require disclosure in the Company's filings with the SEC as a +transaction with a related person. +The +related persons must disclose to the Audit Committee any potential related +person transactions and must disclose all material facts with respect to such +interest. All related person transactions will be reviewed by the +Audit Committee. In determining whether to approve or ratify a +transaction, the Audit Committee will consider the relevant facts and +circumstances of the transaction which may include factors such as the +relationship of the related person with the Company, the materiality or +significance of the transaction to the Company and the business purpose and +reasonableness of the transaction, whether the transaction is comparable to a +transaction that could be available to the Company on an arms-length basis, and +the impact of the transaction on the Company's business and +operations. +During +the year ended December 31, 2007, there was no transaction or series of +transactions, or any currently proposed transaction, in which the amount +involved exceeds $120,000 and in which any director, executive officer, holder +of more than 5% of the Company's common stock or any member of the immediate +family of any of the foregoing persons had or will have a direct or indirect +material interest. +Indemnification of Directors and +Officers +The +Company's By-Laws provide that the Company shall indemnify any director, +officer, employee, or other agent of the Company who is or was a party, or is +threatened to be made a party, to any proceeding (other than an action by or in +the right of the Company to procure a judgment in its favor) by reason of the +fact that such person is or was an agent of the Company, against expenses, +judgments, fines, settlements, and other amounts actually and reasonably +incurred in connection with such proceeding, if that person acted in good faith +and in a manner that person reasonably believed to be in the best interest of +the Company, and in the case of a criminal proceeding, had no reasonable cause +to believe the conduct of that person was unlawful. +The +Company has entered into separate indemnification agreements with each of its +directors and officers whereby the Company has agreed to indemnify the director +or officer against all expenses, including attorneys' fees, and other amounts +reasonably incurred by the officer or director in connection with any +threatened, pending or completed civil, criminal, administrative or +investigative action or proceeding to which such person is party by reason of +the fact that he is or was a director or officer, as the case may be, of the +Company, if the person acted in good faith and in a manner reasonably believed +to be in or not opposed to the best interests of the Company, and, with respect +to any criminal action or proceeding, the person had no reasonable cause to +believe such conduct to be unlawful. The agreements provide for the +advancement of expenses and that the Company has the right to purchase and +maintain insurance on behalf of the director or officer against any liability or +liabilities asserted against him, whether or not the Company would have the +power to indemnify the person against such liability under any provision of the +agreement. The Company has agreed to indemnify such person against +expenses actually and reasonably incurred in connection with any action in which +the person has been successful on the merits or +otherwise. Indemnification must also be provided by the Company +(unless ordered otherwise by a court) only as authorized in the specific case +upon a determination that the indemnification of the person is appropriate +because he has met the applicable standard of conduct described in the agreement +made by (i) the Board of Directors, by a majority vote of a quorum consisting of +directors who are not parties to such action or proceeding, (ii) independent +legal counsel in a written opinion or (iii) the shareholders of the +Company. +29 +Table of Contents +Additional Information +The \ No newline at end of file diff --git a/raw/filings/0000077877/2008/0001140361-09-005340/filing.txt b/raw/filings/0000077877/2008/0001140361-09-005340/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..2913a8e4ee35a52652174090cd7ec3acbbdc714d --- /dev/null +++ b/raw/filings/0000077877/2008/0001140361-09-005340/filing.txt @@ -0,0 +1,13402 @@ +10-K +1 +form10k.htm +PETROLEUM DEVELOPMENT CORP 10-K 12-31-2008 +form10k.htm +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, 2008 +or +¨ TRANSITION REPORT PURSUANT TO +SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the +transition period from __________ to _________ +Commission +File Number 000-07246 +PETROLEUM +DEVELOPMENT CORPORATION +(Exact +name of registrant as specified in its charter) +Nevada +95-2636730 +(State +of Incorporation) +(I.R.S. +Employer Identification No.) +120 +Genesis Boulevard +Bridgeport, +West Virginia 26330 +(Address +of principal executive offices) (Zip Code) +Registrant's +telephone number, including area code: (304) 842-3597 +Securities +registered pursuant to Section 12(b) of the Act: +Title +of Each Class +Name +of Each Exchange on Which Registered +Common +Stock, par value $.01 per share +NASDAQ +Global Select Market +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 ¨ No +x +Indicate +by check mark if registrant is not required to file reports pursuant to Section +13 or Section 15(d) of the Act. Yes ¨ 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 +¨ +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. ¨ +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 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 ¨ +Non-accelerated +filer ¨ +Smaller +reporting company ¨ +(Do +not check if a smaller reporting +company) +Indicate +by check mark whether the registrant is a shell company (as defined in Rule +12b-2 of the Exchange Act). Yes ¨ No +x +The +aggregate market value of our common stock held by non-affiliates on June 30, +2008, was $965,929,153 (based on the then closing price of $66.49). +As of +February 23, 2009 there were 14,868,158 ares of our common stock +outstanding. +DOCUMENTS +INCORPORATED BY REFERENCE +The +information required by Part III of this Form is incorporated by reference to +our definitive proxy statement to be filed pursuant to Regulation 14A for our +2009 Annual Meeting of Shareholders. +PETROLEUM DEVELOPMENT CORPORATION +2008 +ANNUAL REPORT ON FORM 10-K +TABLE +OF CONTENTS +PART +I +Page +Item +1. +Business +1 +Item +1A. +Risk +Factors +16 +Item +1B. +Unresolved Staff +Comments +25 +Item +2. +Properties +26 +Item +3. +Legal +Proceedings +26 +Item +4. +Submission of Matters to a Vote of +Security Holders +26 +PART +II +Item +5. +Market for the Registrant’s Common +Equity, Related Stockholder Matters and Issuer Purchases of Equity +Securities +26 +Item +6. +Selected Financial +Data +29 +Item +7. +Management’s Discussion and Analysis +of Financial Condition and Results of +Operations +30 +Item +7A. +Quantitative and Qualitative +Disclosures About Market Risk +47 +Item +8. +Financial Statements and +Supplementary Data +49 +Item +9. +Changes in and Disagreements With +Accountants on Accounting and Financial +Disclosure +49 +Item +9A. +Controls and +Procedures +49 +Item +9B. +Other +Information +50 +PART +III +Item +10. +Directors, Executive Officers and +Corporate Governance +50 +Item +11. +Executive +Compensation +50 +Item +12. +Security Ownership of Certain +Beneficial Owners and Management and Related Stockholder +Matters +50 +Item +13. +Certain Relationships and Related +Transactions, and Director Independence +51 +Item +14. +Principal Accounting Fees and +Services +51 +PART +IV +Item +15. +Exhibits, Financial Statement +Schedules +51 +SIGNATURES +52 +GLOSSARY OF OIL AND NATURAL GAS +TERMS +53 +Table of Contents +PART I +REFERENCES +TO THE REGISTRANT +Unless +the context otherwise requires, references to “PDC”, “the Company”, “we”, “us”, +“our”, “ours”, or “ourselves” in this report refer to the registrant, Petroleum +Development Corporation, together with its subsidiaries, proportionate share of +its sponsored drilling partnerships and an entity in which it has a controlling +interest. +GLOSSARY +OF OIL AND NATURAL GAS TERMS +Words +defined in the Glossary of Oil and Natural Gas Terms are set in boldface type +the first time they appear. +SPECIAL +NOTE REGARDING FORWARD-LOOKING STATEMENTS +This +report 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 regarding our business, financial condition, results of operations and +prospects. Words such as expects, anticipates, intends, plans, +believes, seeks, estimates and similar expressions or variations of such words +are intended to identify forward-looking statements herein, which include +statements of estimated oil +and natural gas production and reserves, drilling plans, future cash flows, +anticipated liquidity, anticipated capital expenditures and our management’s +strategies, plans and objectives. However, these are not the +exclusive means of identifying forward-looking statements +herein. Although forward-looking statements contained in this report +reflect our good faith judgment, such statements can only be based on facts and +factors currently known to us. Consequently, forward-looking +statements are inherently subject to risks and uncertainties, including risks +and uncertainties incidental to the exploration for, and the acquisition, +development, production and marketing of, natural gas and oil, and actual +outcomes may differ materially from the results and outcomes discussed in the +forward-looking statements. Important factors that could cause actual +results to differ materially from the forward looking statements include, but +are not limited to: +· +changes +in production volumes, worldwide demand, and commodity prices for oil and +natural gas; +· +the +timing and extent of our success in discovering, acquiring, developing and +producing natural gas and oil +reserves; +· +our +ability to acquire leases, drilling rigs, supplies and services at +reasonable prices; +· +the +availability and cost of capital to +us; +· +risks +incident to the drilling and operation of natural gas and oil +wells; +· +future +production and development costs; +· +the +availability of sufficient pipeline and other transportation facilities to +carry our production and the impact of these facilities on +price; +· +the +effect of existing and future laws, governmental regulations and the +political and economic climate of the United States of America +(“U.S.”); +· +the +effect of natural gas and oil derivatives +activities; +· +conditions +in the capital markets; and +· +losses +possible from pending or future +litigation. +Further, +we urge you to carefully review and consider the disclosures made in this +report, including the risks and uncertainties that may affect our business as +described herein under Item 1A , Risk Factors , and our other +filings with the Securities and Exchange Commission (“SEC”). We +caution you not to place undue reliance on forward-looking statements, which +speak only as of the date of this report. We undertake no +obligation to update any forward-looking statements in order to reflect any +event or circumstance occurring after the date of this report or currently +unknown facts or conditions or the occurrence of unanticipated +events. +ITEM 1. BUSINESS +General +We are an +independent energy company engaged in the exploration, development, production +and marketing of oil and natural gas. Since we began oil and natural +gas operations in 1969, we have grown through drilling and development +activities, acquisitions of producing natural gas and oil wells and the +expansion of our natural gas marketing activities. +As of +December 31, 2008, we owned interests in approximately 4,712 gross , +3,259 net , +wells located primarily in the Rocky Mountain Region and the Appalachian and +Michigan Basins with 753 billion cubic feet equivalent, or Bcfe , +of net proved +reserves , of which 88% was natural gas and 12% was oil. +During +2008, our production was 38.7 Bcfe, averaging 106.1 MMcfe +per day, a 38.5% increase over 76.6 MMcfe per day produced in +2007. We replaced our 2008 production with 106 Bcfe of new proved +reserves, net of dispositions, for a reserve +replacement rate of 274%. Reserve replacement through the +drillbit was 104 Bcfe, or 268% of production, and reserve replacement through +acquisitions was 2 Bcfe, or 6% of production. Proved reserves grew +9.8% during 2008, from 686 Bcfe to 753 Bcfe, of which 44% were proved +developed reserves . +1 +Table of Contents +We make available free of charge on our website at www.petd.com our annual +reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form +8-K, and any amendments to these reports as soon as reasonably practicable after +we electronically file these reports with, or furnish them to, the +SEC. We will also make available to any shareholder, without charge, +a copy of our Annual Report on Form 10-K, or any other filing, as filed with the +SEC, by mail. For a mailed copy of a report, you may contact +Petroleum Development Corporation, Investor Relations, 1775 Sherman Street, +Suite 3000, Denver, CO 80203, or call toll free (800) 624-3821. +In addition to our SEC filings, other information, including our press +releases, Bylaws, Committee Charters, Code of Business Conduct and Ethics, +Shareholder Communication Policy, Director Nomination Procedures and the +Whistleblower Hotline, is also available on our website. However, the +information available on our website is not part of this report and is not +hereby incorporated by reference. +Business +Strategy +Our +primary objective is to continue to increase shareholder value through the +growth of our reserves, production, net income and cash flow. To +achieve meaningful increases in these key areas, we maintain an active drilling +program that focuses on low risk development of our oil and natural gas +reserves, limited exploratory drilling and the acquisition of producing +properties with significant development potential. +Drill +and Develop +Our acreage holdings include positions in the Rocky Mountain Region and the +Appalachian, Michigan and Fort Worth Basins. In the Rocky Mountain +Region, we focus on developmental drilling in Northeastern Colorado, or NECO, +the Wattenberg Field (both located in the DJ Basin), the Grand Valley Field, +Piceance Basin, and additional limited development in North +Dakota. We drilled 379 gross, 333.4 net, wells in 2008, compared to +349 gross, 276.3 net, wells in 2007. In addition, we seek to maximize +the value of our existing wells through a program of well recompletions +and refractures . During +2008, we recompleted and/or refraced a total of 125 wells compared to 181 in +2007. In 2009, with a limited inventory of available recompletion +opportunities, we plan to recomplete and/or refrac 40 wells in the Appalachian +Basin. +We +believe that we will be able to continue to drill a substantial number of new +wells on our current undeveloped properties. As of December 31, 2008, +we had leases or other development rights to approximately 224,800 undeveloped +acres, of which approximately 188,000 acres, or 83.5%, were in the Rocky +Mountain Region. We plan to drill approximately 166 gross, 144.1 net, +wells in 2009, excluding exploratory +wells . To support future development activities, we have +conducted exploratory drilling in the past and plan to drill seven wells in +2009, primarily in the Appalachian Basin. The goal of the exploration +program is to develop new areas for us to include in our future development +drilling activity. +Strategically +Acquire +Our acquisition efforts focus on producing properties that have a significant +undeveloped acreage component. When weighing potential acquisitions, +we prefer properties that have most of their value in producing wells, behind +the pipe reserves or high quality proved undeveloped +locations. Historically, acquisitions have offered efficiency +improvements through economies of scale in management and administration +costs. During the period December 2006 through October 2007, we +completed three acquisitions of assets or companies in our core operating area +of the Wattenberg Field in Colorado and acquired assets in southwestern +Pennsylvania within close proximity to our existing assets in the Appalachian +Basin. We had no significant acquisitions of properties in +2008. We expect to continue to evaluate acquisition +opportunities. See Note 14 , Acquisitions , to our +accompanying consolidated financial statements included in this +report. +Manage +Risk +We seek opportunities to reduce the risk inherent to our business in the oil and +natural gas industry by focusing our drilling efforts primarily on lower risk +development +wells and by maintaining positions in several different geographic +regions and markets. Historically, we have concentrated on +development drilling and geographical diversification to reduce risk levels +associated with natural gas and oil drilling, production and +markets. Currently, a majority of our proved reserves are located in +the Rocky Mountain Region due to our success in that area over the past several +years. However, we benefit from operational diversity in the Rocky +Mountain Region by maintaining significant activity and production in three +separate areas, including the Grand Valley Field of the Piceance Basin in +western Colorado, the Wattenberg Field in north central Colorado and the NECO +area. Additionally, we regularly review opportunities to further +diversify into other regions where we can apply our operational +expertise. We believe development drilling will remain the foundation +of our drilling activities in the future because it is less risky than +exploratory drilling and is likely to generate cash returns more +quickly. We expect that future activities may include some level of +exploratory drilling when the economic environment and commodity price models +justify such risks. We view exploratory activities as having the +potential to identify new development opportunities at a cost competitive to the +current cost of acquiring proven locations. +2 +Table of Contents +To help +manage the risks associated with the oil and natural gas industry, we maintain a +conservative financial approach and proactively employ strategies to reduce the +effects of commodity price volatility. We also believe that +successful oil and natural gas marketing is essential to risk management and +profitable operations. To further this goal, we utilize Riley Natural +Gas, or RNG, a wholly-owned subsidiary, to manage the marketing of our oil and +natural gas and our use of oil and natural gas commodity derivatives as risk +management tools. This allows us to maintain better control over +third party risk in sales and derivative activities. We use oil and +natural gas derivatives contracts primarily to reduce the effects of volatile +commodity prices. We currently have derivative contracts in place on +a significant portion of our production; however, pursuant to our derivative +policy, all volumes for derivatives contracts are limited to 80% of our future +production from producing wells at the time we enter into the derivative +contracts, with the exception of put contracts for which volumes are not +limited. As of December 31, 2008, we had oil and natural gas hedges +in place covering 52% of our expected oil production and 62% of our expected +natural gas production in 2009. Further, while our derivative +instruments are utilized to manage the impact of price volatility of our oil and +natural gas production, they do not qualify for use of hedge accounting under +the terms of SFAS No. 133, requiring us to recognize changes in the fair value +of our derivative positions in earnings each reporting period and, therefore, +resulting in the potential for significant earnings volatility. See +Note 1 , Summary of Significant Accounting +Polices – Derivative Financial Instruments , to our accompanying +consolidated financial statements included in this report. +Business +Segments +We divide +our operating activities into four segments: +· +oil +and gas sales; +· +natural +gas marketing activities; +· +well +operations and pipeline income; and +· +oil +and gas well drilling operations. +See Note 16 , Business Segments , to our +accompanying consolidated financial statements included in this +report. +Oil +and Gas Sales +Our oil +and gas sales segment is our largest business segment based on +revenue. This segment reflects revenues and expenses from production +and sale of oil and natural gas. During 2008, approximately 84.8% of +our oil and gas sales revenue was generated by the Rocky Mountain Region, 10.9% +by the Appalachian Basin and 4.3% by the Michigan Basin. As of the +end of 2008, our total proved reserves were located as follows: Rocky Mountain +Region 82%, Appalachian Basin 15% and Michigan 3%. The majority of +our undeveloped +acreage is in the Rocky Mountain Region, where we focused our 2008 +drilling activities. This segment represents approximately 133% of +our income before income taxes for the year ended December 31, +2008. +Natural +Gas Marketing Activities +Our natural gas marketing activities segment is comprised of our wholly-owned +subsidiary, RNG, through which we purchase, aggregate and resell natural gas +produced by us and others. This allows us to diversify our operations +beyond natural gas drilling and production. Through RNG, we have +established relationships with many of the natural gas producers in the +Appalachian Basin and we have gained significant expertise in the natural gas +end-user market. We do not take speculative positions on commodity +prices, and we employ derivative strategies to manage the financial effects of +commodity price volatility. Our natural gas marketing segment +represented approximately 1% of our income before income taxes for the year +ended December 31, 2008. +Well +Operations and Pipeline Income +We operate approximately 95.5% of the wells in which we own a working +interest . With respect to wells in which we own an interest of +less than 100%, we charge the other working interest owners, including our +drilling partnerships, a competitive fee for operating the well and transporting +natural gas. Our well operations and pipeline income segment +represented approximately 2% of our income before income taxes for the year +ended December 31, 2008. +3 +Table of Contents +Oil +and Gas Well Drilling Operations +Our drilling and development segment reflects results of drilling and +development activities conducted for affiliated and non-affiliated +parties. Historically, we have engaged in these activities primarily +through sponsoring drilling partnerships, which allowed us to share the risks +and costs inherent in drilling and development operations with our investor +partners. Beginning with our third sponsored drilling partnership in +2005, we have drilled partnership wells on a “cost-plus” basis, which means that +we bill our investor partners for the actual drilling costs plus a fixed +drilling fee. Prior to our cost-plus drilling arrangements, drilling +was conducted on a “footage” basis, where the Company bore the risk of changes +in costs. In addition, we have typically purchased a 20% to 37% +working interest in the wells developed through these +partnerships. In September 2006, we raised approximately $90 million +through investor subscriptions in one drilling partnership, and in August 2007, +we raised approximately $90 million through an additional drilling +partnership. +Our oil and gas well drilling segment represented approximately 3% of our income +before income taxes for the year ended December 31, 2008. In January +2008, we announced that we did not plan to sponsor new drilling partnerships in +2008. However, a portion of the funds available for drilling from the +2007 partnership were advanced and unexpended at the end of +2007. The majority of these funds were used in 2008 for +drilling and completion +activities, a portion of which was recognized as income in 2008. The +funds remaining as of December 31, 2008, will be used for completion activities +to be conducted in 2009. Currently, we do not plan to sponsor a +drilling partnership in 2009 and anticipate that our oil and gas well drilling +segment’s contribution to operating income will decline significantly in +2009. +Areas +of Operations +We focus our exploration, development and production efforts in three primary +geographic regions: +· +Rocky +Mountain Region; +· +Appalachian +Basin; and +· +Michigan +Basin. +During 2008, we generated approximately 85.6% of our production from Rocky +Mountain Region wells, 10.2% of our production from Appalachian Basin wells and +4.2% of our production from Michigan Basin wells. The majority of our +undeveloped acreage is in the Rocky Mountain Region and our current drilling +plans continue to be focused predominantly in this area. +Rocky Mountain Region. In 1999, we began operations in the +Rocky Mountain Region. Our Rocky Mountain Region is divided into four +operating areas: (1) Grand Valley Field, (2) Wattenberg Field, (3) NECO area and +(4) North Dakota area. Our Rocky Mountain Region includes +approximately 320,000 gross acres of leasehold and 2,408 gross, 1,542 net, oil +and natural gas wells in which we own an interest. The general +details of each area within the region are further outlined below: +· +Grand +Valley Field, Piceance Basin, Garfield County, +Colorado. We commenced operations in the area in late +1999 and currently own an interest in 285 gross, 158.3 net, natural gas +wells. Our leasehold position encompasses approximately 7,900 +gross acres with approximately 5,200 net undeveloped acres remaining for +development as of December 31, 2008. We drilled 62 gross, 54.4 +net, wells in the area in 2008 and produced approximately 12.5 Bcfe net to +our interests. Development wells drilled in the area range from +7,000 to 9,500 feet in depth and the majority of wells are drilled +directionally from multi-well pads ranging from two to eight or more wells +per drilling pad. The primary target in the area is gas +reserves, developed from multiple sandstone reservoirs in the Mesaverde +Williams Fork formation. Well spacing is approximately ten +acres per well. +· +Wattenberg +Field, DJ Basin, Weld and Adams Counties, Colorado . We +commenced operations in the area in late 1999 and currently own an +interest in 1,390 gross, 875.2 net, oil and natural gas +wells. Our leasehold position encompasses approximately 75,900 +gross acres with approximately 24,000 net undeveloped acres remaining for +development as of December 31, 2008. We drilled 149 gross, +122.7 net, wells in the area in 2008 and produced approximately 15.4 Bcfe +net to our interests. Wells drilled in the area range from +approximately 7,000 to 8,000 feet in depth and generally target oil and +gas reserves in the Niobrara, Codell and J Sand +reservoirs. Well spacing ranges from 20 to 40 acres per +well. Operations in the area, in addition to the drilling of +new development wells, include the refrac of Codell and Niobrara +reservoirs in existing wellbores whereby the Codell sandstone reservoir is +fraced a second time and/or initial completion +attempts are made in the slightly shallower Niobrara carbonate +reservoir. +4 +Table of Contents +· +NECO area. +DJ Basin, Yuma County Colorado and Cheyenne County, +Kansas . We commenced operations in the area in 2003 and +currently own an interest in 717 gross, 504 net, natural gas +wells. Our leasehold position encompasses approximately 141,600 +gross acres with approximately 93,200 net undeveloped acres remaining for +development as of December 31, 2008. We drilled 98 gross, 88.1 +net, wells in the area in 2008 and produced approximately 5 Bcfe net to +our interests. Wells drilled in the area range from +approximately 1,500 to 3,000 feet in depth and target gas reserves in the +shallow Niobrara reservoir. Well spacing is approximately 40 +acres per well. New drilling operations range from exploratory +wells to test undrilled, seismically defined, structural features at the +Niobrara horizon to development wells targeting known reserves in existing +identified features. +· +North +Dakota, Burke County . We commenced operations in the +area in 2006 and currently own an interest in 13 gross, 3.7 net, oil and +natural gas wells. We divested the majority of our Bakken +project acreage in late 2007 (See Note 13 , Sale of Oil and Gas +Properties , to our accompanying consolidated financial statements +included in this report). Our remaining leasehold encompasses +two project areas in Burke County and encompasses approximately 75,100 +gross acres with approximately 46,300 net undeveloped acres remaining for +development as of December 31, 2008. The eastern area acreage +is prospective for development of oil and gas reserves in the Nesson +Formation. Nesson development wells are approximately 6,000 +feet in depth with single or multiple horizontal legs to 4,000 feet or +more in length for a measured length of 10,000 feet or more per +leg. The westernmost acreage block is undeveloped and includes +approximately 23,600 gross, 16,200 net acres. The western +project targets exploratory horizontal +drilling to the Midale/Nesson Formation at depths of approximately +6,800 feet with a lateral leg component of up to 6,100 feet. In +2009, we plan to drill up to four exploratory wells on our acreage with +funding from an unrelated third party in exchange for an interest +in our acreage position. +Appalachian Basin. We have conducted operations in the +Appalachian Basin since 1969. Our leasehold position encompasses +approximately 140,300 gross acres with approximately 19,400 net undeveloped +acres remaining for development as of December 31, 2008. We own an +interest in approximately 2,090 gross, 1,566.5 net, oil and natural gas wells in +West Virginia, Pennsylvania and Tennessee. We drilled 63 gross/net +wells in the area in 2008 and produced +approximately 3.9 Bcfe net to our interests. The majority of our +Appalachian leasehold is developed on approximately 40 acre +spacing. Wells located in this area are approximately 4,500 feet deep +and target predominantly gas reserves in Devonian and Mississippian aged tight +sandstone reservoirs. We are currently +evaluating the potential of the Marcellus Formation in West Virginia and +Pennsylvania and have drilled three tests to date in West Virginia, two of which +are in line. +Michigan Basin . We began +operations in the Michigan Basin in 1997 with the bulk of drilling activity +occurring prior to 2002. We own an interest in approximately 210 +gross, 146.5 net, oil and natural gas wells that produced 1.6 Bcfe net to our +interest in 2008. Wells in the area range from 1,000 to 2,500 feet in +depth and produce gas from the Antrim Shale. We drilled 2 gross, 1.6 +net, exploratory wells in 2008. +Fort +Worth Basin . In addition to those operating areas above, we +have an interest in approximately 12,500 gross, 9,100 net undeveloped acres, in +Fort Worth Basin, northeastern Erath County, Texas. The leasehold +acreage is prospective for the development of oil and natural gas reserves in +the Barnett Shale formation at depths of approximately 5,000 +feet. Development is typically with a horizontal component of +approximately 3,000 feet or more, resulting in an approximate measured length of +up to 8,000 feet or more in this area. In 2008, we commenced drilling +operations and drilled three exploratory Barnett wells. These wells +generated less than 1% of our 2008 production. Based on these +results, we recorded impairments of both proved and unproved properties in this +area in 2008. We are currently evaluating our future plans in this +area and currently have no drilling activity planned in 2009. +5 +Table of Contents +The table below sets forth our productive wells by operating area at December +31, 2008. +Productive +Wells +Gas +Oil +Total +Location +Gross +Net +Gross +Net +Gross +Net +Appalachian +Basin +2,051 +1,551.0 +39 +15.4 +2,090 +1,566.4 +Michigan +Basin +203 +143.8 +7 +2.7 +210 +146.5 +Rocky +Mountain Region +Wattenberg +1,365 +856.0 +25 +19.3 +1,390 +875.3 +Grand +Valley +285 +158.3 +- +- +285 +158.3 +NECO +Area +717 +504.0 +- +- +717 +504.0 +North +Dakota +4 +0.4 +9 +3.3 +13 +3.7 +Wyoming +- +- +3 +0.7 +3 +0.7 +Total +Rocky Mountain Region +2,371 +1,518.7 +37 +23.3 +2,408 +1,542.0 +Fort +Worth Basin +4 +4.0 +- +- +4 +4.0 +Total +Productive Wells +4,629 +3,217.5 +83 +41.4 +4,712 +3,258.9 +Operations +Prospect +Generation +Our staff of professional geologists is responsible for identifying areas with +potential for economic production of natural gas and oil. They +utilize results from logs, seismic data and other tools to evaluate existing +wells and to predict the location of economically attractive new natural gas and +oil reserves. To further this process, we have collected and continue +to collect logs, core data, production information and other raw data available +from state and private agencies, other companies and individuals actively +drilling in the regions being evaluated. From this information, the +geologists develop models of the subsurface structures and formations that are +used to predict areas for prospective economic development. +On the basis of these models, our land department obtains available natural gas +and oil leaseholds, farmouts and other development rights in these prospective +areas. In most cases, to secure a lease, we pay a lease bonus and +annual rental payments, converting, upon initiation of production, to a royalty . In +addition, overriding royalty payments may be granted to third parties in +conjunction with the acquisition of drilling rights initially leased by +others. As of December 31, 2008, we had leasehold rights to +approximately 224,800 acres available for development. +Drilling +Activities +The following table summarizes our development and exploratory drilling activity +for the last three years. There is no correlation between the number +of productive wells completed during any period and the aggregate reserves +attributable to those wells. Productive wells consist of producing +wells and wells capable of commercial production. +Drilling +Activity +2008 +2007 +2006 +Gross +Net +Gross +Net +Gross +Net +Development +Productive +(1) +349 +303.8 +327 +258.9 +216 +129.8 +Dry +8 +8.0 +11 +9.7 +6 +4.6 +Total +development +357 +311.8 +338 +268.6 +222 +134.4 +Exploratory +Productive +(1) +7 +7.0 +1 +0.2 +8 +2.8 +Dry +10 +9.6 +7 +4.5 +1 +0.5 +Pending +determination +5 +5.0 +3 +3.0 +- +- +Total +exploratory +22 +21.6 +11 +7.7 +9 +3.3 +Total +Drilling Activity +379 +333.4 +349 +276.3 +231 +137.7 +______________ +(1) +As +of December 31, 2008, 94 of the 356 productive wells were awaiting gas pipeline +connection, of which 38 were connected and turned in line by February 13, +2009. +6 +Table of Contents +The following table sets forth the wells we drilled by operating area during the +periods indicated. +2008 +2007 +2006 +Gross +Net +Gross +Net +Gross +Net +Appalachian +Basin +63 +63.0 +8 +8.0 +- +- +Michigan +Basin +2 +1.6 +3 +3.0 +1 +1.0 +Rocky +Mountain Region +311 +265.8 +337 +264.3 +230 +136.7 +Fort +Worth Basin +3 +3.0 +1 +1.0 +- +- +Total +379 +333.4 +349 +276.3 +231 +137.7 +We plan to drill approximately 166 gross wells, excluding exploratory wells, in +2009: 12 in the Appalachian Basin and 154 in the Rocky Mountain +Region. +Much of the work associated with drilling, completing and connecting wells, +including drilling, fracturing, logging and pipeline construction is performed +under our direction by subcontractors specializing in those operations, as is +common in the industry. When judged advantageous, material and +services we use in the development process are acquired through competitive +bidding by approved vendors. We also directly negotiate rates and +costs for services and supplies when conditions indicate that such an approach +is warranted. +Financing +of Company Drilling and Development Activities +We +conduct development drilling activities for our own account and act +as operator for other +oil and gas owners. When conducting activities for our own account, +we have historically funded our operations through our cash flows from +operations, capital provided from our long term credit facility and, in 2008, from our senior notes +issuance. In the future, we expect to continue to use these same +sources, but may also use other sources of funding, including, but not limited +to, asset sales, volumetric production payments, debt securities, convertible +debt securities and equity offerings. +Drilling +and Development Activities Conducted for Company Sponsored +Partnerships +We began +sponsoring drilling partnerships in 1984, and had sponsored one or more every +year through 2007. For many years, our drilling partners were +primarily the public and private partnerships we sponsored. At +closing, we contribute a cash investment to purchase an interest in the drilling +and development activities of the partnership and then serve as the managing +general partner. As wells produce for a number of years, we continue +to serve as operator for 33 partnerships, as well as for other unaffiliated +parties. +When developing wells for our partnerships or others, we enter into a +development agreement with the investor partner, pursuant to which we agree to +sell some or all of our rights in a well to be drilled to the partnership or +other entity. The partnership or other entity thereby becomes owner +of a working interest in the well. In our financial reporting, we +report only our proportionate share of oil and gas reserves, production, oil and +gas sales and costs associated with wells in which other investors +participate. +In January 2008, we announced that we did not plan to sponsor new drilling +partnerships in 2008 in order to focus our effort on continuing our growth +through drilling and exploration. Currently, we have no plans to +sponsor a partnership in 2009. +Purchases +of Producing Properties +In addition to drilling new wells, we continue to pursue opportunities to +purchase existing wells and development rights from other owners, as well as +greater ownership interests in the wells we operate. Generally, +outside interests purchased include a majority interest in the wells and the +right to operate the wells. In January 2007, we completed the +purchase from an unrelated party of approximately 144 oil and gas wells and +8,160 acres of leaseholds in the Wattenberg Field. Also in January +2007, we purchased the outside partnership interests in 44 partnerships which we +sponsored and formed primarily in the late 1980s and 1990s. These +interests constituted the majority of the interests in 718 wells, primarily in +the Appalachian and Michigan Basins. In February 2007, we acquired +from an unrelated party 28 producing wells and associated undeveloped acreage in +Colorado. In October 2007, we purchased from unrelated parties a +majority working interest of 762 natural gas wells located in southwestern +Pennsylvania. The purchase also included associated pipelines, +equipment, real estate and undeveloped acreage. No significant +acquisitions were made in 2008. +7 +Table of Contents +Production, Sales, Prices and Lifting +Costs +The following table sets forth information regarding our production volumes, oil +and natural gas sales, average sales price received and average lifting cost +incurred for the periods indicated. +Year +Ended December 31, +2008 +2007 +2006 +Production (1) +Oil +(Bbls) +1,160,408 +910,052 +631,395 +Natural +gas (Mcf) +31,759,792 +22,513,306 +13,160,784 +Natural +gas equivalent (Mcfe) (2) +38,722,240 +27,973,618 +16,949,154 +Oil and Gas Sales (in +thousands) +Oil +sales +$ +104,168 +$ +55,196 +$ +37,460 +Gas +sales +221,734 +119,991 +77,729 +Royalty +litigation provision +(4,025 +) +- +- +Total +oil and gas sales +$ +321,877 +$ +175,187 +$ +115,189 +Realized Gain (Loss) on +Derivatives, net (in thousands) +Oil +derivatives - realized loss +$ +(3,145 +) +$ +(177 +) +$ +- +Natural +gas derivatives - realized gain +12,632 +7,350 +1,895 +Total +realized gain on derivatives, net +$ +9,487 +$ +7,173 +$ +1,895 +Average +Sales Price +Oil +(per Bbl) (3) +$ +89.77 +$ +60.65 +$ +59.33 +Natural +gas (per Mcf) (3) +$ +6.98 +$ +5.33 +$ +5.91 +Natural +gas equivalent (per Mcfe) +$ +8.42 +$ +6.26 +$ +6.80 +Average +Sales Price (including realized gain (loss) on +derivatives) +Oil +(per Bbl) +$ +87.06 +$ +60.46 +$ +59.33 +Natural +gas (per Mcf) +$ +7.38 +$ +5.66 +$ +6.05 +Natural +gas equivalent (per Mcfe) +$ +8.66 +$ +6.52 +$ +6.91 +Average +Production Cost (Lifting Cost) per Mcfe (4) +$ +1.07 +$ +0.90 +$ +0.76 +_____________ +(1) +Production +is net and determined by multiplying the gross production volume of +properties in which we have an interest by the percentage of the leasehold +or other property interest we own. +(2) +A ratio of energy content of +natural gas and oil (six Mcf of natural gas equals one +Bbl of oil) was used to obtain a +conversion factor to convert oil production into equivalent Mcf of natural +gas. +(3) +We +utilize commodity based derivative instruments to manage a portion of our +exposure to price volatility of our natural gas and oil +sales. This amount excludes realized and unrealized gains and +losses on commodity based derivative +instruments. +(4) +Production +costs represent oil and natural gas operating expenses which exclude +production taxes. +Oil +and Natural Gas Reserves +All of our natural gas and oil reserves are located in the U.S. We +utilized the services of independent petroleum engineers to estimate our oil and +gas reserves. For the years ended December 31, 2008 and 2007, our +reserve estimates for the Appalachian and Michigan Basins are based on reserve +reports prepared by Wright & Company and for the Rocky Mountain Region, +reserve estimates are based on reserve reports prepared by Ryder Scott Company, +L.P. For the year ended December 31, 2006, our reserve estimates for +the Appalachian and Michigan Basins and NECO Area were based on reserve reports +prepared by Wright & Company and our reserve estimates for the Rocky +Mountain Region, with the exception of the NECO properties, were based on +reserve reports prepared by Ryder Scott. The independent engineers' +estimates are made using available geological and reservoir data as well as +production performance data. The estimates are prepared with respect +to reserve categorization, using the definitions for proved reserves set forth +in Regulation S-X, Rule 4-10(a) and subsequent SEC staff interpretations and +guidance. When preparing our reserve estimates, the independent +engineers did not independently verify the accuracy and completeness of +information and data furnished by us with respect to ownership interests, oil +and natural gas production, well test data, historical costs of operations and +developments, product prices, or any agreements relating to current and future +operations of properties and sales of production. Our independent +reserve estimates are reviewed and approved by our internal engineering staff +and management. +8 +Table of Contents +The tables below set forth information regarding our estimated proved +reserves. Reserves cannot be measured exactly, because reserve +estimates involve subjective judgments. The estimates must be +reviewed periodically and adjusted to reflect additional information gained from +reservoir performance, new geological and geophysical data and economic +changes. Neither the present value of estimated future net cash flows +nor the standardized measure is intended to represent the current market value +of the estimated oil and natural gas reserves we own. +Proved +Reserves as of December 31, +2008 +2007 +2006 +Oil +( MBbl ) +15,037 +15,338 +7,272 +Natural +gas ( MMcf ) +662,857 +593,563 +279,078 +Total +proved reserves ( MMcfe ) +753,079 +685,591 +322,710 +Proved +developed reserves (MMcfe) +329,669 +317,884 +165,690 +Estimated +future net cash flows (in +thousands) (1) +$ +1,056,890 +$ +1,847,485 +$ +525,454 +Standardized +measure (in thousands) (1)(2) +$ +356,805 +$ +753,071 +$ +215,662 +______________ +(1) +Estimated +future net cash flow represents the estimated future gross revenue to be +generated from the production of proved reserves, net of estimated +production costs, future development costs and income tax expense, using +prices and costs in effect at December 31for each respective +year. For the weighted average wellhead prices used in our +reserve reports, see Note 18 , +“Supplemental Oil and Gas Information,” of our consolidated financial +statements included in this report. These prices should not be +interpreted as a prediction of future prices, nor do they reflect the +value of our commodity hedges in place at December 31for each respective +year. The amounts shown do not give effect to non-property +related expenses, such as corporate general and administrative expenses +and debt service, or to depreciation, depletion and +amortization. +(2) +The +standardized +measure of discounted future net cash flow is calculated in +accordance with Statement of Financial Accounting Standards (“SFAS”) No. +69, which requires the future cash flows to be discounted. The +discount rate used was 10%. Additional information on this +measure, including a description of changes in this measure from year to +year, is presented in Note 18 , +“Supplemental Oil and Gas Information,” of our consolidated financial +statements included in this report. +9 +Table of Contents +Proved +Reserves as of +December 31, +2008 +Oil +(MBbl) +Gas +(MMcf) +Gas +Equivalent +(MMcfe) +Percent +Proved +developed +Appalachian +Basin +29 +73,447 +73,621 +22 +% +Michigan +Basin +40 +19,784 +20,024 +6 +% +Rocky +Mountain Region +Wattenberg +5,079 +50,005 +80,479 +25 +% +Grand +Valley +173 +111,310 +112,348 +34 +% +NECO +- +42,042 +42,042 +13 +% +North +Dakota +105 +114 +744 +0 +% +Wyoming +8 +- +48 +0 +% +Total +Rocky Mountain Region +5,365 +203,471 +235,661 +72 +% +Fort +Worth Basin +4 +339 +363 +0 +% +Total +proved developed +5,438 +297,041 +329,669 +100 +% +Proved +undeveloped +Appalachian +- +39,380 +39,380 +9 +% +Rocky +Mountain Region +Wattenberg +9,340 +62,284 +118,324 +28 +% +Grand +Valley +259 +258,824 +260,378 +62 +% +NECO +- +5,328 +5,328 +1 +% +Total +Rocky Mountain Region +9,599 +326,436 +384,030 +91 +% +Total +proved undeveloped +9,599 +365,816 +423,410 +100 +% +Proved +reserves +Appalachian +29 +112,827 +113,001 +15 +% +Michigan +40 +19,784 +20,024 +3 +% +Rocky +Mountain Region +Wattenberg +14,419 +112,289 +198,803 +27 +% +Grand +Valley +432 +370,134 +372,726 +49 +% +NECO +- +47,370 +47,370 +6 +% +North +Dakota +105 +114 +744 +0 +% +Wyoming +8 +- +48 +0 +% +Total +Rocky Mountain Region +14,964 +529,907 +619,691 +82 +% +Fort +Worth Basin +4 +339 +363 +0 +% +Total +proved reserves +15,037 +662,857 +753,079 +100 +% +Acreage +The following table sets forth by operating area leased acres as of December 31, +2008. +Developed +Undeveloped +Total +Location +Gross +Net +Gross +Net +Gross +Net +Appalachian +Basin +117,800 +113,000 +22,500 +19,400 +140,300 +132,400 +Michigan +Basin +16,800 +14,800 +10,000 +8,400 +26,800 +23,200 +Rocky +Mountain Region +Wattenberg +45,800 +43,400 +30,100 +24,000 +75,900 +67,400 +Grand +Valley +2,700 +2,700 +5,200 +5,200 +7,900 +7,900 +NECO +23,200 +19,300 +118,400 +93,200 +141,600 +112,500 +North +Dakota +8,300 +4,800 +66,800 +46,300 +75,100 +51,100 +Wyoming +300 +100 +19,200 +19,200 +19,500 +19,300 +Total +Rocky Mountain Region +80,300 +70,300 +239,700 +187,900 +320,000 +258,200 +Fort +Worth Basin +400 +400 +12,100 +9,100 +12,500 +9,500 +Total +Acreage +215,300 +198,500 +284,300 +224,800 +499,600 +423,300 +10 +Table of Contents +Title +to Properties +We +believe that we hold good and defensible title to our developed properties, in +accordance with standards generally accepted in the oil and natural gas +industry. As is customary in the industry, a preliminary title +examination is conducted at the time the undeveloped properties are +acquired. Prior to the commencement of drilling operations, a title +examination is conducted and curative work is performed with respect to +discovered defects which we deem to be significant. Title +examinations have been performed with respect to substantially all of our +producing properties. Two properties in our Grand Valley Field +represent 49% of our total proved reserves. +The +properties we own are subject to royalty, overriding royalty and other +outstanding interests customary to the industry. The properties may +also be subject to additional burdens, liens or encumbrances customary to the +industry, including items such as operating agreements, current taxes, +development obligations under natural gas and oil leases, farm-out agreements +and other restrictions. We do not believe that any of these burdens +will materially interfere with the use of the properties. +Natural +Gas Sales +We +generally sell the natural gas that we produce under contracts with indexed +monthly pricing provisions. Virtually all of our contracts include +provisions wherein prices change monthly with changes in the market, for which +certain adjustments may be made based on whether a well delivers to a gathering +or transmission line, quality of natural gas and prevailing supply and demand +conditions, so that the price of the natural gas fluctuates to remain +competitive with other available natural gas supplies. As a result, +our revenues from the sale of natural gas will suffer if market prices decline +and benefit if they increase. We believe that the pricing provisions +of our natural gas contracts are customary in the industry. We also +enter into financial derivatives such as puts, collars and swaps in order to +reduce the impact of possible price instability regarding the physical sales +market. See Item 7, Management’s Discussion and Analysis +of Financial Condition and Results of Operation: Results of Operations - Oil and +Gas Price Risk Management, Net, Oil and Gas Derivative Activities and +Note 3, Derivative Financial +Instruments , to our consolidated financial statements included in this +report. +We +sell our natural gas to other gas marketers, utilities, industrial end-users and +other wholesale gas purchasers. During 2008, the natural gas we +produced was sold at prices ranging from $2.77 to $13.85 per Mcf, depending upon +well location, the date of the sales contract and other factors. Our +weighted net average price of natural gas sold in 2008 was $6.98 per +Mcf. +In +general, we have been and expect to continue to be able to produce and sell +natural gas from our wells without significant curtailment and at competitive +prices. We do experience limited curtailments from time to time due +to pipeline maintenance and operating issues. For instance, we +experienced an approximate 10% to 15% curtailment of production volumes, +approximately 10,000 Mcf per day, in the Piceance Basin due to limited +compression and pipeline capacity throughout most of the fourth quarter in +2008. This interruption, due to third party infrastructure, was +corrected in early 2009. Open access transportation through the +country's interstate pipeline system gives us access to a broad range of +markets. Whenever feasible, we obtain access to multiple pipelines +and markets from each of our gathering systems seeking the best available market +for our natural gas at any point in time. +Oil +Sales +The +majority of our wells in the Wattenberg Field in Colorado and our wells in North +Dakota produce oil in addition to natural gas. As of December 31, +2008, oil represented 12% of our total equivalent reserves and accounted for +approximately 32% of our oil and gas sales revenue for the year ended December +31, 2008. +We are +currently able to sell all the oil that we can produce under existing sales +contracts with petroleum refiners and marketers. We do not refine any +of our oil production. Our crude oil production is sold to purchasers +at or near our wells under both short and long-term purchase contracts with +monthly pricing provisions. During 2008, oil we produced sold at +prices ranging from $19.82 to $132.38 per Bbl, depending upon the location and +quality of oil. Our weighted net average price per Bbl of oil sold in +2008 was $89.77. +Natural +Gas Marketing +Our +natural gas marketing activities involve the purchase of natural gas from other +producers and the sale of that natural gas along with the natural gas we produce +for our own interest and that of our affiliated partnerships. A +variety of factors affect the market for natural gas, +including: +· +the +availability of other domestic +production; +· +natural +gas imports; +· +the +availability and price of alternative +fuels; +· +the +proximity and capacity of natural gas +pipelines; +· +general +fluctuations in the supply and demand for natural gas; +and +· +the +effects of state and federal regulations on natural gas production and +sales. +11 +Table of Contents +The +natural gas industry also competes with other industries in supplying the energy +and fuel requirements of industrial, commercial and individual +customers. +RNG +specializes in the purchase, aggregation and sale of natural gas production in +our Eastern operating areas. RNG markets the natural gas we produce +and also purchases natural gas in the Appalachian Basin from other producers and +resells it to other marketers, utilities or end users. RNG's +employees have extensive knowledge of natural gas markets in our areas of +operations. Such knowledge assists us in maximizing our prices as we +market natural gas from PDC-operated wells. The gas is marketed to +other marketers, natural gas utilities, as well as industrial and commercial +customers, either directly through our gathering system, or through +transportation services provided by regulated interstate pipeline +companies. +We have +entered into various sales, transportation and processing agreements with +unrelated third parties which we sell to or who transports our natural +gas. The following table sets forth information about long-term firm +sales, processing and transportation agreements for pipeline capacity, which +require a demand charge whether volumes are delivered or not. +Type +of Arrangement +Location +Average +Annual +Volume +(MMbtu) +Expiration +Date +Firm +sales and processing +Grand +Valley +23,218,287 +May +2016 +Firm +transportation +NECO +Area +1,825,000 +December +2010 +Firm +transportation +NECO +Area +1,825,000 +December +2016 +Firm +transportation (1) +Appalachian +Basin +12,230,785 +December +2022 +(1) Contract is a precedent +agreement and becomes effective when the planned pipeline is placed in service, +estimated at this time to be 2012. Contract is null and void if pipeline +is not +completed. +Commodity +Risk Management Activities +We +utilize commodity based derivative instruments to manage a portion of our +exposure to price volatility with regard to our oil and natural gas sales and +marketing activities. These instruments consist of NYMEX -traded +natural gas over-the-counter swaps, futures and option contracts for Appalachian +and Michigan production, CIG and PEPL - based contracts for Colorado +natural gas production and NYMEX-traded over-the-counter oil swaps and option +contracts for Colorado oil production. We may utilize derivatives +based on other indices or markets where appropriate. The contracts +economically provide price stability for committed and anticipated oil and +natural gas purchases and sales, generally forecasted to occur within the next +two to three-year period, but no longer than five years beyond the derivative +transaction date. Our policies prohibit the use of oil and natural +gas futures, swaps or options for speculative purposes and permit utilization of +derivatives only if there is an underlying physical position. +RNG has +extensive experience with the use of derivatives to reduce the risk and effect +of natural gas price changes. RNG uses these financial derivatives to +coordinate fixed purchases and sales. We use financial derivatives to +establish “floors” and “ceilings” or “collars” on the possible range of the +prices realized for the sale of natural gas and oil in addition to fixing prices +by using swaps. RNG also enters into back-to-back fixed-price +purchases and sales contracts with counterparties. These fixed +physical contracts meet the SFAS No. 133, Accounting for Derivative +Instruments and Certain Hedging Activities , definition of a +derivative. Both types of derivatives (i.e., the physical deals and +the cash settled contracts) are carried on the balance sheet at fair value with +changes in fair values recognized currently in the statement of +operations. +We are +subject to price fluctuations for natural gas sold in the spot market and under +market index contracts. RNG does not always hedge the area basis risk +for third party trades with back-to-back fixed price purchases and +sales. We continue to evaluate the potential for reducing these risks +by entering into derivative transactions. In addition, we may close +out any portion of derivatives that may exist from time to time which may result +in a realized gain or loss on that derivative transaction. We manage +price risk on only a portion of our anticipated production, so the remaining +portion of our production is subject to the full fluctuation of market +pricing. +Well +Operations +As of +December 31, 2008, we had an interest in approximately 2,412 wells in the Rocky +Mountain Region, 2,090 wells in the Appalachian Basin, and 210 wells in the +Michigan Basin. On average, our interest ownership in these wells was +approximately 69.2%. +We are +paid a monthly operating fee for the portion of each well we operate that is +owned by others, including our sponsored partnerships. The fee is +competitive with rates charged by other operators in the area. The +fee covers monthly operating and accounting costs, insurance and other recurring +costs. If we purchase well interests belonging to investors in our +sponsored partnerships, we then account for the purchased interests as being +owned by us, which results in a decrease in well operations income. +Transportation +and Gathering +We +develop, own and operate gathering systems in some of our areas of +operations. We also continue to construct new trunk lines as +necessary to provide for the marketing of natural gas being developed from new +areas and to enhance or maintain our existing systems. Pipelines and +related facilities can represent a significant portion of the capital costs of +developing wells, particularly in new areas located at a distance from existing +pipelines. We consider these costs in our evaluation of our leasing, +development and acquisition opportunities. +12 +Table of Contents +Our +natural gas and oil are transported through our own and third party gathering +systems and pipelines, and we incur processing, gathering and transportation +expenses to move our natural gas from the wellhead to a purchaser-specified +delivery point. These expenses vary based on the volume and distance +shipped, and the fee charged by the third-party processor or +transporter. Capacity on these gathering systems and pipelines is +occasionally limited and at times unavailable because of repairs or +improvements, or as a result of priority transportation agreements with other +gas transporters. While our ability to market our natural gas has +been only infrequently limited or delayed, if transportation space is restricted +or is unavailable, our cash flow from the affected properties could be adversely +affected. In certain instances, we enter into firm transportation +agreements to provide for pipeline capacity to flow and sell a portion of our +gas volumes. In order to meet pipeline specifications, we are +required, in some cases, to process our gas before we can transport +it. We typically contract with third parties in the Grand Valley and +NECO areas of our Rocky Mountain Region and Appalachian Basin for firm +transportation of our natural gas. We also may enter into firm sales +agreements to ensure that we are selling to a purchaser who has contracted for +pipeline capacity. These agreements are subject to the same +limitations discussed above in this paragraph. +Governmental +Regulation +While the +prices of oil and natural gas are set by the market, other aspects of our +business and the oil and natural gas industry in general are heavily +regulated. The availability of a ready market for oil and natural gas +production depends on several factors beyond our control. These +factors include regulation of production, federal and state regulations +governing environmental quality and pollution control, the amount of oil and +natural gas available for sale, the availability of adequate pipeline and other +transportation and processing facilities and the marketing of competitive +fuels. State and federal regulations generally are intended to +protect consumers from unfair treatment and oppressive control, to reduce the +risk to the public and workers from the drilling, completion, production and +transportation of oil and natural gas, to prevent waste of oil and natural gas, +to protect rights among owners in a common reservoir and to control +contamination of the environment. Pipelines are subject to the +jurisdiction of various federal, state and local agencies. In the +western part of the U.S., the federal and state governments own a large +percentage of the land and the rights to develop oil and natural +gas. Generally, government leases are subject to additional +regulations and controls not commonly seen on private leases. We take +the steps necessary to comply with applicable regulations, both on our own +behalf and as part of the services we provide to our drilling +partnerships. We believe that we are in compliance with such +statutes, rules, regulations and governmental orders, although there can be no +assurance that this is or will remain the case. The following summary +discussion of the regulation of the U.S. oil and natural gas industry is not +intended to constitute a complete discussion of the various statutes, rules, +regulations and environmental orders to which our operations may be +subject. +Regulation +of Oil and Natural Gas Exploration and Production +Our +exploration and production business is subject to various federal, state and +local laws and regulations on the taxation of oil and natural gas, the +development, production and marketing of oil and natural gas and environmental +and safety matters. Many laws and regulations require drilling +permits and govern the spacing of wells, rates of production, water discharge, +prevention of waste and other matters. Prior to commencing drilling +activities for a well, we must procure permits and/or approvals for the various +stages of the drilling process from the applicable state and local agencies in +the state in which the area to be drilled is located. The permits and +approvals include those for the drilling of wells. Additionally, +other regulated matters include: +· +bond +requirements in order to drill or operate +wells; +· +the +location of wells; +· +the +method of drilling and casing +wells; +· +the +surface use and restoration of well +properties; +· +the +plugging and abandoning of wells; +and +· +the +disposal of fluids. +Our +operations are also subject to various conservation laws and +regulations. These include the regulation of the size of drilling and +spacing units or proration units, the density of wells which may be drilled and +the unitization or pooling of properties. In this regard, some states +allow the forced pooling or integration of tracts to facilitate exploration +while other states rely primarily or exclusively on voluntary pooling of lands +and leases. In areas where pooling is voluntary, it may be more +difficult to form units, and therefore, more difficult to develop a project if +the operator owns less than 100% of the leasehold. In addition, state +conservation laws may establish maximum rates of production from oil and natural +gas wells, generally prohibiting the venting or flaring of natural gas and +imposing certain requirements regarding the ratability of +production. Where wells are to be drilled on state or federal leases, +additional regulations and conditions may apply. The effect of these +regulations may limit the amount of oil and natural gas we can produce from our +wells and may limit the number of wells or the locations at which we can +drill. Such laws and regulations may increase the costs of planning, +designing, drilling, installing, operating and abandoning our oil and natural +gas wells and other facilities. In addition, these laws and +regulations, and any others that are passed by the jurisdictions where we have +production, could limit the total number of wells drilled or the allowable +production from successful wells, which could limit our reserves. As +a result, we are unable to predict the future cost or effect of complying with +such regulations. +13 +Table of Contents +Regulation +of Sales and Transportation of Natural Gas +Historically, +the price of natural gas was subject to limitation by federal +legislation. The Natural Gas Wellhead Decontrol Act removed, as of +January 1, 1993, all remaining federal price controls from natural gas sold in +“first sales” on or after that date. The Federal Energy Regulatory +Commission's, or FERC, jurisdiction over natural gas transportation was +unaffected by the Decontrol Act. +We move +natural gas through pipelines owned by other companies, and sell natural gas to +other companies that also utilize common carrier pipeline +facilities. Natural gas pipeline interstate transmission and storage +activities are subject to regulation by the FERC under the Natural Gas Act of +1938, or NGA, and under the Natural Gas Policy Act of 1978, and, as such, rates +and charges for the transportation of natural gas in interstate commerce, +accounting, and the extension, enlargement or abandonment of its jurisdictional +facilities, among other things, are subject to regulation. Each +natural gas pipeline company holds certificates of public convenience and +necessity issued by the FERC authorizing ownership and operation of all +pipelines, facilities and properties for which certificates are required under +the NGA. Each natural gas pipeline company is also subject to the +Natural Gas Pipeline Safety Act of 1968, as amended, which regulates safety +requirements in the design, construction, operation and maintenance of +interstate natural gas transmission facilities. FERC regulations +govern how interstate pipelines communicate and do business with their +affiliates. Interstate pipelines may not operate their pipeline +systems to preferentially benefit their marketing affiliates. +Each +interstate natural gas pipeline company establishes its rates primarily through +the FERC’s ratemaking process. Key determinants in the ratemaking +process are: +• +costs +of providing service, including depreciation +expense; +• +allowed +rate of return, including the equity component of the capital structure +and related income taxes; and +• +volume +throughput assumptions. +The +availability, terms and cost of transportation affect our natural gas +sales. In the past, FERC has undertaken various initiatives to +increase competition within the natural gas industry. As a result of +initiatives like FERC Order No. 636, issued in April 1992, the interstate +natural gas transportation and marketing system was substantially restructured +to remove various barriers and practices that historically limited non-pipeline +natural gas sellers, including producers, from effectively competing with +interstate pipelines for sales to local distribution companies and large +industrial and commercial customers. The most significant provisions +of Order No. 636 require that interstate pipelines provide transportation +separate or “unbundled” from their sales service, and require that pipelines +provide firm and interruptible transportation service on an open access basis +that is equal for all natural gas suppliers. In many instances, the +result of Order No. 636 and related initiatives has been to substantially reduce +or eliminate the interstate pipelines' traditional role as wholesalers of +natural gas in favor of providing only storage and transportation +services. Another effect of regulatory restructuring is greater +access to transportation on interstate pipelines. In some cases, +producers and marketers have benefited from this +availability. However, competition among suppliers has greatly +increased and traditional long-term producer-pipeline contracts are +rare. Furthermore, gathering facilities of interstate pipelines are +no longer regulated by FERC, thus allowing gatherers to charge higher gathering +rates. Historically, producers were able to flow supplies into +interstate pipelines on an interruptible basis; however, recently we have seen +the increased need to acquire firm transportation on pipelines in order to avoid +curtailments or shut-in-gas, which could adversely affect cash flows from the +affected area. +Additional +proposals and proceedings that might affect the natural gas industry occur +frequently in Congress, FERC, state commissions, state legislatures, 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 FERC and Congress will continue. We +cannot determine to what extent our future operations and earnings will be +affected by new legislation, new regulations, or changes in existing regulation, +at federal, state or local levels. +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. Public interest in the protection of the environment has +increased dramatically in recent years. The trend of more expansive +and tougher environmental legislation and regulations could +continue. To the extent laws are enacted or other governmental action +is taken that restricts drilling or imposes environmental protection +requirements that result in increased costs and reduced access to the natural +gas industry in general, our business and prospects could be adversely +affected. +We +generate wastes that may be subject to the Federal Resource Conservation and +Recovery Act, or RCRA, and comparable state statutes. The U.S. +Environmental Protection Agency, or EPA, and various state agencies have limited +the approved methods of disposal for certain hazardous and non-hazardous +wastes. Furthermore, certain wastes generated by our operations that +are currently exempt from treatment as “hazardous wastes” may in the future be +designated as “hazardous wastes,” and therefore be subject to more rigorous and +costly operating and disposal requirements. +14 +Table of Contents +We +currently own or lease numerous properties that for many years have been used +for the exploration and production of oil and natural gas. Although +we believe that we have utilized good operating and waste disposal practices, +and when necessary, appropriate remediation techniques, prior owners and +operators of these properties may not have utilized similar practices and +techniques, and hydrocarbons or other wastes may have been disposed of or +released on or under the properties that we own or lease or on or under +locations where such wastes have been taken for disposal. These +properties and the wastes disposed thereon may be subject to the Comprehensive +Environmental Response, Compensation and Liability Act, or CERCLA, RCRA and +analogous state laws, as well as state laws governing the management of oil and +natural gas wastes. Under such laws, 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) or to perform remedial plugging operations to prevent +future contamination. +CERCLA +and similar state laws impose liability, without regard to fault or the legality +of the original conduct, on certain classes of persons that are considered to +have contributed to the release of a “hazardous substance” into the +environment. These persons include the owner or operator of the +disposal site or sites where the release occurred and companies that disposed of +or arranged for the disposal of the hazardous substances found at the +site. Persons who are or were responsible for release of hazardous +substances under CERCLA may be subject to full liability for the costs of +cleaning up the hazardous substances that have been released into the +environment and for damages to natural resources, and 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. As an owner and operator of oil and natural gas +wells, we may be liable pursuant to CERCLA and similar state laws. +Our +operations may be subject to the Clean Air Act, or CAA, and comparable state and +local requirements. Amendments to the CAA were adopted in 1990 and +contain provisions that may result in the gradual imposition of certain +pollution control requirements with respect to air emissions from our +operations. The EPA and states have been developing regulations to +implement these requirements. We may be required to incur certain +capital expenditures in the next several years for air pollution control +equipment in connection with maintaining or obtaining operating permits and +approvals addressing other air emission-related issues. The State of +Colorado has also indicated it intends to implement new air regulations in 2009, +which affect the oil and gas industry, including our operations, related to air +emissions. +The +Federal Clean Water Act, or CWA, and analogous state laws impose strict controls +against the discharge of pollutants, including spills and leaks of oil and other +substances. The CWA also regulates storm water run-off from oil and +gas facilities and requires a storm water discharge permit for certain +activities. Spill prevention, control, and countermeasure +requirements of the CWA require appropriate containment terms and similar +structures to help prevent the contamination of navigable waters in the event of +a petroleum hydrocarbon tank spill, rupture, or leak. +Oil +production is subject to many of the same operating hazards and environmental +concerns as natural gas production, but is also subject to the risk of oil +spills. Federal regulations require certain owners or operators of +facilities that store or otherwise handle oil, including us, to procure and +implement Spill Prevention, Control and Counter-measures plans relating to the +possible discharge of oil into surface waters. The Oil Pollution Act +of 1990, or OPA, subjects owners of facilities to strict joint and several +liability for all containment and cleanup costs and certain other damages +arising from oil spills. Noncompliance with OPA may result in varying +civil and criminal penalties and liabilities. We are also subject to +the CWA and analogous state laws relating to the control of water pollution, +which laws provide varying civil and criminal penalties and liabilities for +release of petroleum or its derivatives into surface waters or into the +ground. Historically, we have not experienced any significant oil +discharge or oil spill problems. +In +December 2008, the State of Colorado’s Oil and Gas Conservation Commission +finalized new broad-based environmental regulations for the oil and natural gas +industry. These regulations will increase our costs and may +ultimately limit some drilling locations. Our expenses relating to +preserving the environment have risen over the past few years and are expected +to continue to rise in 2009 and beyond. Environmental regulations +have had no materially adverse effect on our operations to date, but no +assurance can be given that environmental regulations or interpretations of such +regulations will not, in the future, result in a curtailment of production or +otherwise have a materially adverse effect on our business, financial condition +or results of operations. See Note 8 , Commitments and Contingencies – +Litigation, Colorado Stormwater Permit , to our accompanying consolidated +financial statements included in this report. +Operating +Hazards and Insurance +Our +exploration and production operations include a variety of operating risks, +including, but not limited to, the risk of fire, explosions, blowouts, +cratering, pipe failure, casing collapse, abnormally pressured formations, and +environmental hazards such as gas leaks, ruptures and discharges of toxic +gas. The occurrence of any of these could result in substantial +losses to us due to injury and loss of life, severe damage to and destruction of +property, natural resources and equipment, pollution and other environmental +damage, clean-up responsibilities, regulatory investigation and penalties and +suspension of operations. Our pipeline, gathering and distribution +operations are subject to the many hazards inherent in the natural gas +industry. These hazards include damage to wells, pipelines and other +related equipment, damage to property caused by hurricanes, floods, fires and +other acts of God, inadvertent damage from construction equipment, leakage of +natural gas and other hydrocarbons, fires and explosions and other hazards that +could also result in personal injury and loss of life, pollution and suspension +of operations. +15 +Table of Contents +Any +significant problems related to our facilities could adversely affect our +ability to conduct our operations. In accordance with customary +industry practice, we maintain insurance against some, but not all, potential +risks; however, there can be no assurance that such insurance will be adequate +to cover any losses or exposure for liability. The occurrence of a +significant event not fully insured against could materially adversely affect +our operations and financial condition. We cannot predict whether +insurance will continue to be available at premium levels that justify our +purchase or whether insurance will be available at all. Furthermore, +we are not insured against our economic losses resulting from damage or +destruction to third party property, such as the Rockies Express pipeline; such +an event could result in significantly lower regional prices or our inability to +deliver gas. +Competition +We +believe that our exploration, drilling and production capabilities and the +experience of our management and professional staff generally enable us to +compete effectively. We encounter competition from numerous other oil +and natural gas companies, drilling and income programs and partnerships in all +areas of operations, including drilling and marketing oil and natural gas and +obtaining desirable oil and natural gas leases on producing +properties. Many of these competitors possess larger staffs and +greater financial resources than we do, which may enable them to identify and +acquire desirable producing properties and drilling prospects more +economically. Our ability to explore for oil and natural gas +prospects and to acquire additional properties in the future depends upon our +ability to conduct our operations, to evaluate and select suitable properties +and to consummate transactions in this highly competitive +environment. We also face intense competition in the marketing of +natural gas from competitors including other producers as well as marketing +companies. Also, international developments and the possible improved +economics of domestic natural gas exploration may influence other companies to +increase their domestic oil and natural gas exploration. Furthermore, +competition among companies for favorable prospects can be expected to continue, +and it is anticipated that the cost of acquiring properties may increase in the +future. During 2008, our industry experienced continued strong demand +for drilling services and supplies which resulted in increasing +costs. In 2009, due to industry slowdown, we are experiencing overall +reductions in our operating and drilling costs. Factors affecting +competition in the oil and natural gas industry include price, location of +drilling, availability of drilling prospects and drilling rigs, pipeline +capacity, quality of production and volumes produced. We believe that +we can compete effectively in the oil and natural gas industry in each of the +listed areas. Nevertheless, our business, financial condition and +results of operations could be materially adversely affected by +competition. We also compete with other oil and gas companies as well +as companies in other industries for the capital we need to conduct our +operations. Recently, turmoil in the capital markets has made +financing more expensive and difficult to obtain. In the event that +we do not have adequate capital to execute our business plan, we may be forced +to curtail our drilling and acquisition activities. +Employees +As of +December 31, 2008, we had 317 employees, including 205 in production, 8 in +natural gas marketing, 28 in exploration and development, 49 in finance, +accounting and data processing, and 27 in administration. Our +engineers, supervisors and well tenders are responsible for the day-to-day +operation of wells and some pipeline systems. In addition, we retain +subcontractors to perform drilling, fracturing, logging, and pipeline +construction functions at drilling sites, with our employees supervising the +activities of the subcontractors. In 2008, the total number of +Company employees increased by 61. +Our +employees are not covered by a collective bargaining agreement. We +consider relations with our employees to be very good. +ITEM 1A. RISK FACTORS +You +should carefully consider the following risk factors in addition to the other +information included in this report. Each of these risk factors could +adversely affect our business, operating results and financial condition, as +well as adversely affect the value of an investment in our common stock or other +securities. +16 +Table of Contents +Risks +Related to the Global Economic Environment +The +current global economic environment may increase the magnitude and the +likelihood of the occurrence of the negative consequences discussed in many of +the risks factors that follow. +In +particular, consider the risks related to (1) the rapid deterioration of demand +for oil and natural gas resulting from the economic environment and the related +negative effects on oil and gas pricing, and (2) the effect of the credit +constraints on our business, including the severe reduction in the availability +of credit for drilling or to finance acquisitions. Also consider the +interplay between these two risks: decline in oil and gas prices can lead to a +reduction in the borrowing base for our credit line, and hence a reduction in +our credit available for drilling. Similarly, further reductions in +oil and gas prices could result in some of our assets becoming uneconomic to +exploit, which would reduce our reserves, which in turn would reduce our +borrowing base and the credit available to us. These factors could +result in less drilling and production by us, and could thereby adversely affect +our profitability and could limit our ability to execute our business +plan. These factors could also make it impossible or extremely +expensive to extend the term of our revolving credit line. The global +economic environment also increases the counterparty failure risk for both the +banks which are parties to our oil and gas derivative holdings and for payments +from purchasers of our oil and gas. Lastly, inability to ascertain +the ultimate depth and duration of the economic environment could cause us to +refrain from capital expenditures in order to maintain higher liquidity; our +uncertainty and caution could result in significantly reduced drilling and hence +reduced future production. All these risks could have a significant +adverse effect on our business and our financial results. Any +additional deterioration in the domestic or global economic conditions will +further amplify these risks. +Recent +disruptions in the global financial markets and the related economic environment +may further decrease the demand for oil and gas and the prices of oil and gas, +thereby limiting our future drilling and production, and thereby adversely +affecting our profitability. +During +the second half of 2008 and to date, prices for oil and gas decreased over +70%. The well-publicized global financial market disruptions and the +related economic environment may further decrease demand for oil and gas and +therefore lower oil and gas prices. If there is such an additional reduction in +demand, the continued production of gas may increase current oversupply and +result in still lower gas prices. There is no certainty how long this +low price environment will continue. We operate in a highly +competitive industry, and certain competitors may have lower operating costs in +such an environment. Furthermore, as a result of these disruptions in +the financial markets, it is possible that in future years we would not be able +to borrow sufficient funds to sustain or increase capital expenditures relative +to 2008 expenditures, should we wish to make expenditures at those +levels. Such market conditions may also make it more difficult or +impossible for us to finance acquisitions, through either equity or debt; +acquisitions have historically been a major source of growth for +us. We may also have difficulty finding partners to develop new +drilling prospects and to build the pipeline systems needed to transport our +gas. Inability of third parties to finance and build additional +pipelines out of the Rockies and elsewhere could cause significant negative +pricing effects. Any of the above factors could adversely affect our +operating results. +Risks +Related to Our Business and the Natural Gas and Oil Industry +Natural +gas and oil prices fluctuate unpredictably and a decline in natural gas and oil +prices can significantly affect the value of our assets, our financial results +and impede our growth. +Our +revenue, profitability and cash flow depend in large part upon the prices and +demand for natural gas and oil. The markets for these commodities are +very volatile, and even relatively modest drops in prices can significantly +affect our financial results and impede our growth. Changes in +natural gas and oil prices have a significant effect on our cash flow and on the +value of our reserves, which can in turn reduce our borrowing base under our +senior credit agreement. Prices for natural gas and oil may fluctuate +widely in response to relatively minor changes in the supply of and demand for +natural gas and oil, market uncertainty and a variety of additional factors that +are beyond our control, including national and international economic and +political factors and federal and state legislation. The prices from the fourth +quarter of 2008 to date have been too low to economically justify many drilling +operations, and it is uncertain how long such low pricing shall +persist. +The +prices of natural gas and oil are volatile, often fluctuating +greatly. Lower natural gas and oil prices may not only reduce our +revenues, but also may reduce the amount of natural gas and oil that we can +produce economically. As a result, we may have to make substantial +additional downward adjustments to our estimated proved reserves. If +this occurs or if our estimates of development costs increase, production data +factors change or our exploration results deteriorate, accounting rules may +require us to write-down operating assets to fair value, as a non-cash charge to +earnings. We assess impairment of capitalized costs of proved natural +gas and oil properties by comparing net capitalized costs to estimated +undiscounted future net cash flows on a field-by-field basis using estimated +production based upon prices at which management reasonably estimates such +products may be sold. In 2008, we recorded an impairment charge of +$7.5 million primarily related to our Texas Barnett Shale wells, and in 2006, we +recorded an impairment charge of $1.5 million related to our Nesson field in +North Dakota. There were no impairments during 2007. We +may incur impairment charges in the future, which could have a material adverse +effect on the results of our operations. +17 +Table of Contents +A +substantial part of our natural gas and oil production is located in the Rocky +Mountain Region, making it vulnerable to risks associated with operating +primarily in a single geographic area. +Our +operations have been focused on the Rocky Mountain Region, which means our +current producing properties and new drilling opportunities are geographically +concentrated in that area. Because our operations are not as +diversified geographically as many of our competitors, the success of our +operations and our profitability may be disproportionately exposed to the affect +of any regional events, including fluctuations in prices of natural gas and oil +produced from the wells in the region, natural disasters, restrictive +governmental regulations, transportation capacity constraints, curtailment of +production or interruption of transportation, and any resulting delays or +interruptions of production from existing or planned new wells. +During +the last four months of 2008, natural gas prices in the Rocky Mountain Region +fell disproportionately when compared to other markets, due in part to +continuing constraints in transporting natural gas from producing properties in +the region. Because of the concentration of our operations in the +Rocky Mountain Region, and although, in late 2008 we entered into a significant +multi-year basis hedge in order to minimize the price risk of our concentration +in the Rocky Mountain Region, such price decreases are more likely to have a +material adverse effect on our revenue, profitability and cash flow than those +of our more geographically diverse competitors. +Our +estimated natural gas and oil reserves are based on many assumptions that may +turn out to be inaccurate. Any material inaccuracies in these reserve +estimates or underlying assumptions may materially affect the quantities and +present value of our reserves. +Natural +gas and oil reserve engineering requires subjective estimates of underground +accumulations of natural gas and oil and assumptions concerning future natural +gas and oil prices, production levels, and operating and development costs over +the economic life of the properties. As a result, estimated +quantities of proved reserves and projections of future production rates and the +timing of development expenditures may be inaccurate. Independent +petroleum engineers prepare our estimates of natural gas and oil reserves using +pricing, production, cost, tax and other information that we +provide. The reserve estimates are based on certain assumptions +regarding future natural gas and oil prices, production levels, and operating +and development costs that may prove incorrect. Any significant +variance from these assumptions to actual figures could greatly +affect: +· +the +estimates of reserves; +· +the +economically recoverable quantities of natural gas and oil attributable to +any particular group of properties; +· +future +depreciation, depletion and amortization rates and +amounts; +· +impairments +in the value of our assets; +· +the +classifications of reserves based on risk of +recovery; +· +estimates +of the future net cash flows; and +· +timing +of our capital +expenditures. +Some of +our reserve estimates must be made with limited production history, which +renders these reserve estimates less reliable than estimates based on a longer +production history. Numerous changes over time to the assumptions on +which the reserve estimates are based, as described above, often result in the +actual quantities of natural gas and oil recovered being different from earlier +reserve estimates. +The +present value of our estimated future net cash flows from proved reserves is not +necessarily the same as the current market value of our estimated natural gas +and oil reserves (the SEC requires the use of year end prices). The +estimated discounted future net cash flows from proved reserves are based on +selling prices in effect on the day of estimate (year end). However, +factors such as actual prices we receive for natural gas and oil and hedging +instruments, the amount and timing of actual production, amount and timing of +future development costs, supply of and demand for natural gas and oil, and +changes in governmental regulations or taxation also affect our actual future +net cash flows from our natural gas and oil properties. +The +timing of both our production and incurrence of expenses in connection with the +development and production of natural gas and oil properties will affect the +timing of actual future net cash flows from proved reserves, and thus their +actual present value. In addition, the 10% discount factor (the rate +required by the SEC) we use when calculating discounted future net cash flows +may not be the most appropriate discount factor based on interest rates +currently in effect and risks associated with our natural gas and oil properties +or the natural gas and oil industry in general. +18 +Table of Contents +Unless +natural gas and oil reserves are replaced as they are produced, our reserves and +production will decline, which would adversely affect our future business, +financial condition and results of operations. +Producing +natural gas and oil reservoirs generally is characterized by declining +production rates that vary depending upon reservoir characteristics and other +factors. The rate of decline will change if production from existing +wells declines in a different manner than we estimated and the rate can change +due to other circumstances. Thus, our future natural gas and oil +reserves and production and, therefore, our cash flow and income, are highly +dependent on efficiently developing and exploiting our current reserves and +economically finding or acquiring additional recoverable reserves. We +may not be able to develop, discover or acquire additional reserves to replace +our current and future production at acceptable costs. As a result, +our future operations, financial condition and results of operations would be +adversely affected. +Acquisitions +are subject to the uncertainties of evaluating recoverable reserves and +potential liabilities. +Acquisitions +of producing properties and undeveloped properties have been an important part +of our historical growth. We expect acquisitions will also contribute +to our future growth. Successful acquisitions require an assessment +of a number of factors, many of which are beyond our control. These +factors include recoverable reserves, development potential, future natural gas +and oil prices, operating costs and potential environmental and other +liabilities. Such assessments are inexact and their accuracy is +inherently uncertain. In connection with our assessments, we perform +engineering, geological and geophysical reviews of the acquired properties, +which we believe is generally consistent with industry +practices. However, such reviews are not likely to permit us to +become sufficiently familiar with the properties to fully assess their +deficiencies and capabilities. We do not inspect every well prior to +an acquisition and our ability to evaluate undeveloped acreage is inherently +imprecise. Even when we inspect a well, we do not always discover +structural, subsurface and environmental problems that may exist or +arise. In some cases, our review prior to signing a definitive +purchase agreement may be even more limited. +Our focus +on acquiring producing natural gas and oil properties may increase our potential +exposure to liabilities and costs for environmental and other problems existing +on acquired properties. Often we are not entitled to contractual +indemnification associated with acquired properties. Normally, we +acquire interests in properties on an “as is” basis with no or limited remedies +for breaches of representations and warranties, as was the case in the +acquisitions of assets from EXCO Resources Inc. and Castle Gas Company, as well +as the acquisition of all shares of Unioil, Inc. We could incur +significant unknown liabilities, including environmental liabilities, or +experience losses due to title defects, in our acquisitions for which we have +limited or no contractual remedies or insurance coverage. +Additionally, +significant acquisitions can change the nature of our operations 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. For example, in the Castle acquisition, +we acquired interests in wells which we will need to operate together with other +partners, we acquired pipelines that we will need to operate and expect we will +need to commit to drilling in the acquired areas to achieve the expected +benefits. Consequently, we may not be able to efficiently realize the +assumed or expected economic benefits of properties that we acquire, if at +all. +When +drilling prospects, we may not yield natural gas or oil in commercially viable +quantities. +A +prospect is a property on which our geologists have identified what they +believe, based on available information, to be indications of natural gas or oil +bearing rocks. However, our geologists cannot know conclusively prior +to drilling and testing whether natural gas or oil will be present or, if +present, whether natural gas or oil will be present in sufficient quantities to +repay drilling or completion costs and generate a profit given the available +data and technology. If a well is determined to be dry or uneconomic, +which can occur even though it contains some oil or natural gas, it is +classified as a dry +hole and must be plugged and abandoned in accordance with applicable +regulations. This generally results in the loss of the entire cost of +drilling and completion to that point, the cost of plugging, and lease costs +associated with the prospect. Even wells that are completed and +placed into production may not produce sufficient natural gas and oil to be +profitable. If we drill a dry hole or unprofitable well on current +and future prospects, the profitability of our operations will decline and our +value will likely be reduced. In sum, the cost of drilling, +completing and operating any well is often uncertain and new wells may not be +productive. Our recent uneconomic drilling in the Texas Barnett Shale +illustrates this risk. +We +may not be able to identify enough attractive prospects on a timely basis to +meet our development needs, which could limit our future development +opportunities. +Our +geologists have identified a number of potential drilling locations on our +existing acreage. These drilling locations must be replaced as they +are drilled for us to continue to grow our reserves and +production. Our ability to identify and acquire new drilling +locations depends on a number of uncertainties, including the availability of +capital, regulatory approvals, natural gas and oil prices, competition, costs, +availability of drilling rigs, drilling results and the ability of our +geologists to successfully identify potentially successful new areas to +develop. Because of these uncertainties, our profitability and growth +opportunities may be limited by the timely availability of new drilling +locations. As a result, our operations and profitability could be +adversely affected. +19 +Table of Contents +Drilling +for and producing natural gas and oil are high risk activities with many +uncertainties that could adversely affect our business, financial condition and +results of operations. +Drilling +activities are subject to many risks, including the risk that we will not +discover commercially productive reservoirs. Drilling for natural gas and oil +can be unprofitable, not only due to dry holes, but also due to curtailments, +delays or cancellations as a result of other factors, including: +• unusual +or unexpected geological formations; +• +pressures; +• +fires; +• +blowouts; +• loss of +drilling fluid circulation; +• title +problems; +• +facility or equipment malfunctions; +• +unexpected operational events; +• +shortages or delivery delays of equipment and services; +• +compliance with environmental and other governmental requirements; +and +• adverse +weather conditions. +Any of +these risks can cause substantial losses, including personal injury or loss of +life, damage to or destruction of property, natural resources and equipment, +pollution, environmental contamination or loss of wells and regulatory +penalties. We maintain insurance against various losses and +liabilities arising from operations; however, insurance against all operational +risks is not available. Additionally, our management may elect not to +obtain insurance if the cost of available insurance is excessive relative to the +perceived risks presented. Thus, losses could occur for uninsurable or uninsured +risks or in amounts in excess of existing insurance coverage. The +occurrence of an event that is not fully covered by insurance could have a +material adverse effect on our business activities, financial condition and +results of operations. +Our +oil and gas well drilling operations segment has historically received most of +its revenue from the partnerships we sponsor, and a reduction or loss of that +business could reduce or eliminate the revenue, profit and cash flow associated +with those activities. +Our oil +and gas well drilling operations segment has, prior to 2008, received most of +its revenue from the partnerships we sponsor. We sponsor oil and +natural gas partnerships through a network of non-affiliated FINRA broker +dealers. We did not offer a partnership in 2008 and do not +anticipate offering a partnership in 2009. There can be no assurance +that the network of brokers will be available or can be recreated if we wish to +use partnerships to raise funds in future years. In that situation, +our operations and profitability could be adversely +affected. +Under +the “successful efforts” accounting method that we use, unsuccessful exploratory +wells must be expensed in the period when they are determined to be +non-productive, which reduces our net income in such periods and could have a +negative effect on our profitability. +We have +conducted exploratory drilling and plan to continue exploratory drilling in 2009 +in order to identify additional opportunities for future +development. Under the “successful efforts” method of accounting that +we use, the cost of unsuccessful exploratory wells must be charged to expense in +the period when they are determined to be unsuccessful. In addition, +lease costs for acreage condemned by the unsuccessful well must also be +expensed. In contrast, unsuccessful development wells are capitalized +as a part of the investment in the field where they are +located. Because exploratory wells generally are more likely to be +unsuccessful than development wells, we anticipate that some or all of our +exploratory wells may not be productive. The costs of such +unsuccessful exploratory wells could result in a significant reduction in our +profitability in periods when the costs are required to be expensed and these +increased costs could reduce our net income and have a negative effect on our +profitability and ability to repay or refinance our +indebtedness. +20 +Table of Contents +Increasing finding and development +costs may impair our profitability. +In order +to continue to grow and maintain our profitability, we must annually add new +reserves that exceed our yearly production at a finding and development cost +that yields an acceptable operating margin and depreciation, depletion and +amortization rate. Without cost effective exploration, development or +acquisition activities, our production, reserves and profitability will decline +over time. Given the relative maturity of most natural gas and oil +basins in North America and the high level of activity in the industry, the cost +of finding new reserves through exploration and development operations has been +increasing. The acquisition market for natural gas and oil properties +has become extremely competitive among producers for additional production and +expanded drilling opportunities in North America. Acquisition values +climbed toward historic highs during 2007 and 2008 on a per unit basis, +particularly in the Rocky Mountain Region, and these values may continue to +increase in the future. This increase in finding and development +costs results in higher depreciation, depletion and amortization +rates. If the upward trend in finding and development costs +continues, we will be exposed to an increased likelihood of a write-down in +carrying value of our natural gas and oil properties in response to falling +commodity prices and reduced profitability of our operations. +Our +development and exploration operations require substantial capital, and we may +be unable to obtain needed capital or financing on satisfactory terms, which +could lead to a loss of properties and a decline in our natural gas and oil +reserves, and ultimately our profitability. +The +natural gas and oil industry is capital intensive. We expect to +continue to make substantial capital expenditures in our business and operations +for the exploration, development, production and acquisition of natural gas and +oil reserves. To date, we have financed capital expenditures +primarily with bank borrowings, cash generated by operations and our 2008 public +note issuance. We intend to finance our future capital expenditures +with cash flow from operations and our existing and planned financing +arrangements. Our cash flow from operations and access to capital is +subject to a number of variables, including: +• our +proved reserves; +• the +amount of natural gas and oil we are able to produce from existing +wells; +• the +prices at which natural gas and oil are sold; +• the +costs to produce oil and natural gas; and +• our +ability to acquire, locate and produce new reserves. +If our +revenues or the borrowing base under our credit facility decreases as a result +of lower natural gas and oil prices, operating difficulties, declines in +reserves or for any other reason, then we may have limited ability to obtain the +capital necessary to sustain our operations at current levels. We +may, from time to time, need to seek additional financing. There can +be no assurance as to the availability or terms of any additional +financing. +If +our revenues or the borrowing base under our revolving credit facility decrease +as a result of lower natural gas and oil prices, or we incur operating +difficulties, declines in reserves or for any other reason, we may have limited +ability to obtain the capital necessary to sustain our operations at planned +levels, and our profitability may be adversely affected. +If +additional capital is needed, we may not be able to obtain debt or equity +financing on favorable terms, or at all. If cash generated by our +operations or sale of drilling partnerships or available under our revolving +credit facility is not sufficient to meet our capital requirements, failure to +obtain additional financing could result in a curtailment of the exploration and +development of our prospects, which in turn could lead to a possible loss of +properties, decline in natural gas and oil reserves and a decline in our +profitability. +Seasonal +weather conditions and lease stipulations adversely affect our ability to +conduct drilling activities in some of the areas where we operate. +Seasonal +weather conditions and lease stipulations designed to protect various wildlife +affect natural gas and oil operations in the Rocky Mountains. In +certain areas, including parts of the Piceance Basin in Colorado, drilling and +other natural gas and oil activities are restricted or prohibited by lease +stipulations, or prevented by weather conditions, for up to six months out of +the year. This limits our operations in those areas and can intensify +competition during those months for drilling rigs, oil field equipment, +services, supplies and qualified personnel, which may lead to periodic +shortages. These constraints and the resulting shortages or high +costs could delay our operations and materially increase operating and capital +costs and therefore adversely affect our profitability. +21 +Table of Contents +We +have limited control over activities on properties in which we own an interest +but we do not operate, which could reduce our production and +revenues. +We +operate most of the wells in which we own an interest. However, there +are some wells we do not operate because we participate through joint operating +agreements under which we own partial interests in natural gas and oil +properties operated by other entities. If we do not operate the +properties in which we own an interest, we do not have control over normal +operating procedures, expenditures or future development of underlying +properties. The failure of an operator to adequately perform +operations, or an operator’s breach of the applicable agreements, could reduce +production and revenues and affect our profitability. The success and +timing of drilling and development activities on properties operated by others +therefore depends upon a number of factors outside of our control, including the +operator’s timing and amount of capital expenditures, expertise (including +safety and environmental compliance) and financial resources, inclusion of other +participants in drilling wells, and use of technology. +Market +conditions or operational impediments could hinder our access to natural gas and +oil markets or delay production. +Market +conditions or the unavailability of satisfactory natural gas and oil +transportation arrangements may hinder our access to natural gas and oil markets +or delay our production. The availability of a ready market for +natural gas and oil production depends on a number of factors, including the +demand for and supply of natural gas and oil and the proximity of reserves to +pipelines and terminal facilities. Our ability to market our +production depends in substantial part on the availability and capacity of +gathering systems, pipelines and processing facilities owned and operated by +third parties. Failure to obtain such services on acceptable terms +could materially harm our business. We may be required to shut in +wells for lack of market or because of inadequacy, unavailability or the pricing +associated with natural gas pipeline, gathering system capacity or processing +facilities. If that were to occur, we would be unable to realize +revenue from those wells until we made production arrangements to deliver the +product to market. Thus, our profitability would be adversely +affected. +Our +derivative activities could result in financial losses or reduced income from +failure to perform by our counterparties or from changes in +prices. +We use +derivatives for a portion of our natural gas and oil production from our own +wells, our partnerships and for natural gas purchases and sales by our marketing +subsidiary to achieve a more predictable cash flow, to reduce exposure to +adverse fluctuations in the prices of natural gas and oil, and to allow our +natural gas marketing company to offer pricing options to natural gas sellers +and purchasers. These arrangements expose us to the risk of financial loss in +some circumstances, including when purchases or sales are different than +expected, the counter-party to the derivative contract defaults on its contract +obligations, or when there is a change in the expected differential between the +underlying price in the derivative agreement and actual prices that we +receive. +In +addition, derivative arrangements may limit the benefit from changes in the +prices for natural gas and oil and may require the use of our resources to meet +cash margin requirements. Since our derivatives do not currently +qualify for use of hedge accounting, changes in the fair value of derivatives +are recorded in our income statements, and our net income is subject to greater +volatility than if our derivative instruments qualified for hedge +accounting. For instance, if oil and gas prices rise significantly, +it could result in significant non-cash charges each quarter, which could have a +material negative effect on our net income. +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 natural gas and oil sales or joint +interest billings to a small number of third parties in the energy +industry. This concentration of customers and joint interest owners +may affect our overall credit risk in that these entities may be similarly +affected by changes in economic and other conditions. In addition, +our natural gas and oil derivatives as well as the derivatives used by our +marketing subsidiary expose us to credit risk in the event of nonperformance by +counterparties. +Terrorist +attacks or similar hostilities may adversely affect our results of +operations. +Increasing +terrorist attacks around the world have created many economic and political +uncertainties, some of which may materially adversely affect our +business. Uncertainty surrounding military strikes or a sustained +military campaign may affect our operations in unpredictable ways, including +disruptions of fuel supplies and markets, particularly oil, and the possibility +that infrastructure facilities, including pipelines, production facilities, +processing plants and refineries, could be direct targets of, or indirect +casualties of, an act of terror or war. The continuation of these +attacks may subject our operations to increased risks and, depending on their +ultimate magnitude, could have a material adverse effect on our business, +results of operations, financial condition and prospects. +Our +insurance coverage may not be sufficient to cover some liabilities or losses +that we may incur. +The +occurrence of a significant accident or other event not fully covered by +insurance could have a material adverse effect on our operations and financial +condition. Insurance does not protect us against all operational +risks. We do not carry business interruption insurance at levels that +would provide enough funds for us to continue operating without access to other +funds. For some risks, such as drilling blow-out insurance, we may +not obtain insurance if we believe the cost of available insurance is excessive +relative to the risks presented. In addition, pollution and +environmental risks that we are subject to are generally not fully +insurable. +22 +Table of Contents +We +may not be able to keep pace with technological developments in our +industry. +The +natural gas and oil industry is characterized by rapid and significant +technological advancements and introductions of new products and services using +new technologies. As our competitors use or develop new technologies, +we may be placed at a competitive disadvantage, and competitive pressures may +force us to implement those new technologies at substantial cost. In +addition, other natural gas and oil companies 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. We may not be able to respond to these competitive pressures +and implement new technologies on a timely basis or at an acceptable +cost. If one or more of the technologies we use now or in the future +were to become obsolete or if we were unable to use the most advanced +commercially available technology, our business, financial condition and results +of operations could be materially adversely affected. +Competition +in the natural gas and oil industry is intense, which may adversely affect our +ability to succeed. +The +natural gas and oil industry is intensely competitive, and we compete with other +companies that have greater resources. Many of these companies not +only explore for and produce natural gas and oil, but also carry on refining +operations and market petroleum and other products on a regional, national or +worldwide basis. These companies may be able to pay more for +productive natural gas and oil properties and exploratory prospects or define, +evaluate, bid for and purchase a greater number of properties and prospects than +we can. In addition, these companies may have a greater ability to +continue exploration activities during periods of low natural gas and oil market +prices. Larger competitors may be able to absorb the burden of +present and future federal, state, local and other laws and regulations more +easily than we can, which can adversely affect our competitive +position. Our ability to acquire additional properties and to +discover reserves in the future will be dependent upon our ability to evaluate +and select suitable properties and to consummate transactions in a highly +competitive environment. In addition, because many companies in our +industry have greater financial and human resources, we may be at a disadvantage +in bidding for exploratory prospects and producing natural gas and oil +properties. These factors could adversely affect the success of our +operations and our profitability. +We +are subject to complex federal, state, local and other laws and regulations that +could adversely affect the cost, manner or feasibility of doing +business. +Our +exploration, development, production and marketing operations are regulated +extensively at the federal, state and local levels. Environmental and other +governmental laws and regulations have increased the costs to plan, design, +drill, install, operate and abandon natural gas and oil wells. Under +these laws and regulations, we could also be liable for personal injuries, +property damage and other damages. Failure to comply with these laws +and regulations may result in the suspension or termination of operations and +subject us to administrative, civil and criminal penalties. Moreover, +public interest in environmental protection has increased in recent years, and +environmental organizations have opposed, with some success, certain drilling +projects. +Part of +the regulatory environment includes federal requirements for obtaining +environmental assessments, environmental impact studies and/or plans of +development before commencing exploration and production +activities. In addition, our activities are subject to the regulation +by natural gas and oil-producing states of conservation practices and protection +of correlative rights. These regulations affect our operations, +increase our costs of exploration and production and limit the quantity of +natural gas and oil that we can produce and market. A major risk +inherent in our drilling plans is the need to obtain drilling permits from state +and local authorities. Delays in obtaining regulatory approvals, +drilling permits, 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. Additionally, the natural gas and oil regulatory +environment could change in ways that might substantially increase our financial +and managerial costs to comply with the requirements of these laws and +regulations and, consequently, adversely affect our +profitability. Furthermore, these additional costs may put us at a +competitive disadvantage compared to larger companies in the industry which can +spread such additional costs over a greater number of wells and larger operating +staff. +Illustrative +of these risks are regulations recently enacted by the State of Colorado which +focus on the oil and gas industry. These multi-faceted proposed +regulations significantly enhance requirements regarding oil and gas permitting, +environmental requirements, and wildlife protection. Permitting +delays and increased costs could result from these final +regulations. +23 +Table of Contents +Litigation +has been commenced against us pertaining to our royalty practices and payments; +the cost of our defending these lawsuits, and any future similar lawsuit, could +be significant and any resulting judgments against us could have a material +adverse effect upon our financial condition. +In recent +years, litigation has commenced against us and several other companies in our +industry regarding royalty practices and payments in jurisdictions where we +conduct business. For more information on the suits that currently +relate to us, see Item +3 , Legal +Proceedings . We intend to defend ourselves vigorously in these +cases. Even if the ultimate outcome of this litigation resulted in +our dismissal, defense costs could be significant. These costs would +be reflected in terms of dollar outlay as well as the amount of time, attention +and other resources that our management would have to appropriate to the +defense. Although we cannot predict an eventual outcome of this +litigation, a judgment in favor of a plaintiff could have a material adverse +effect on our financial condition. +Any +future failure to maintain effective internal control over financial reporting +and/or effective disclosure controls and procedures could have a material +adverse effect on the reliability of our financial statements and our ability to +file public reports on time, raise capital and meet our debt +obligations. +Our management assessed the +effectiveness of our internal control over financial reporting as of December +31, 2008, and pursuant to this assessment, concluded that we did maintain +effective internal control over financial reporting as of December 31, +2008. However, for each of the years in the three-year period ended +December 31, 2007, management’s assessment of the effectiveness of our internal +control over financial reporting identified several material weaknesses as +disclosed in our Annual Reports on Form 10-K for each of the years in the +three-year period then ended and filed with the SEC on March 20, 2008, May 23, +2007, and May 31, 2006, respectively. The existence of a material +weakness means there is a deficiency, or a combination of deficiencies, in +internal control over financial reporting, such that there is a reasonable +possibility that a material misstatement of our annual or interim financial +statements will not be prevented or detected on a timely basis. +Any future failure to maintain +effective internal control over financial reporting and/or effective disclosure +controls and procedures could prevent us from being able to prevent fraud and/or +provide reliable financial statements and other public reports. Such +circumstances could harm our business and operating results, cause investors to +lose confidence in the accuracy and completeness of our financial statements and +reports, and have a material adverse effect on the trading price of our debt and +equity securities and our ability to raise capital necessary for our +operations. These failures may also adversely affect our ability to +file our periodic reports with the SEC on time. Being late in +filing our periodic reports with the SEC may result in the delisting of our +common stock from the NASDAQ Stock Market or a default under our senior credit +agreement, the indenture governing our outstanding 12% senior notes due 2018, +and any other instruments governing debt that we may incur in the +future. Ultimately, such defaults could lead to the acceleration of +our debt obligations, and if an acceleration of our debt obligations were to +occur, we may not have sufficient funds to repay those obligations immediately, +and we would be forced to seek alternative repayment arrangements either through +a bankruptcy or an out of court debt restructuring. Consequently, a +future material weakness could lead to significant and negative changes to our +financial condition and the value of our equity and debt +securities. +Risks +Associated with Our Indebtedness +Our +credit facility has substantial restrictions and financial covenants and we may +have difficulty obtaining additional credit, which could adversely affect our +operations. Our lenders can unilaterally reduce our borrowing +availability based on anticipated sustained oil and natural gas +prices. +We depend +on our revolving credit facility for future capital needs. The terms +of the borrowing agreement require us to comply with certain financial covenants +and ratios. Our ability to comply with these restrictions and +covenants in the future is uncertain and will be affected by the levels of cash +flows from operations and events or circumstances beyond our +control. Our failure to comply with any of the restrictions and +covenants under the revolving credit facility or other debt financing could +result in a default under those facilities, which could cause all of our +existing indebtedness to be immediately due and payable. +The +revolving credit facility limits the amounts we can borrow to a borrowing base +amount, determined by the lenders in their sole discretion based upon projected +revenues from the natural gas and oil properties securing their +loan. The lenders can unilaterally adjust the borrowing base and the +borrowings permitted to be outstanding under the revolving credit +facility. Outstanding borrowings in excess of the borrowing base must +be repaid immediately, or we must pledge other natural gas and oil properties as +additional collateral. We do not currently have any substantial unpledged +properties, and we may not have the financial resources in the future to make +any mandatory principal prepayments required under the revolving credit +facility. Our inability to borrow additional funds under our credit +facility could adversely affect our operations. +24 +Table of Contents +The +indenture governing our outstanding senior notes and our senior credit agreement +impose (and we anticipate that the indentures governing any other debt +securities we may issue will also impose) restrictions on us that may limit the +discretion of management in operating our business. That, in turn, could impair +our ability to meet our obligations. +The +indenture governing our outstanding senior notes and our senior credit agreement +contain (and we anticipate that the indentures governing any other debt +securities we may issue will also contain) various restrictive covenants that +limit management’s discretion in operating our business. In +particular, these covenants limit our ability to, among other +things: +• incur +additional debt; +• make +certain investments or pay dividends or distributions on our capital stock, or +purchase, redeem or retire capital stock; +• sell +assets, including capital stock of our restricted subsidiaries; +• +restrict dividends or other payments by restricted subsidiaries; +• create +liens; +• enter +into transactions with affiliates; and +• merge +or consolidate with another company. +These +covenants could materially and adversely affect our ability to finance our +future operations or capital needs. Furthermore, they may restrict +our ability to expand, to pursue our business strategies and otherwise conduct +our business. Our ability to comply with these covenants may be +affected by circumstances and events beyond our control, such as prevailing +economic conditions and changes in regulations, and we cannot assure you that we +will be able to comply with them. A breach of any of these covenants +could result in a default under the indenture governing our outstanding senior +notes and any other debt securities we may issue in the future and/or our senior +credit agreement. If there were an event of default under our +indenture and/or the senior credit agreement, the affected creditors could cause +all amounts borrowed under these instruments to be due and payable +immediately. Additionally, if we fail to repay indebtedness under our +senior credit agreement when it becomes due, the lenders under the senior credit +agreement could proceed against the assets which we have pledged to them as +security. Our assets and cash flow might not be sufficient to repay +our outstanding debt in the event of a default. The occurrence of +such an event would adversely affect our operations and +profitability. +Our +senior credit agreement also requires us to maintain specified financial ratios +and satisfy certain financial tests. Our ability to maintain or meet +such financial ratios and tests may be affected by events beyond our control, +including changes in general economic and business conditions, and we cannot +assure you that we will maintain or meet such ratios and tests, or that the +lenders under the senior credit agreement will waive any failure to meet such +ratios or tests. +In +addition, upon a change in control, we are required to offer to buy each senior +note for 101% of the principal amount, plus unpaid interest. A change +in control is defined to include: (i) when a majority of the Board of +Directors are not continuing directors; (ii) when one person (or group of +related persons) holds direct or indirect ownership of over 50% of our voting +stock; or (iii) upon sale, transfer or lease of substantially all of our +assets. +We +may incur additional indebtedness to facilitate our acquisition of additional +properties, which would increase our leverage and could negatively affect our +business or financial condition. +Our +business strategy includes the acquisition of additional properties that we +believe would have a positive effect on our current business and +operations. We expect to continue to pursue acquisitions of such +properties and may incur additional indebtedness to finance the +acquisitions. Our incurrence of additional indebtedness would +increase our leverage and our interest expense, which could have a negative +effect on our business or financial condition. +If +we fail to obtain additional financing, we may be unable to refinance our +existing debt, expand our current operations or acquire new businesses. This +could result in our failure to grow in accordance with our plans, or could +result in defaults in our obligations under our senior credit agreement or the +indenture relating to our outstanding senior notes. +In order +to refinance indebtedness, expand existing operations and acquire additional +businesses or properties, we will require substantial amounts of +capital. There can be no assurance that financing, whether from +equity or debt financings or other sources, will be available or, if available, +will be on terms satisfactory to us. If we are unable to obtain such +financing, we will be unable to acquire additional businesses or properties and +may be unable to meet our obligations under our senior credit agreement and the +indenture relating to our outstanding senior notes or any other debt securities +we may issue in the future. Such an event would adversely affect our +operations and profitability. +ITEM 1B. UNRESOLVED STAFF COMMENTS +None. +25 +Table of Contents +ITEM 2. PROPERTIES +Information +regarding our wells, production, proved reserves and acreage are included in +Item 1 and in Note +1 , Summary of +Significant Accounting Policies , to our consolidated financial statements +included in this report. +Substantially +all of our oil and natural gas properties have been mortgaged or pledged as +security for our credit facility. See Note 6, Long Term Debt , to our +accompanying consolidated financial statements included in this +report. +Facilities +We own +our 32,000 square feet corporate office building located in Bridgeport, West +Virginia. We lease approximately 5,000 and 17,000 square feet of +office space in two buildings near our current corporate office through March +2010 and November 2011, respectively. We lease 15,700 square feet of +office space in downtown Denver, Colorado through March 2012, which effective +March 1, 2009, will become our corporate headquarters. +We own or +lease field operating facilities in the following locations: +· +West +Virginia: Bridgeport, Glenville and West +Union +· +Michigan: Ossineke +· +Colorado: Evans, +Parachute and Wray +· +Pennsylvania: Indiana +and Mahaffey +ITEM 3. LEGAL PROCEEDINGS +Information regarding our legal proceedings can be found in Note 8 , Commitments and Contingencies – +Litigation and Note 17 , Subsequent Events , to our +consolidated financial statements included in this report. +ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY +HOLDERS +None. +PART +II +ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY, +RELATED STOCKHOLDERS MATTERS AND ISSUER PURCHASES OF EQUITY +SECURITIES. +Our +authorized capital stock consists of 100,000,000 shares of common stock, par +value $0.01 per share. Our common stock is traded on the NASDAQ +Global Select Market under the ticker symbol PETD. +26 +Table of Contents +The +following table sets forth the range of high and low sales prices for our common +stock as reported on the NASDAQ Global Select Market for the periods indicated +below. +High +Low +2008 +First +Quarter +$ +73.92 +$ +50.75 +Second +Quarter +79.09 +66.37 +Third +Quarter +68.76 +34.15 +Fourth +Quarter +44.75 +11.50 +2007 +First +Quarter +$ +55.20 +$ +40.53 +Second +Quarter +55.24 +44.59 +Third +Quarter +51.13 +35.73 +Fourth +Quarter +61.91 +41.65 +As of +February 23, 2009, we had approximately 1,107 shareholders of +record. +We +have not paid any dividends on our common stock and currently intend to retain +earnings for use in our business. We do not expect to declare cash +dividends in the foreseeable future. +The +following table presents information about our purchases of our common stock +during the three months ended December 31, 2008. +Period +Total Number of +Shares Purchased (1) +Average Price Paid per +Share +Total Number of +Shares Purchased as Part of Publicly Announced Plans or +Programs +Maximum Number of Shares that May Yet Be Purchased +Under the Plans or Programs +October +1 - 31, 2008 +118 +$ +20.71 +- +- +November +1-30, 2008 +351 +15.74 +- +- +December +1-31, 2008 +827 +24.88 +- +- +Total +fourth quarter purchases +1,296 +22.02 +______________ +(1) +Pursuant +to our stock-based compensation plans, the 1,296 shares purchased +during the quarter represent purchases from our employees for their +payment of tax liabilities related to the vesting of +securities. +On +October 16, 2006, our Board of Directors approved a share purchase program +authorizing us to purchase up to 10% of our then outstanding common stock +(1,477,109 shares) through April 2008. There were 1,465,089 shares +that were authorized but not yet purchased as of December 31, +2007. Total shares purchased in 2008 pursuant to the program were +64,263 common shares at a cost of $4.4 million ($67.97 average price paid per +share), including 63,756 shares from our executive officers at a cost of $4.3 +million ($67.98 price paid per share). Shares purchased from +employees, excluding executive officers, were generally purchased at fair market +value based on the closing price on the date of purchase and were primarily +purchased to satisfy the statutory minimum tax withholding requirement for +restricted stock that vested in 2008. Shares purchased from executive +officers were primarily pursuant to a separation agreement with our former +president and to satisfy the statutory minimum tax withholding requirements for +shares vested in 2008. The authorization to purchase the remaining +1,400,826 shares effectively expired on April 30, 2008. All shares +purchased in accordance with the program have been subsequently +retired. +27 +Table of Contents +SHAREHOLDER +PERFORMANCE GRAPH +The +performance graph below compares the cumulative total return of our common stock +over a five year period ended December 31, 2008, with the cumulative total +returns for the same period for a Standard Industrial Code Index, or SIC, and +the Standard and Poor's, or S&P, 500 Index. The SIC Code Index is +a weighted composite of 158 crude petroleum and natural gas +companies. The cumulative total shareholder return assumes that $100 +was invested, including reinvestment of dividends, if any, in our common stock +on December 31, 2003, and in the S&P 500 Index and the SIC Code Index on the +same date. The results shown in the graph below are not necessarily +indicative of future performance. +Year +Ended December 31, +2003 +2004 +2005 +2006 +2007 +2008 +PETROLEUM +DEVELOPMENT CORPORATION +$ +100 +$ +163 +$ +141 +$ +182 +$ +249 +$ +102 +SIC +CODE INDEX +100 +127 +183 +237 +334 +195 +S&P +500 INDEX +100 +111 +116 +135 +142 +90 +28 +Table of Contents +ITEM 6. SELECTED FINANCIAL DATA +Year +Ended December 31, +2008 +2007 +2006 +2005 +2004 +(in +thousands, except per share data) +Revenues: +Oil +and gas sales +$ +321,877 +$ +175,187 +$ +115,189 +$ +102,559 +$ +69,492 +Sales +from natural gas marketing activities +140,263 +103,624 +131,325 +121,104 +94,627 +Oil +and gas well drilling operations (1) +7,615 +12,154 +17,917 +99,963 +94,076 +Well +operations and pipeline income +11,474 +9,342 +10,704 +8,760 +7,677 +Oil +and gas price risk management gain (loss), net (2) +127,838 +2,756 +9,147 +(9,368 +) +(3,085 +) +Other +293 +2,172 +2,221 +2,180 +1,696 +Total +revenues +609,360 +305,235 +286,503 +325,198 +264,483 +Costs +and expenses: +Oil +and gas production and well operations costs +78,209 +49,264 +29,021 +20,400 +17,713 +Cost +of natural gas marketing activities +139,234 +100,584 +130,150 +119,644 +92,881 +Cost +of oil and gas well drilling operations (1) +2,213 +2,508 +12,617 +88,185 +77,696 +Exploration +expense +45,105 +23,551 +8,131 +11,115 +- +General +and administrative expense +37,715 +30,968 +19,047 +6,960 +4,506 +Depreciation, +depletion and amortization +104,575 +70,844 +33,735 +21,116 +18,156 +Total +costs and expenses +407,051 +277,719 +232,701 +267,420 +210,952 +Gain +on sale of leaseholds (3) +- +33,291 +328,000 +7,669 +- +Income +from operations +202,309 +60,807 +381,802 +65,447 +53,531 +Interest +income +591 +2,662 +8,050 +898 +185 +Interest +expense +(28,132 +) +(9,279 +) +(2,443 +) +(217 +) +(238 +) +Income +before income taxes +174,768 +54,190 +387,409 +66,128 +53,478 +Provision +for income taxes +61,459 +20,981 +149,637 +24,676 +20,250 +Net +income +$ +113,309 +$ +33,209 +$ +237,772 +$ +41,452 +$ +33,228 +Basic +earnings per common share +$ +7.69 +$ +2.25 +$ +15.18 +$ +2.53 +$ +2.05 +Diluted +earnings per share +$ +7.63 +$ +2.24 +$ +15.11 +$ +2.52 +$ +2.00 +As +of December 31, +2008 +2007 +2006 +2005 +2004 +Total +assets +$ +1,402,704 +$ +1,050,479 +$ +884,287 +$ +444,361 +$ +329,453 +Working +capital (deficit) +$ +31,266 +$ +(50,212 +) +$ +29,180 +$ +(16,763 +) +$ +231 +Long-term +debt +$ +394,867 +$ +235,000 +$ +117,000 +$ +24,000 +$ +21,000 +Shareholders' +equity +$ +511,581 +$ +395,526 +$ +360,144 +$ +188,265 +$ +154,021 +______________ +(1) +In +December 2005, we began entering into cost-plus drilling service +arrangements, which are recorded on a net basis unlike our footage based +arrangements which are recorded on a gross basis. See Note 1 , +“Summary of Significant Accounting Policies,” to our accompanying +consolidated financial statements included in this +report. Further, we have not sponsored a drilling program since +August 2007, related revenue continued to be recognized through +2008. +(2) +See +Note 3 , +“Derivative Financial Instruments”, to our accompanying consolidated +financial statements included in this +report. +(3) +In +July 2006, we sold a portion of our undeveloped leasehold located in Grand +Valley Field, Garfield County, Colorado. See Note 13 , “Sale +of Oil and Gas Properties,” to our accompanying consolidated financial +statements included in this +report. +29 +Table of Contents +ITEM 7. MANAGEMENT'S +DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF +OPERATIONS +The +following discussion and analysis, as well as other sections in this Form 10-K, +should be read in conjunction with our accompanying consolidated financial +statements and related notes to consolidated financial statements included in +this report. Further, we encourage you to revisit Special Note Regarding +Forward-Looking Statements on page 1 of this +report. +2008 +Overview +The year +2008 was a year of unprecedented events: oil and natural gas prices soared to +record and near record highs, respectively, through July; then, in the midst of +U.S. credit turmoil and a worldwide economic slump, in December, oil prices fell +to their lowest in four years and natural gas prices dropped almost by +half. Our reaction to these events is one of +caution. While we certainly felt the impact of these events, we +believe that we were successful in managing our operations in such a manner that +we were able to minimize the negative impacts while capitalizing on the positive +impacts. Our strong derivative position eased the impact of the fall +in oil and natural gas prices. We exit 2008 with $7.6 million in net +realized derivative gains, $31.4 million in the fourth quarter +alone. Further, we estimate the net fair value of our derivative +positions, excluding the derivative positions attributed to our affiliated +partnerships, as of December 31, 2008, to be $117.8 million. See +2009 Outlook and Liquidity and Capital +Resources sections below for a discussion of the steps we plan to take in +this uncertain economic environment. +For the +second consecutive year, our net wells drilled increased double digits, up 20.7% +in 2008 from 2007, which was up 100.1% from 2006. The increased +drilling activity was fueled by the July 2006 sale of an undeveloped leasehold +located in Grand Valley Field, Garfield County, Colorado, providing us with cash +proceeds of $353.6 million and our February 2008 senior notes offering with net +proceeds of $196 million. We ended 2008 with interests in 4,712 +gross, 3,259 net, wells located in the Rocky Mountain Region and the Appalachian +and Michigan Basins. In 2008, we recompleted 104 wells in the +Wattenberg Field and 21 wells in the Appalachian Basin. +The +decline in prices during the fourth quarter of 2008 has resulted in $118.4 +million in unrealized gains on derivatives for the year ended December 31, +2008. The $118.4 million in unrealized gains for the year is the fair +value of the derivative positions as of December 31, 2008, less the related +unrealized amounts recorded in prior periods. An unrealized gain is a +non-cash item and there will be further gains or losses as prices decrease or +increase until the positions mature or are closed. While the required +accounting treatment for derivatives that do not qualify for hedge accounting +treatment under SFAS No. 133 may result in significant swings in operating +results over the life of the derivatives, the combination of the settled +derivative contracts and the revenue received from the oil and gas sales at +delivery are expected to result in a more predictable cash flow stream than +would the sales contracts without the associated derivatives. +The +average NYMEX and CIG prices for the next 24 months (forward curve) from the +respective dates below are as follows: +December 31, +June 30, +December 31, +February 13, +Commodity +Index +2007 +2008 +2008 +2009 +Natural +gas: +NYMEX +$ +8.12 +$ +12.52 +$ +6.62 +$ +5.87 +CIG +6.78 +8.86 +4.49 +4.13 +Oil: +NYMEX +90.79 +140.15 +57.49 +53.07 +The +dramatic commodity price declines from June 30, 2008, through December 31, 2008, +relative to our current derivative positions, resulted in the significant +unrealized derivative gains in 2008. If there are further price +declines in 2009, unrealized derivatives gains on our current positions are +expected to continue. +30 +Table of Contents +2009 +Outlook +We +project that our 2009 production will be approximately 44.4 Bcfe or a 15% +increase over 2008 production. Our 2009 capital budget of $120 +million to $140 million represents an approximate 60% decrease compared to +2008. We selected this level of spending with the goal of remaining +debt neutral to help maintain adequate liquidity during 2009. We +realize that oil and gas prices may vary considerably from our +projections. We use oil and natural gas derivatives contracts in +order to reduce the effects of volatile commodity prices. As of +December 31, 2008, we had oil and natural gas hedges in place covering 52% of +our expected oil production and 62% of our expected natural gas production in +2009. +For 2009, +our drilling plans continue to be focused primarily in the Rocky Mountain +Region. We plan to drill approximately 166 gross wells, excluding +exploratory wells, of which 154 are in the Rocky Mountain Region and 12 are in +the Appalachian Basin. We are currently evaluating the exploration +potential of the Marcellus Formation in the Appalachian +Basin. Through a combination of lease, farmout and wellbore +ownership, we operate over 2,100 wells within the Marcellus “Fairway” +area. We currently have three wells drilled, two of which are in +line, and seven additional vertical tests are planned in 2009. +Due to +the continued decline in natural gas prices, in early 2009, we temporarily +ceased all of our drilling operations in the Piceance Basin, resulting in the +demobilization of the three contracted drilling rigs in this area. We +have included in our approved 2009 capital budget $40.4 million for drilling and +completion activities in the Piceance Basin. Should natural gas +prices change materially from the projected levels, we will reevaluate our +drilling options. +Results +of Operations +Summary +Operating Results +The +following table sets forth selected information regarding our results of +operations, including production volumes, oil and gas sales, average sales +prices received, average sales price including realized derivative gains and +losses, average lifting cost, other operating income and expenses for the years +ended December 31, 2008, 2007 and 2006. +31 +Table of Contents +Summary +Operating Results for the +Year Ended December 31, +Change +2008 +2007 +2006 +2008-2007 +2007-2006 +Production (1) +Oil +(Bbls) +1,160,408 +910,052 +631,395 +27.5 +% +44.1 +% +Natural +gas (Mcf) +31,759,792 +22,513,306 +13,160,784 +41.1 +% +71.1 +% +Natural +gas equivalent (Mcfe) (2) +38,722,240 +27,973,618 +16,949,154 +38.4 +% +65.0 +% +Oil and Gas +Sales (in thousands) +Oil +sales +$ +104,168 +$ +55,196 +$ +37,460 +88.7 +% +47.3 +% +Gas +sales +221,734 +119,991 +77,729 +84.8 +% +54.4 +% +Royalty +litigation provision +(4,025) +- +- +* +* +Total +oil and gas sales +$ +321,877 +$ +175,187 +$ +115,189 +86.0 +% +52.1 +% +Realized Gain (Loss) on +Derivatives, net (in thousands) +Oil +derivatives - realized loss +$ +(3,145 +) +$ +(177 +) +$ +- +* +* +Natural +gas derivatives - realized gain +12,632 +7,350 +1,895 +71.9 +% +* +Total +realized gain on derivatives, net +$ +9,487 +$ +7,173 +$ +1,895 +32.3 +% +* +Average +Sales Price +Oil +(per Bbl) (3) +$ +89.77 +$ +60.65 +$ +59.33 +48.0 +% +2.2 +% +Natural +gas (per Mcf) (3) +$ +6.98 +$ +5.33 +$ +5.91 +31.0 +% +-9.8 +% +Natural +gas equivalent (per Mcfe) +$ +8.42 +$ +6.26 +$ +6.80 +34.4 +% +-7.9 +% +Average +Sales Price (including realized gain (loss) on +derivatives) +Oil +(per Bbl) +$ +87.06 +$ +60.46 +$ +59.33 +44.0 +% +1.9 +% +Natural +gas (per Mcf) +$ +7.38 +$ +5.66 +$ +6.05 +30.5 +% +-6.5 +% +Natural +gas equivalent (per Mcfe) +$ +8.66 +$ +6.52 +$ +6.91 +32.9 +% +-5.6 +% +Average Lifting Cost per +Mcfe (4) +$ +1.07 +$ +0.90 +$ +0.76 +18.9 +% +18.4 +% +Other Operating +Income (5) (in +thousands) +Natural +gas marketing activities +$ +1,029 +$ +3,040 +$ +1,175 +-66.2 +% +158.7 +% +Oil +and gas well drilling operations +$ +5,402 +$ +9,646 +$ +5,300 +-44.0 +% +82.0 +% +Costs and Expenses (in +thousands) +Exploration +expense +$ +45,105 +$ +23,551 +$ +8,131 +91.5 +% +189.6 +% +General +and administrative expense +$ +37,715 +$ +30,968 +$ +19,047 +21.8 +% +62.6 +% +Depreciation, +depletion and amortization +$ +104,575 +$ +70,844 +$ +33,735 +47.6 +% +110.0 +% +Interest Expense (in +thousands) +$ +28,132 +$ +9,279 +$ +2,443 +203.2 +% +* +*Percentage +change not meaningful or equal to or greater than +250% +Amounts +may not calculate due to +rounding +_______________ +(1) +Production +is net and determined by multiplying the gross production volume of +properties in which we have an interest by the percentage of the leasehold +or other property interest we own. +(2) +A +ratio of energy content of natural gas and oil (six Mcf of natural gas +equals one Bbl of oil) was used to obtain a conversion factor to convert +oil production into equivalent Mcf of natural +gas. +(3) +We +utilize commodity based derivative instruments to manage a portion of our +exposure to price volatility of our natural gas and oil +sales. This amount excludes realized and unrealized gains and +losses on commodity based derivative +instruments. +(4) +Production +costs represent oil and gas operating expenses which exclude production +taxes. +(5) +Includes +revenues and operating +expenses. +32 +Table of Contents +Oil +and Gas Sales Activity +Oil +and Natural Gas Production and Sales Activity by Area +Year +Ended December 31, +Change +2008 +2007 +2006 +2008-2007 +2007-2006 +Production +Oil +(Bbls) +Appalachian +Basin +6,623 +5,490 +1,837 +20.6 +% +198.9 +% +Michigan +Basin +3,469 +4,301 +4,439 +-19.3 +% +-3.1 +% +Rocky +Mountain Region +1,150,316 +900,261 +625,119 +27.8 +% +44.0 +% +Total +1,160,408 +910,052 +631,395 +27.5 +% +44.1 +% +Natural +gas (Mcf) +Appalachian +Basin +3,902,183 +2,711,300 +1,451,729 +43.9 +% +86.8 +% +Michigan +Basin +1,609,984 +1,678,155 +1,399,852 +-4.1 +% +19.9 +% +Rocky +Mountain Region +26,247,625 +18,123,851 +10,309,203 +44.8 +% +75.8 +% +Total +31,759,792 +22,513,306 +13,160,784 +41.1 +% +71.1 +% +Natural +gas equivalent (Mcfe) +Appalachian +Basin +3,941,921 +2,744,240 +1,462,751 +43.6 +% +87.6 +% +Michigan +Basin +1,630,798 +1,703,961 +1,426,486 +-4.3 +% +19.5 +% +Rocky +Mountain Region +33,149,521 +23,525,417 +14,059,917 +40.9 +% +67.3 +% +Total +38,722,240 +27,973,618 +16,949,154 +38.4 +% +65.0 +% +Average +Sales Price (excluding derivative gains/losses) +Oil +(per Bbl) +Appalachian +Basin +$ +88.80 +$ +59.08 +$ +60.14 +50.3 +% +-1.8 +% +Michigan +Basin +100.79 +68.31 +61.07 +47.5 +% +11.9 +% +Rocky +Mountain Region +89.73 +60.62 +59.31 +48.0 +% +2.2 +% +Weighted +average price +89.77 +60.65 +59.33 +48.0 +% +2.2 +% +Natural +gas (per Mcf) +Appalachian +Basin +$ +9.21 +$ +6.99 +$ +7.37 +31.8 +% +-5.2 +% +Michigan +Basin +8.41 +6.12 +6.53 +37.4 +% +-6.3 +% +Rocky +Mountain Region +6.57 +5.01 +5.62 +31.1 +% +-10.9 +% +Weighted +average price +6.98 +5.33 +5.91 +31.0 +% +-9.8 +% +Natural +gas equivalent (per Mcfe) +Appalachian +Basin +$ +9.24 +$ +7.02 +$ +7.39 +31.6 +% +-5.0 +% +Michigan +Basin +8.52 +6.20 +6.60 +37.4 +% +-6.1 +% +Rocky +Mountain Region +8.32 +6.18 +6.75 +34.6 +% +-8.4 +% +Weighted +average price +8.42 +6.26 +6.80 +34.5 +% +-7.9 +% +Our oil +and natural gas sales revenues have increased in each of the past two years, +primarily due to increased volumes and higher average sales prices in 2008 and +increased volumes partially offset by lower average sales prices in +2007. Increased volumes contributed $90.5 million and $75 million to +the increase in oil and gas sales revenues in 2008 and 2007, +respectively. The increases in oil and natural gas volumes over the +past two years is attributable to the significant increase in the number of +wells drilled for our own account in 2008 and 2007 compared to those drilled in +prior years, and to a lesser extent, the acquisition of producing oil and gas +properties in the fourth quarter of 2006. The production volumes and +oil and gas sales revenue generated in 2007 from the acquisition of oil and gas +properties made in early 2007 and December 2006 and their subsequent development +were 6.5 Bcfe and $45.8 million, respectively. +33 +Table of Contents +Oil and Natural +Gas Pricing. Financial results depend +upon many factors, particularly the price of oil and natural gas and our ability +to market our production effectively. Oil and natural gas prices have +been among the most volatile of all commodity prices. These price +variations have a material impact on our financial results. Oil and +natural gas prices also vary by region and locality, depending upon the distance +to markets, and the supply and demand relationships in that region or +locality. This can be especially true in the Rocky Mountain +Region. The combination of increased drilling activity and the lack +of local markets have resulted in a local market oversupply situation from time +to time. Like most producers in the region, we rely on major +interstate pipeline companies to construct these facilities to increase pipeline +capacity, rendering the timing and availability of these facilities beyond our +control. Oil pricing is also driven strongly by supply and demand +relationships. +The price +we receive for a large portion of the natural gas produced in the Rocky Mountain +Region is based on a market basket of prices, which generally includes gas sold +at CIG prices as well as gas sold at Mid-Continent or other nearby region +prices. The CIG Index, and other indices for production delivered to +other Rocky Mountain pipelines, has historically been less than the price +received for natural gas produced in the eastern regions, which is NYMEX +based. +Although +82.6% of our 2008 natural gas production came from the Rocky Mountain Region, +much of our Rocky Mountain natural gas pricing is based upon other indices in +addition to CIG. The table below identifies the pricing basis of our +oil and natural gas pricing based on sales volumes for the year ended December +31, 2008. The pricing basis is the index that most closely relates to +the price under which our oil and natural gas is sold. +Energy +Market Exposure +as +of December 31, 2008 +Area +Pricing +Basis +Commodity +Percent +of +Oil +and Gas +Sales +Piceance/Wattenberg +Colorado +Interstate Gas (CIG) +Gas +39% +Colorado/North +Dakota +NYMEX +Oil +16% +NECO +Mid +Continent (Panhandle Eastern) +Gas +12% +Piceance +San +Juan Basin/Southern California +Gas +16% +Appalachian +NYMEX +Gas +10% +Michigan +Mich-Con/NYMEX +Gas +4% +Wattenberg +Colorado +Liquids +Gas +2% +Other +Other +Gas/Oil +1% +100% +Lifting +Costs . Lifting costs per +Mcfe , +excluding production taxes which fluctuate with oil and natural gas prices, have +increased approximately 18% annually since 2006, an increase of approximately +41% from 2006 to 2008. The increase is primarily due to general oil +field services and wage inflation pressures. As production volumes +increase when we add new wells, we can expect to see modest decreases in lifting +costs as we work on improving and stabilizing our lifting costs. In +our Rocky Mountain Region, we traditionally experience higher lifting costs due +to severe winter conditions for costs such as snow removal from well and access +roads, along with other weather related problems. +Oil and Gas +Production and Well Operations Costs . In addition to increased +production and the significant number of new wells operated, the increase in oil +and gas production and well operations costs in each of the past two years is +also attributable to additional personnel in the production and engineering +staffs, increased maintenance and operating cost of the new pipeline and +compressor upgrades and improvements, increased production enhancements and +workovers +associated with the early 2007 and December 2006 acquisitions and significant +general oil field services inflation pressures. Oil and gas +production and well operations cost includes our lifting cost, production taxes, +the cost to operate wells and pipelines for our sponsored partnerships and other +third parties (whose income is included in well operations and pipeline income) +and certain production and engineering staff related overhead +costs. In October 2007, in conjunction with the acquisition of oil +and gas properties (762 wells) located in southwestern Pennsylvania, we acquired +a well services operation. The costs related to this operation are +included in the statement of operations line item Oil and Gas Production and well +Operations Costs . +34 +Table of Contents +Oil +and Gas Price Risk Management, Net +Year +Ended December 31, +2008 +2007 +2006 +(in +thousands) +Oil +and gas price risk management, net: +Realized +gain (loss) +Oil +$ +(3,145 +) +$ +(177 +) +$ +- +Natural +gas +12,632 +7,350 +1,895 +Total +realized gain, net +9,487 +7,173 +1,895 +Unrealized +gain (loss), net +118,351 +(4,417 +) +7,252 +$ +127,838 +$ +2,756 +$ +9,147 +Oil and +gas price risk management, net includes realized gains and losses and unrealized +changes in the fair value of oil and natural gas derivatives related to our oil +and natural gas production. Oil and gas price risk management, net +does not include commodity based derivative transactions related to transactions +from natural gas marketing activities, which are included in sales from and cost +of natural gas marketing activities. See Note 2 , Fair Value of Financial +Instruments , and Note 3, Derivative Financial +Instruments , to the accompanying consolidated financial statements for +additional details of our derivative financial instruments. +Oil and +Gas Derivative Activities . We use various +derivative instruments to manage fluctuations in oil and natural gas +prices. We have in place a series of collars, fixed price swaps and +basis swaps on a portion of our oil and natural gas production. Under +the collar arrangements, if the applicable index rises above the ceiling price +or swap, we pay the counterparty; however, if the index drops below the floor or +swap, the counterparty pays us. Our production volumes for the +quarter ended December 31, 2008, were 326,000 Bbls of oil and 9.3 Bcf of natural +gas. +35 +Table of Contents +The +following table identifies our derivative positions (excluding the derivative +positions allocated to our affiliated partnerships) related to oil and gas sales +activities in effect as of December 31, 2008, on our production by +area. No new positions have been entered into subsequent to December +31, 2008, through the date of this filing. +Floors +Ceilings +Swaps +(Fixed Prices) +Basis +Swaps +Commodity/ +Index/ Operating +Area +Quantity +(Gas-MMbtu Oil-Bbls) +Weighted +Average Contract +Price +Quantity +(Gas-MMbtu Oil-Bbls) +Weighted +Average Contract +Price +Quantity +(Gas-MMbtu Oil-Bbls) +Weighted +Average Contract +Price +Quantity +(Gas-MMbtu Oil-Bbls) +Weighted +Average Contract +Price +Fair +Value +a t December 31, +2008 +(in thousands) +Natural +Gas +CIG +Piceance +Basin +1Q +2009 +- +$ +- +- +$ +- +2,388,158 +$ +8.08 +- +$ +- +$ +9,340 +2Q +2009 +2,116,233 +5.75 +2,116,233 +8.90 +- +- +- +- +4,358 +3Q +2009 +2,116,233 +5.75 +2,116,233 +8.90 +- +- +- +- +3,523 +4Q +2009 +1,536,701 +6.70 +1,536,701 +10.25 +584,500 +9.20 +6,490 +2010 +1,672,131 +6.80 +1,672,131 +10.90 +876,751 +9.20 +4,274,703 +1.88 +7,788 +2011 +637,795 +4.75 +637,795 +9.45 +- +- +4,698,955 +1.88 +689 +2012 +- +- +- +- +- +- +4,733,113 +1.88 +(1,907 +) +2013 +- +- +- +- +- +- +4,250,630 +1.88 +(2,846 +) +Wattenberg +Field +1Q +2009 +- +- +- +- +1,702,203 +8.07 +- +- +6,640 +2Q +2009 +1,524,639 +5.75 +1,524,639 +8.89 +- +- +- +- +3,140 +3Q +2009 +1,524,639 +5.75 +1,524,639 +8.89 +- +- +- +- +2,538 +4Q +2009 +1,119,322 +6.71 +1,119,322 +10.26 +424,381 +9.20 +- +- +4,725 +2010 +1,170,071 +6.90 +1,170,071 +10.98 +636,571 +9.20 +2,682,613 +1.88 +5,410 +2011 +380,112 +4.75 +380,112 +9.45 +- +- +2,951,819 +1.88 +429 +2012 +- +- +- +- +- +- +2,953,958 +1.88 +(1,190 +) +2013 +- +- +- +- +- +- +2,637,419 +1.88 +(1,766 +) +PEPL +NECO +1Q +2009 +- +- +- +- +810,000 +8.46 +- +- +3,315 +2Q +2009 +720,000 +6.14 +720,000 +10.81 +- +- +- +- +1,332 +3Q +2009 +720,000 +6.14 +720,000 +10.81 +- +- +- +- +984 +4Q +2009 +580,000 +7.81 +580,000 +12.68 +240,000 +10.91 +- +- +2,669 +2010 +1,410,000 +6.59 +1,410,000 +10.91 +1,060,000 +7.99 +- +- +3,741 +2011 +300,000 +6.00 +300,000 +10.10 +- +- +- +- +92 +NYMEX +Appalachian +and Michigan Basins +1Q +2009 +260,103 +8.40 +260,103 +13.05 +972,279 +9.71 +- +- +4,469 +2Q +2009 +905,212 +7.13 +905,212 +12.85 +429,743 +9.09 +- +- +2,836 +3Q +2009 +905,212 +7.13 +905,212 +12.85 +429,743 +9.09 +- +- +2,625 +4Q +2009 +868,186 +9.00 +868,186 +15.66 +429,457 +9.09 +- +- +3,367 +2010 +1,547,849 +8.22 +1,547,849 +14.19 +1,704,946 +9.08 +- +- +5,968 +2011 +232,277 +6.75 +232,277 +12.13 +800,844 +9.60 +- +- +1,731 +2012 +- +- +- +- +155,211 +9.89 +- +- +306 +Total +Natural Gas +80,796 +Oil +NYMEX +Watenberg +Field +1Q +2009 +- +- +- +- +154,188 +90.52 +- +- +6,428 +2Q +2009 +- +- +- +155,903 +90.52 +- +- +5,729 +3Q +2009 +- +- +- +- +157,615 +90.52 +- +- +5,291 +4Q +2009 +- +- +- +- +157,615 +90.52 +- +- +4,856 +2010 +- +- +- +- +529,664 +92.96 +- +- +14,702 +Total +Oil +37,006 +Total +Natural Gas and Oil +$ +117,802 +36 +Table of Contents +Natural +Gas Marketing Activities +The +increase in sales from natural gas marketing activities in 2008 compared to 2007 +is primarily due to an increase in prices and increased unrealized gains on +derivative instruments. The increase in costs of natural gas +marketing activities in 2008 compared to 2007 is primarily due to an increase in +prices and increased unrealized losses on derivative instruments. +In 2008, +prices on sales and purchases were 31.8% higher on average than in 2007, +resulting in a $27.8 million increase in sales and costs. The sales +related unrealized gain on derivatives increased by $6.4 million and the cost of +sales related unrealized loss on derivatives increased by $6.9 million. Volumes +sold and purchased for resale decreased slightly by 2%. +The +decrease in sales from natural gas marketing activities in 2007 compared to 2006 +is primarily due to a decrease in prices and volumes sold and a decrease in +unrealized gains on derivative instruments. The decrease in costs of +natural gas marketing activities in 2007 compared to 2006 is also due to a +decrease in prices and volumes purchased and a decrease in unrealized losses on +derivative instruments. +In 2007, +prices on sales and purchases were 5% lower on average than in 2006, resulting +in a $5 million decrease in sales and costs. In January 2007, we +acquired all of the outstanding partnership interests in 44 of our sponsored +drilling partnerships. Natural gas sales and purchases related to the +net 423 wells acquired no longer flowed through marketing activities; the result +was a decline in sales from and costs of natural gas marketing activities of +$12.2 million. This decline in partnership volumes was offset by an +increase in non-partnership volumes sold and purchased amounting to $3.7 +million, for a net volume effect of an $8.5 million decrease compared to +2006. The gain on unrealized sales decreased $14 million from a $12.3 +million gain in 2006 to a $1.7 million loss in 2007. The gain on +unrealized costs decreased $13.4 million from an $11.9 million loss in 2006 to a +$1.5 million gain in 2007. +Our +natural gas marketing segment specializes in the purchase, aggregation and sale +of natural gas production in our eastern operating areas. Through our +natural gas marketing segment, we market the natural gas we produce as well as +our purchases of natural gas from other producers in the Appalachian Basin, +including our affiliated partnerships. Our derivative activities +related to natural gas marketing activities include both physical and +cash-settled derivatives. We offer fixed-price derivative contracts +for the purchase or sale of physical gas and enter into cash-settled derivative +positions with counterparties in order to offset those same physical +positions. We do not take speculative positions on commodity +prices. +37 +Table of Contents +Natural Gas Marketing +Derivative Activities . +The +following table identifies our derivative positions related to our gas marketing +activities in effect as of December 31, 2008. +Floors +Ceilings +Swaps +(Fixed Prices) +Basis +Swaps +Commodity/ +Derivative Instrument +Quantity +(Gas-MMbtu Oil-Bbls) +Weighted +Average Contract +Price +Quantity +(Gas-MMbtu Oil-Bbls) +Weighted +Average Contract +Price +Quantity +(Gas-MMbtu Oil-Bbls) +Weighted +Average Contract +Price +Quantity +(Gas-MMbtu Oil-Bbls) +Weighted +Average Contract +Price +Fair +Value +a t December 31, +2008 +(in thousands) +Natural Gas +Physical +Sales +1Q +2009 +20,000 +$ +6.50 +- +$ +- +112,400 +$ +8.59 +290,021 +$ +0.37 +$ +230 +2Q +2009 +- +- +- +- +43,132 +9.20 +72,493 +0.29 +119 +3Q +2009 +- +- +- +- +31,320 +9.55 +66,578 +0.29 +88 +4Q +2009 +- +- +- +- +9,293 +8.36 +38,266 +0.51 +14 +2010 +- +- +- +- +15,610 +8.45 +30,410 +0.80 +19 +Financial +Purchases +1Q +2009 +20,000 +6.50 +- +- +152,400 +7.31 +- +- +(207 +) +2Q +2009 +- +- +- +- +43,132 +8.11 +- +- +(99 +) +3Q +2009 +- +- +- +- +31,191 +8.48 +- +- +(74 +) +4Q +2009 +- +- +- +- +29,293 +10.77 +- +- +(113 +) +2010 +- +- +- +- +45,610 +10.86 +- +- +(157 +) +Financial +Sales +1Q +2009 +- +- +10,000 +10.30 +580,900 +9.13 +226,665 +0.32 +1,879 +2Q +2009 +- +- +- +322,500 +9.27 +211,272 +0.32 +1,116 +3Q +2009 +- +- +- +- +250,500 +9.39 +141,250 +0.32 +812 +4Q +2009 +- +- +- +- +248,500 +8.90 +166,050 +0.32 +540 +2010 +- +- +- +- +695,000 +8.71 +- +- +1,040 +2011 +- +150,000 +8.44 +- +- +125 +Physical +Purchases +1Q +2009 +- +- +10,000 +10.30 +581,395 +9.29 +46,935 +0.32 +(1,762 +) +2Q +2009 +- +- +- +- +322,995 +9.44 +46,874 +0.32 +(1,079 +) +3Q +2009 +- +- +- +- +250,995 +9.56 +46,752 +0.32 +(788 +) +4Q +2009 +- +- +- +- +228,665 +9.60 +15,584 +0.32 +(597 +) +2010 +- +- +- +- +665,000 +9.14 +- +- +(1,146 +) +2011 +- +- +- +- +150,000 +8.61 +- +- +(125 +) +Total +Natural Gas +$ +(165 +) +Oil +and Gas Well Drilling +The +decrease in oil and gas well drilling operations revenue was due to our decision +not to sponsor a drilling partnership in 2008 and our change from footage-based +drilling arrangements to cost-plus drilling arrangements, which have differing +revenue recognition presentations. +In +January 2008, we announced that we did not plan to sponsor new drilling +partnerships in 2008. In August 2007, we completed our only sponsored +drilling partnership offering in 2007. Drilling for the partnership +commenced during the third quarter of 2007. From inception to +December 31, 2008, $12.7 million in revenues had been recognized related to the +2007 drilling program. Advances for future drilling contracts held as +of December 31, 2008, will be used for completion activities to be conducted in +2009. Currently, we do not plan to sponsor a drilling partnership in +2009 or in the foreseeable future. Consequently, we anticipate that our oil and +gas drilling segment’s contribution to operating income, which was $5.4 million, +$9.6 million and $5.3 million in 2008, 2007 and 2006, respectively, will decline +substantially in 2009. Thereafter, our oil and gas well drilling +contribution to operating income will cease unless we undertake new drilling +ventures. +Beginning +with the last sponsored partnership in 2005 (for which revenue generating +activities began in 2006), our partnership wells have been drilled on a +“cost-plus” basis, which means that we charge the partnerships for the actual +cost of the wells plus an agreed upon mark-up above that cost. Prior +to that partnership, we had conducted most of our third-party drilling +activities on a footage basis, pursuant to which we drilled the wells for a +fixed price per foot drilled with additional chargeable items as provided for in +the drilling agreement. Our services provided under the cost-plus +drilling arrangements are reported net of recovered costs and reflected as +revenue in oil and gas well drilling operations, whereas the revenues under the +footage-based arrangements were recorded gross of related +expenses. For the year ended December 31, 2006, the oil and gas well +drilling segment’s results included $5.4 million in revenues and $10 million in +expenses related to footage based arrangements. +38 +Table of Contents +Well +Operations and Pipeline Income +In +January 2007, we acquired all of the outstanding partnership interests in 44 of +our sponsored drilling partnerships. Having acquired 423 net wells +pursuant to the acquisition, we no longer record income for operating these +wells and related pipelines. This decrease in revenue was offset in +part by an increase in the number of new wells drilled and placed in service and +pipeline systems we operate for our sponsored drilling partnerships as well as +third parties. In October 2007, in conjunction with the acquisition +of oil and gas properties located in southwestern Pennsylvania, we acquired a +well services operation. The revenues related to this operation are +included in the statement of operations line item Well Operations and Pipeline +Income . +Gain +on Sale of Leaseholds +In July +2006, we entered into a purchase and sale agreement with an unaffiliated party +regarding the sale of our undeveloped leasehold located in the Grand Valley +Field, Garfield County, Colorado, as filed with the Securities and Exchange +Commission, or SEC, as Exhibit 10.3 to Form 10-Q for the period ended September +30, 2006. Total proceeds from the sale were $353.6 million, of which +we recognized a $328 million gain on sale of leasehold in the third quarter of +2006. +In +May 2007, we entered into a letter agreement amending the above +mentioned purchase and sale agreement, relieving us of our obligation, in its +entirety, to either drill 16 wells or pay liquidated damages of $1.6 million per +undrilled well. As a result, we recognized the remaining deferred +gain of $25.6 million in the second quarter of 2007. +In +December 2007, we sold to the same unaffiliated party a portion of our North +Dakota properties for approximately $34.7 million. The properties, +located in Dunn, Williams and McKenzie Counties, North Dakota, include interests +in five producing Bakken wells and approximately 72,000 net undeveloped +acres. We recorded a gain on sale of leaseholds of $7.7 million in +the fourth quarter of 2007. +Other +Costs and Expenses +Exploration +Expense +The +following table sets forth the major components of exploration +expense. +Year +Ended December 31, +2008 +2007 +2006 +(in +thousands) +Impairment +of proved oil and gas properties +$ +12,825 +$ +- +$ +1,510 +Amortization/impairment +of unproved properties +12,798 +3,291 +1,010 +Exploratory +dry holes +7,675 +4,187 +1,790 +Geological +and geophysical costs +2,121 +6,299 +2,234 +35,419 +13,777 +6,544 +Operating +and other +9,686 +9,774 +1,587 +Total +exploration expense +$ +45,105 +$ +23,551 +$ +8,131 +We +expanded exploratory drilling activities in 2005 and have generally believed +that the additional risk and costs associated with exploratory drilling is +justified by the potential to generate additional proved +properties. However, we plan to reduce exploratory drilling in 2009 +given the current economic conditions and focus primarily on development +activities in our proven fields. +We assess +our proved oil and gas properties for possible impairment by comparing net +capitalized costs to estimated undiscounted future net cash flows on a +field-by-field basis using estimated production based upon prices at which we +reasonably estimate the commodity to be sold. If net capitalized +costs exceed undiscounted future net cash flows, the measurement of impairment +is based on estimated fair value which would consider future discounted cash +flows. We assess our unproved oil and gas properties for possible +impairment by field based on our historical experience, current market data, +acquisition dates, average lease terms and the probability of being +drilled. +39 +Table of Contents +We +recognized impairment losses on proved oil and gas properties of $12.8 million +in 2008, consisting of $7.5 million related to our properties in the Fort Worth +Basin, $3 million in our Bakken Field in North Dakota and $2.3 million in our +Nesson Field, also in North Dakota. We also recognized +impairment losses of unproved properties of $12.9 million, consisting primarily +of $7.3 million related to our unproved properties in the Fort Worth Basin and +amortization of approximately $5.6 million related to all of our other areas of +operations. The $7.7 million of exploratory dry holes relates +primarily to two Michigan wells, one New York well and one Colorado +well. +In 2007, +exploration expense includes $2.7 million of liquidated damages associated with +the abandonment of an exploration agreement with an unaffiliated party and $1.1 +million related to the write-off of the carrying value of the related acreage, +$6.3 million in geological and geophysical costs related to seismic evaluation +of various exploratory prospects and increased payroll and payroll related costs +and other exploratory department costs. +In 2006, +exploration expense includes $1.8 million related to one exploratory dry hole, +$1.5 million related to an impairment charge on our Nesson Field in North Dakota +and $2.2 million in geological and geophysical costs related to the seismic +evaluation of our Northeast Colorado properties. +General +and Administrative Expense +General +and administrative expense has increased for the third consecutive +year. However, 2008 is considered pivotal because the rate of +increase is declining and we expect this trend to continue in +2009. It is this trend that we expect to continue in +2009. General and administrative expenses have been declining on a +per Mcfe basis, from $1.12 per Mcfe in 2006 to $1.11 per Mcfe in 2007 and $0.97 +per Mcfe in 2008. +The +increase in general and administrative expense in 2008 compared to 2007 was +primarily due to increased payroll and payroll related expenses, which includes +$4.7 million related to agreements with two former executive officers: $3.2 +million related to a separation agreement with our former president and $1.5 +million related to an agreement for the retirement of our former chief executive +officer. This increase was partially offset by a $2 million decrease +in audit fees and a decrease in various other general and administrative +expenses. +The +increase in general and administrative expense in 2007 compared to 2006 was +primarily due to increased costs related to increased payroll and payroll +related expenses, which includes stock-based compensation expense related to the +recruitment of professionals and key personnel in 2007. The increase +in management personnel is attributable to the growth we are experiencing, the +increase in the cost of recruiting and the higher compensation required to +obtain experienced oil and gas personnel. We also experienced higher +financial statement audit costs related to the late filing of our 2006 Form +10-K, higher compliance costs with the various provisions of the Sarbanes-Oxley +Act, increased accounting assistance from third party consulting services and +increased legal costs. +Depreciation, +Depletion and Amortization +DD&A expense +includes depreciation and amortization expense related of non-oil and natural +gas properties as well as oil and natural gas properties. DD&A +expense for non-oil and natural gas properties was $7.6 million, $4.3 million +and $2 million in 2008, 2007 and 2006, respectively. DD&A expense +related to oil and natural gas properties is directly related to reserves and +production volumes. DD&A expense is primarily based upon year-end +proved developed producing oil and gas reserves. These reserves are +priced at the price of oil and natural gas as of December 31 each +year. If prices increase, the corresponding volume of oil and gas +reserves will increase, resulting in decreases in the rate of DD&A per unit +of production. If prices decrease, as they did from 2007 to 2008, +volumes of oil and gas reserves will decrease resulting in increases in the rate +of DD&A per unit of production. See Note 18 , Supplemental Oil and Gas Information +– Unaudited , to our accompanying consolidated financial statements, for +the average December 31 oil and natural gas prices used to determine year-end +reserves and other reserve information. The cost to acquire acreage, +drill, complete and equip new wells have risen significantly over the past five +years along with oil and natural gas prices and is a major contributing factor +for the increased DD&A rate in the table below: +40 +Table of Contents +DD&A +rates for our oil and gas properties are shown in the table below. +Year +Ended December 31, +2008 +2007 +2006 +(per +Mcfe) +Appalachian +Basin (1) +$ +1.55 +$ +1.32 +$ +1.13 +Michigan +Basin +1.35 +1.28 +0.83 +Rocky +Mountain Region: +Wattenberg +Field +(2) +3.47 +2.99 +2.34 +Piceance +Basin (3) +2.04 +2.27 +1.83 +NECO +1.45 +1.45 +1.26 +Weighted +average +2.51 +2.37 +1.87 +______________ +(1) +The +increase in DD&A rate for the Appalachian Basin in 2008 was due to the +higher market price of a fourth quarter 2007 acquisition of 752 wells in +southwestern Pennsylvania and the new wells drilled in +2008. +(2) +Although +the Wattenberg Field development costs and DD&A rates are higher than +the other fields, the relative value of its oil production currently more +than offsets this cost difference. The Wattenberg Field has +produced volumes in excess of 85% of our total oil production in each of +the years in the three-year period ended December 31, +2008. +(3) +The +decrease in DD&A rates for the Piceance Basin in 2008 compared to 2007 +is the result of higher year-end 2008 oil and natural gas reserves, due +primarily to the improvements in drilling and completion technology and +expanded pipeline and compression +capacity. +Non-Operating +Income/Expense +Interest +Income . The decreases in our interest income in 2008 and 2007 +were the result of lower cash balances earning interest compared to +2006. In July 2006, we received $353.6 million in cash proceeds from +the sale of undeveloped leaseholds. These proceeds earned interest +income until reinvested in oil and gas properties in January 2007. +Interest +Expense . The increases in our interest expense were primarily +due to significantly higher average outstanding balances of our credit facility +and, in 2008, our 12% senior notes offset in part by lower average interest +rates in our bank credit facility. The average long-term debt in 2008 +was $275.9 million compared to $132.5 million in +2007. Interest expense is net of capitalized +interest. Interest costs capitalized in 2008, 2007 and 2006 were $2.6 +million, $3 million and $1.6 million, respectively. We have +historically utilized our daily cash balances to reduce our line of credit +borrowings, thereby lowering our interest costs. +Provision +for Income Taxes +Our 2008 +effective income tax rate was 35.2% in 2008 compared to 38.7% in 2007 and 38.6% +in 2006. This reduced rate reflects second and third quarter discrete +benefits of $1.4 million for each period, related principally to the +implementation of state tax strategies during each respective +quarter. The impact of these strategies also affected our rate used +to establish deferred taxes and resulted in a deferred tax benefit of $1 million +in 2008. +Our +effective tax rate, excluding the effect of discrete items, for 2008 was 37.3%, +which was virtually unchanged from 2007 and slightly less than the 2006 rate of +38.4%. In 2008, the rate decreased primarily due to a 0.5% reduction +in our effective state tax rate due to the benefit being realized from our +implemented state tax planning strategies and a 0.7% reduction primarily related +to reduced tax penalties. However, these 2008 rate decreases were +offset by our permanent tax deductions resulting in a proportionately smaller +effective rate benefit of 0.8% compared to 1.8% in 2007. In 2006, our +permanent tax deduction for percentage depletion resulted in a proportionately +smaller tax rate benefit of only 0.1%. +41 +Table of Contents +Liquidity +and Capital Resources +Cash flow +from operations and our bank credit facility are the primary sources of +liquidity for us to satisfy our operating expenses and fund our capital +expenditures. We had $180.5 million of available borrowing capacity +under our $375 million bank credit facility as of December 31, +2008. Cash provided by operating activities was $139.1 million for +the current year period compared to $60.3 million in the prior year +period. The $78.8 million increase in the current year period was +primarily due to higher natural gas and oil prices through mid-2008 and higher +volumes of oil and natural gas production and realized derivative gains +primarily in the fourth quarter of 2008. Changes in cash flow from +operations are largely due to the same factors that affect our net income, +excluding non-cash items which are primarily depreciation, depletion and +amortization and unrealized gains and losses on derivative +transactions. See the discussion under Results of +Operations . Cash flow used in investing activities increased +$55.6 million, or 21%, from $267.4 million for the year ended 2007 to $323 +million in 2008. Substantially all of our investing activity involved +drilling for oil and gas reserves during 2008. Cash flows provided +from financing activities increased $52.6 million, or 54%, from $97.5 million to +$150.1 million for the years ended December 31, 2007 and 2008, +respectively. This increase was primarily due to the increase in +proceeds from the issuance of our 12% senior notes of $200 million offset by net +repayments on our bank credit facility. +Changes +in market prices for oil and natural gas, our ability to increase production, +the impact of realized gains and losses on our oil and natural gas derivative +instruments and changes in costs are the principal determinants of the level of +our cash flow from operations. Oil and natural gas sales for the year +ended December 31, 2008, were approximately 85% higher than the prior year, +resulting from a 34% increase in average oil and natural gas prices and a 38% +increase in oil and natural gas production. While a decline in oil +and natural gas prices would affect the amount of cash from operations that +would be generated, we have oil and natural gas derivative positions in place, +as of the date of this filing, covering 52% of our expected oil production and +62% of our expected natural gas production in 2009, at average prices of $90.52 +per Bbl and $7.25 per Mcf, respectively. These contracts reduce the +impact of price changes for a substantial portion of our 2009 cash from +operations. +Our +primary use of funds is for capital expenditures. As a result of the +current unstable conditions in the commodity and financial markets, we have +significantly reduced our planned 2009 capital expenditures to a range of $120 +million to $140 million which represents an approximate 60% decrease from our +2008 capital expenditures. With this reduction, we estimate our 2009 +production will increase by approximately 15% over 2008 in part due to increased +production from wells drilled in the latter part of 2008. We believe, +based on the current commodity price environment, our cash flow from operations +will fund our reduced 2009 capital spending program allowing us to remain debt +neutral during 2009. We expect to manage capital expenditures within +our cash flow from operations in 2009 and for the foreseeable future until +commodity prices and capital markets are more favorable. In order to +continue to maintain or grow our production, we will need to commit greater +amounts of capital in 2010 and beyond. If capital is not available or +is constrained in the future, we will be limited to our cash flow from +operations and liquidity under our credit facility as the sources of funding for +our capital expenditures. Oil and gas produced from our existing +properties declines rapidly in the first two years of production. We +could not maintain our current level of oil and gas production and cash flow +from operations if capital markets and commodity prices remain in their current +depressed state for a prolonged period beyond 2009, which would have a material +negative impact on our operations in 2010 and beyond. +We +considered the possibility of a reduced available liquidity environment in +planning our 2009 drilling program and believe we will have adequate cash flow +from operations during the year to execute our planned capital expenditures +without drawing additional funds from our credit facility. Currently, +we operate approximately 95% of our properties, allowing us to control the pace +of substantially all of our planned capital +expenditures. Consequently, a substantial portion of our planned +capital expenditures for 2009 and beyond could be deferred if market conditions +worsen. +In +addition to deferring capital expenditures to reduce borrowings under our credit +facility, other sources of liquidity include the fair value of our oil and +natural gas derivative positions, excluding the derivative positions attributed +to our affiliated partnerships, of $117.8 million as well as our available cash +balance which was $51 million as of December 31, 2008. +We have +one significant future drilling commitment along with certain volume delivery +requirements that will require us to expend $60 million in development drilling +on our Wattenberg leases through 2011, provided that our counterparty in the +agreement expands two gas processing facilities and maintains certain wellhead +pressures by June 30, 2010. Our 2009 capital expenditure plan +includes approximately $50 million related to this +commitment. Failure to meet our drilling commitment would result in a +maximum payment to the counterparty of $15 million in 2012; failure to meet our +volume delivery commitments by December 31, 2012, would result in a maximum +payment to the counterparty of $10 million in 2013. Failure of the +counterparty to complete the required plant expansions results in a waiver of +our $60 million capital and volume delivery requirements. +42 +Table of Contents +We have +experienced no impediments in our ability to access borrowings under our current +bank credit facility. We continue to monitor market events and circumstances and +their potential impacts on each of the thirteen lenders that comprise our bank +credit facility. Our $375 million bank credit facility borrowing base +is subject to size redeterminations each April and October based upon a +quantification of our proved reserves at each December 31st +and June 30th, respectively. A commodity price deck reflective of the +current and future commodity pricing environment is utilized by our lenders to +quantify our reserve reports and determine the underlying borrowing +base. We will be subject to a borrowing base redetermination in April +2009. +We +increased our borrowing base in July 2008, and again in November 2008, to $300 +million and $375 million respectively. The increases were driven +primarily by increases in proved producing reserves from drilling +operations. While we have continued to add producing reserves since +our November 2008 redetermination, we believe the significant decrease in +commodity prices and turmoil in the credit markets could have a negative impact +on our borrowing base at our next redetermination in April 2009. Our +credit facility matures in November 2010, and is payable in full at that +time. We have begun discussions with our bank group with the intent +of renewing the credit facility prior to November 1, 2009. There is +no assurance all of the lenders in our credit facility will participate in the +renewal and there is no assurance that our borrowing base will not be reduced +from its current level as a result of the renewal or the loss of one or more +lenders in our credit facility. Further, costs of capital have +increased since we last amended our credit facility and we expect that interest +and commitment fees under a new facility will be higher than in our current +credit facility. See Note 6 , Long Term Debt , to the +accompanying consolidated financial statements. At December 31, 2008, +we had $180.5 million available for borrowing under our $375 million credit +facility. While we believe our borrowing base could be reduced as a +result of redeterminations, we believe that producing reserves added since our +last redetermination and our oil and natural gas derivative positions in place +could mitigate the risk of a significant decrease in our borrowing base in +2009. We also believe that while costs of capital have increased for +credit facilities like ours, the impact of an increase in interest and +commitment fees on our outstanding balance and commitments will not have a +material adverse effect on our liquidity in 2009. Our credit facility +matures in November 2010. If economic conditions deteriorate further +in 2009 and 2010, our ability to renew our credit facility and provide adequate +liquidity to continue our drilling programs could be negatively impacted in 2010 +and beyond. +We are +subject to quarterly financial debt covenants on our bank credit +facility. Our key credit facility debt covenants require that we +maintain: 1) total debt of less than 3.75 times earnings before interest, taxes, +depreciation, amortization and capital expenditures (“EBITDAX”) and 2) an +adjusted working capital ratio of at least 1.0 to 1.0. As of December +31, 2008, our total debt was 1.5 times EBITDAX and our adjusted working capital +ratio was 1.6 to +1.0. Our adjusted working capital ratio is calculated by reducing our +current assets and liabilities by any impact of recording the fair value of our +oil and gas derivative instruments and adding our available borrowings on our +bank credit facilities to our current assets. In addition, the impact +of any current portion of our debt is eliminated from the current +liabilities. Therefore, any change in our available borrowings under +our credit facility impacts our working capital ratio. +We +believe we have sufficient liquidity and capital resources to conduct our +business and remain compliant with our debt covenants throughout 2009 based upon +our 2009 cash flow projections, anticipated capital requirements, the +discretionary nature of our capital expenditures and available capacity under +our bank credit facility. While current conditions in the financial +markets are extremely difficult and illiquid, we have no current plans or +requirements to raise capital through these markets. However, we cannot predict +with any certainty the impact to our future business of any further disruption +or deterioration in the financial markets. We will continue to +closely monitor our liquidity and the credit markets and may choose to access +them opportunistically should conditions and capital market liquidity +improve. +We filed +a shelf registration statement on Form S-3 with the SEC on November 26, 2008. +The shelf provides for an aggregate of $500 million, through the sale of debt +securities, common stock or preferred stock, either separately or represented by +depository shares, warrants and purchase contracts, as well as units that may +include any of these securities or securities of other entities. The +shelf registration statement is intended to allow the Company to be proactive in +its ability to raise capital should the need arise, and to have the flexibility +to raise such funds in one or more offerings, subject to market +conditions. This shelf registration statement was declared effective +by the SEC on January 30, 2009. There are no immediate plans to raise +any funds and there is no assurance that we will be able to secure any such +funds should the need arise. +See Item +7A, Quantitative and +Qualitative Disclosure about Market Risk , for our discussion of credit +risk. +Contractual +Obligations and Contingent Commitments +The table +below sets forth our contractual obligations and contingent commitments as of +December 31, 2008: +Payments +due by period +Contractual +Obligations and Contingent Commitments (1) +Total +Less +than +1 +year +1-3 +years +3-5 +years +More +than +5 +years +(in +thousands) +Long-Term +Debt (2) +$ +394,867 +$ +- +$ +194,500 +$ +- +$ +200,367 +Interest on +long-term debt (2) +238,955 +33,398 +56,352 +73,080 +76,125 +Operating +leases +5,840 +2,687 +2,726 +383 +44 +Asset +retirement obligations +23,086 +50 +100 +100 +22,836 +Rig +commitments (3) +15,859 +12,091 +3,768 +- +- +Capital +expenditure commitments (4) +71,800 +- +70,000 +- +1,800 +Derivative +contracts (5) +10,486 +4,766 +(6,197 +) +11,917 +- +Partnership +derivative contracts (6) +13,944 +3,808 +10,136 +- +- +Production +tax liability +43,948 +18,226 +25,722 +- +- +Firm +transportation, sales and processing agreements (7) +217,495 +8,391 +37,490 +50,333 +121,281 +Other +liabilities (8) +8,380 +446 +1,240 +1,240 +5,454 +Total +$ +1,044,660 +$ +83,863 +$ +395,837 +$ +137,053 +$ +427,907 +43 +Table of Contents +__________ +(1) +Table +does not include deferred income tax obligations to taxing authorities of +$190.9 million and maximum annual repurchase obligations to investing +partners of $15.9 million as of December 31, 2008 due to the uncertainty +surrounding the ultimate settlement of amounts and timing of these +obligations. +(2) +Amounts +presented for long term debt consist of amounts related to our 12% senior +notes and our outstanding credit facility. The interest on long term debt +includes $222.3 million payable to the holders of our 12% senior notes and +$16.7 million related to our outstanding balance of $194.5 million on our +credit facility as of December 31, 2008, based on an imputed interest rate +of 4.65%. +(3) +Drilling rig commitments in +the above table reflect our maximum obligation and does not include future +adjustments to daily rates as provided for in the agreements as such +increases are not predictable and are only included in the above +obligation table upon notification to us by the contractor of an increase +in the rate . Further, our rig commitment +above includes $5.1 million related to a rig sublet to a third party and +remains our obligation should the third party default on terms of the +sublet agreement. +(4) +Primarily +represents our capital expenditure commitment related to certain drilling +and development agreements. See Note 8 , +Commitments and Contingencies, to our accompanying consolidated financial +statements. These amounts do not include advances for future +drilling contracts totaling $1.7 million at December 31, +2008. +(5) +Represents +our gross liability related to the fair value of derivative positions, +including the fair value of derivative contracts we entered into on behalf +of our affiliated partnerships as the managing general +partner. We have a related receivable from the partnerships of +$1.6 million as of December 31, +2008. +(6) +Represents +our affiliated partnerships’ share of the fair value of our gross +derivative assets at December 31, +2008. +(7) +Represents +our gross commitment, including amounts for volumes transported or +sold on behalf of our affiliated partnerships and other working interest +owners. We will recognize in our financial statements our +proportionate share based on our working and net revenue +interest. +(8) +Includes +funds held from revenue distribution to third party investors for plugging +liabilities related to wells we operate and deferred officer +compensation. +As +managing general partner of 33 partnerships ( see Item 1 . +Business – Drilling and +Development Conducted for Company Sponsored Partnerships) , we have +liability for any potential casualty losses in excess of the partnership assets +and insurance. We believe that the casualty insurance coverage +we and our subcontractors carry is adequate to meet this potential +liability. +For +information regarding our legal proceedings, see Note ­8 , Commitments and Contingencies – +Litigation, and Note 17 , Subsequent Events , to our +accompanying consolidated financial statements included in this +report. From time to time we are a party to various other legal +proceedings in the ordinary course of business. We are not currently +a party to any litigation that we believe would have a materially adverse affect +on our business, financial condition, results of operations, or +liquidity. +Critical +Accounting Policies and Estimates +We +have identified the following policies as critical to business operations and +the understanding of our results of operations. This is not a +comprehensive list of all of the accounting policies. In many cases, +the accounting treatment of a particular transaction is specifically dictated by +accounting principles generally accepted in the U.S., with no need for our +judgment in the application. There are also areas in which our +judgment in selecting any available alternative would not produce a materially +different result. However, certain of our accounting policies are +particularly important to the portrayal of our financial position and results of +operations and we may use significant judgment in the application; as a result, +they are subject to an inherent degree of uncertainty. In applying +those policies, we use our judgment to determine the appropriate assumptions to +be used in the determination of certain estimates. Those estimates +are based on historical experience, observation of trends in the industry, and +information available from other outside sources, as appropriate. For +a more detailed discussion on the application of these and other accounting +policies, see Note +1 , Summary of +Significant Accounting Policies , to our accompanying consolidated +financial statements. Our critical accounting policies and estimates +are as follows: +Revenue +Recognition +Oil and natural gas +sales . Sales of oil are recognized when persuasive evidence of +a sales arrangement exists, the oil is verified as produced and is delivered to +a purchaser, collection of revenue from the sale is reasonably assured and the +sales price is determinable. We are currently able to sell all the +oil that we can produce under existing sales contracts with petroleum refiners +and marketers. We do not refine any of our oil +production. Our crude oil production is sold to purchasers at or near +our wells under short-term purchase contracts at prices and in accordance with +arrangements that are customary in the oil industry. +Sales of +natural gas are recognized when natural gas has been delivered to a custody +transfer point, persuasive evidence of a sales arrangement exists, the rights +and responsibility of ownership pass to the purchaser upon delivery, collection +of revenue from the sale is reasonably assured and the sales price is fixed or +determinable. Natural gas is sold by us under contracts with terms +ranging from one month to three years. Virtually all of our contract +pricing provisions are tied to a market index, with certain adjustments based +on, among other factors, whether a well delivers to a gathering or transmission +line, quality of natural gas and prevailing supply and demand conditions, so +that the price of the natural gas fluctuates to remain competitive with other +available natural gas supplies. As a result, our revenues from the +sale of natural gas will suffer if market prices decline and benefit if they +increase. We believe that the pricing provisions of our natural gas +contracts are customary in the industry. +44 +Table of Contents +We +currently use the “net-back” method of accounting for transportation +arrangements of natural gas sales. We sell gas at the wellhead and +collect a price and recognize revenues based on the wellhead sales price since +transportation costs downstream of the wellhead are incurred by our customers +and reflected in the wellhead price. +Natural gas marketing +activities . Natural gas marketing is reported on the gross +accounting method, based on the nature of the agreements between RNG, our +suppliers and our customers. RNG, our marketing subsidiary, purchases +gas from PDC and other small producers and bundles the gas together to sell in +larger amounts to purchasers of natural gas for a price +advantage. RNG has latitude in establishing price and discretion in +supplier and purchaser selection. Natural gas marketing revenues and +expenses reflect the full cost and revenue of those transactions because RNG +takes title to the gas it purchases from the various producers and bears the +risks and rewards of that ownership. Both the realized and unrealized +gains and losses of the RNG commodity based derivative transactions for natural +gas marketing activities are included in gas sales from marketing activities or +cost of gas marketing activities, as applicable. +Oil and gas well drilling +operations . Our drilling segment recognizes revenue from +drilling contracts with sponsored drilling programs using the percentage of +completion method based upon the percentage of contract costs incurred to date +to the estimated total contract costs for each contract. We utilize +this method since reasonably dependable estimates of the total estimated costs +can be made and recognized revenues are subject to revisions as a contract +progresses, the term of which can range from three to twelve +months. We have offered our drilling services under two types of +contractual arrangements, cost-plus or footage-based service contracts, which +result in differing risk and reward relationships and, consequently, different +revenue reporting policies pursuant to Emerging Issues Task Force, or EITF, +Issue No. 99-19, Reporting +Revenue Gross as a Principal versus Net as an Agent . +The first +cost-plus drilling service arrangement was entered into in late 2005 with +drilling activity commencing in the first quarter of 2006. Due to the +fixed-fee-percentage nature of our revenues from these services, we have +determined that, in substance, we are acting as an agent, without risk of loss +during the performance of the drilling activities. Accordingly, our +services provided under the cost-plus drilling agreements are reported on a net +basis. We entered into our second and third cost-plus drilling +arrangements in September 2006 and August 2007 and commenced drilling +immediately. Footage-based contracts provide for the drilling, +completion and equipping of wells at footage rates and are generally completed +within nine to twelve months after the commencement of drilling. We +provide geological, engineering, and drilling supervision on the drilling and +completion process and use subcontractors to perform drilling and completion +services at a fixed footage-based rate and accordingly have the risk of loss in +performing services under these arrangements. Accordingly, we report +revenue under these agreements gross of related expenses. Anticipated +losses, if any, on uncompleted contracts are recorded at the time that the +estimated total costs exceed the estimated total contract revenue. At +December 31, 2007, we had recorded a loss contract reserve of $0.2 +million. There was no loss contract reserve as of December 31, +2008 . +Well operations and pipeline +income . Well operations and pipeline income are recognized +when persuasive evidence of an arrangement exists, services have been rendered, +collection of revenues is reasonably assured and the sales price is fixed or +determinable. We are paid a monthly operating fee for each well we +operate for outside owners including the limited partnerships we +sponsor. The fee covers monthly operating and accounting costs, +insurance and other recurring costs. We may also receive additional +compensation for special non-recurring activities, such as reworks and +recompletions. +Fair +Value of Financial Instruments +We +adopted the provisions of Statement of SFAS No. 157, Fair Value Measurements, +effective January 1, 2008. SFAS No. 157 defines fair value, +establishes a framework for measuring fair value and expands disclosures related +to fair value measurements. SFAS No. 157 applies broadly to financial and +nonfinancial assets and liabilities that are measured at fair value under other +authoritative accounting pronouncements, but does not expand the application of +fair value accounting to any new circumstances. In February 2008, the +Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“FSP”) +FAS No. 157-2, Effective Date of FASB Statement No. 157, which delays the +effective date of SFAS No. 157 by one year (to January 1, 2009) for nonfinancial +assets and liabilities, except those that are recognized or disclosed at fair +value in the financial statements on a recurring basis (at least +annually). Nonfinancial assets and liabilities for which we have not +applied the provisions of SFAS No. 157 include those initially measured at fair +value, including our asset retirement. +Derivative Financial +Instruments . +We use +derivative instruments to manage our commodity and financial market +risks. We currently do not use hedge accounting treatment for our +derivatives. Derivatives are reported on our accompanying +consolidated balance sheets at fair value on a gross asset and liability +basis. Changes in fair value of derivatives are recorded in oil and +gas price risk management, net, in our accompanying consolidated statements of +income. +SFAS No. +157 establishes a fair value hierarchy that requires an entity to maximize the +use of observable inputs and minimize the use of unobservable inputs when +measuring fair value. The valuation hierarchy is based upon the +transparency of inputs to the valuation of an asset or liability as of the +measurement date, giving the highest priority to quoted prices in active markets +(Level 1) and the lowest priority to unobservable data (Level 3). In +some cases, the inputs used to measure fair value might fall in different levels +of the fair value hierarchy. The lowest level input that is +significant to a fair value measurement in its entirety determines the +applicable level in the fair value hierarchy. Assessing the +significance of a particular input to the fair value measurement in its entirety +requires judgment, considering factors specific to the asset or +liability. The three levels of inputs that may be used to measure +fair value are defined as: +Level +1 – Quoted prices (unadjusted) in active markets for identical assets or +liabilities. Instruments included in Level 1 consist of our +commodity derivatives for New York Mercantile Exchange (“NYMEX”)-based +natural gas swaps. +Level +2 – Inputs other than quoted prices included within Level 1 that are +either directly or indirectly observable for the asset or liability, +including (i) quoted prices for similar assets or liabilities in active +markets, (ii) quoted prices for identical or similar assets or liabilities +in inactive markets, (iii) inputs other than quoted prices that are +observable for the asset or liability and (iv) inputs that are derived +from observable market data by correlation or other +means. +Level +3 – Unobservable inputs for the asset or liability, including situations +where there is little, if any, market activity for the asset or +liability. Instruments included in Level 3 consist of our +commodity derivatives for Colorado Interstate Gas (“CIG”) and Panhandle +Eastern Pipeline (“PEPL”)-based natural gas swaps, oil swaps, natural gas +basis protection swaps, oil and natural gas options, and physical sales +and purchases. +We +measure fair value of our derivatives based upon quoted market prices, where +available. Our valuation determination includes: (1) identification +of the inputs to the fair value methodology through the review of counterparty +statements and other supporting documentation, (2) determination of the validity +of the source of the inputs, (3) corroboration of the original source of inputs +through access to multiple quotes, if available, or other information and (4) +monitoring changes in valuation methods and assumptions. The methods +described above may produce a fair value calculation that may not be indicative +of future fair values. Our valuation determination also gives +consideration to our nonperformance risk on our own liabilities as well as the +credit standing of our counterparties. We primarily use two +investment grade financial institutions as our counterparties to our derivative +contracts. We have evaluated the credit risk of our derivative assets +from our counterparties using relevant credit market default rates, giving +consideration to amounts outstanding for each counterparty and the duration of +each outstanding derivative position. Based on our evaluation, we +have determined that the impact of the nonperformance of our counterparties on +the fair value of our derivative instruments is +insignificant. As of December 31, 2008, no valuation allowance +was recorded. Furthermore, while we believe these valuation +methods are appropriate and consistent with that used by other market +participants, the use of different methodologies, or assumptions, to determine +the fair value of certain financial instruments could result in a different +estimate of fair value. We estimated the gross net fair value of our +commodity based derivatives as of December 31, 2008, to be $153.5 +million. +Non-Derivative +Financial Assets and Liabilities. +The +carrying values of the financial instruments comprising cash and cash +equivalents, restricted cash, accounts receivable and accounts payable +approximate fair value due to the short-term maturities of these +instruments. +The +portion of our long-term debt related to our credit facility, approximates fair +value due to the variable nature of its related interest rate. We +estimate the fair value of the portion of our long-term debt related to our +senior notes to be approximately $127 million or approximately 62.5% of par +value as of December 31, 2008. We determined this valuation based +upon measurements of trading activity and quotes provided by brokers and traders +participating in the trading of the securities. +Oil +and Gas Properties +We +account for our oil and gas properties under the successful efforts method of +accounting. Costs of proved developed producing properties, +successful exploratory wells and development dry hole costs are capitalized and +depreciated or depleted by the unit-of-production method based on estimated +proved developed producing oil and natural gas reserves. Property +acquisition costs are depreciated or depleted on the unit-of-production method +based on estimated proved oil and gas reserves. +45 +Table of Contents +Our +estimates of proved reserves are based on quantities of oil and natural gas that +engineering and geological analysis demonstrates, with reasonable certainty, to +be recoverable from established reservoirs in the future under current operating +and economic conditions. Annually, we engage independent petroleum +engineers to prepare a reserve and economic evaluation of all our properties on +a well-by-well basis as of December 31. Additionally, we adjust our +oil and gas reserves for major acquisitions, new drilling and divestitures +during the year as needed. The process of estimating and evaluating +oil and natural gas reserves is complex, requiring significant decisions in the +evaluation of available geological, geophysical, engineering and economic +data. The data for a given property may also change substantially +over time as a result of numerous factors, including additional development +activity, evolving production history and a continual reassessment of the +viability of production under changing economic conditions. As a +result, revisions in existing reserve estimates occur from time to +time. Although every reasonable effort is made to ensure that reserve +estimates reported represent our most accurate assessments possible, the +subjective decisions and variances in available data for various properties +increase the likelihood of significant changes in these estimates over +time. Because estimates of reserves significantly affect our DD&A +expense, a change in our estimated reserves could have an effect on our net +income. +Exploration +costs, including geological and geophysical expenses and delay rentals, are +charged to expense as incurred. Exploratory well drilling costs, +including the cost of stratigraphic test wells, are initially capitalized but +charged to expense if the well is determined to be nonproductive. The +status of each in-progress well is reviewed quarterly to determine the proper +accounting treatment under the successful efforts method of +accounting. Exploratory well costs continue to be capitalized as long +as the well has found a sufficient quantity of reserves to justify our +completion as a producing well and we are making sufficient progress assessing +our reserves and economic and operating viability. If an in-progress +exploratory well is found to be unsuccessful (referred to as a dry hole) prior +to the issuance of the financial statements, the costs incurred prior to the end +of the reporting period are expensed to exploration costs. If we are +unable to make a final determination about the productive status of a well prior +to issuance of the financial statements, the well is classified as “suspended +well costs” until we have had sufficient time to conduct additional completion +or testing operations to evaluate the pertinent geological and engineering data +obtained. At the time when we are able to make a final determination +of a well’s productive status, the well is removed from the suspended well +status and the proper accounting treatment is recorded. At December +31, 2008 and 2007, suspended well costs included in oil and gas properties on +our accompanying consolidated financial statements was $1.2 million and $2.3 +million, respectively. +The +acquisition costs of unproved properties are capitalized when incurred, until +such properties are transferred to proved properties or charged to expense when +expired, impaired or amortized. Unproved oil and gas properties with +individually significant acquisition costs are periodically assessed, and any +impairment in value is charged to exploration expense. The amount of +impairment recognized on unproved properties which are not individually +significant is determined by amortizing the costs of such properties within +appropriate fields based on our historical experience, acquisition dates and +average lease terms. The valuation of unproved properties is +subjective and requires us to make estimates and assumptions which, with the +passage of time, may prove to be materially different from actual realizable +values. +In +accordance with SFAS No. 144, Accounting for the Impairment or +Disposal of Long-Lived Assets , we assess our oil and gas properties for +possible impairment by comparing net capitalized costs to estimated undiscounted +future net cash flows on a field-by-field basis using estimated production based +upon prices at which we reasonably estimate the commodity to be +sold. The estimates of future prices may differ from current market +prices of oil and natural gas. Any downward revisions in estimates to +our reserve quantities, expectations of falling commodity prices or rising +operating costs could result in a reduction in undiscounted future net cash +flows and an impairment of our oil and gas properties. Although our +cash flow estimates are based on the relevant information available at the time +the estimates are made, estimates of future cash flows are, by nature, highly +uncertain and may vary significantly from actual results. +Deferred +Income Tax Asset Valuation Allowance +Deferred +income tax assets are recognized for deductible temporary differences, net +operating loss carry-forwards, and credit carry-forwards if it is more likely +than not that the tax benefits will be realized. To the extent a +deferred tax asset is not expected to be realized under the preceding criteria, +a valuation allowance is established. The factors which we consider +in assessing whether we will realize the value of deferred income tax assets +involve judgments and estimates of both amount and timing, which could differ +from actual results, achieved in future periods. +The +judgments used in applying the above policies are based on our evaluation of the +relevant facts and circumstances as of the date of the financial +statements. Actual results may differ from those +estimates. +Accounting +for Acquisitions Using Purchase Accounting +We +account for acquisitions utilizing the purchase method as prescribed by SFAS No. +141, Business +Combinations . Pursuant to purchase method accounting, the +acquiring company must allocate the cost of the acquisition to assets acquired +and liabilities assumed based on fair values as of the acquisition +date. The purchase price allocations are based on appraisals, +discounted cash flows, quoted market prices and estimates by +management. In addition, when appropriate, we review comparable +purchases and sales of oil and gas properties within the same regions, and use +that data as a basis for fair market value; for example, the amount a willing +buyer and seller would enter into an exchange for such +properties. +46 +Table of Contents +In +estimating the fair values of assets acquired and liabilities assumed we made +various assumptions. The most significant assumptions relate to the +estimated fair values assigned to proved developed producing, proved developed +non-producing, proved undeveloped and unproved oil and gas +properties. To estimate the fair values of these properties, we +prepared estimates of oil and gas reserves. We estimated future +prices to apply to the estimated reserve quantities acquired, and estimated +future operating and development costs, to arrive at estimates of future net +revenues. For estimated proved reserves, the future net revenues were +discounted using a market-based weighted average cost of capital rate determined +appropriate at the time of the acquisition. The market-based weighted +average cost of capital rate was subjected to additional project-specific +risking factors. To compensate for the inherent risk of estimating +and valuing unproved properties, the discounted future net revenues of probable +and possible reserves were reduced by additional risk-weighting +factors. +Deferred +taxes must be recorded for any differences between the assigned values and tax +basis of assets and liabilities. Estimated deferred taxes are based +on available information concerning the tax basis of assets acquired and +liabilities assumed and loss carryforwards at the acquisition date, although +such estimates may change in the future as additional information becomes +known. +Recent +Accounting Standards +See Note 1 , Summary of Significant Accounting +Policies - Recent Accounting Standards , to our accompanying consolidated +financial statements. +ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT +MARKET RISK. +Market-Sensitive +Instruments and Risk Management +We are +exposed to market risks associated with interest rates, commodity prices and +credit exposure. Management has established risk management processes +to monitor and manage these market risks. +Interest +Rate Risk +Changes +in interest rates affect the amount of interest we earn on our cash, cash +equivalents and restricted cash and the interest we pay on borrowings under our +bank credit facility. Our 12% senior notes are fixed rate and, +therefore, do not expose us to the cash flow loss due to changes in market +interest rate. However, changes in interest rates do affect the fair +value of our senior notes. +Our +interest-bearing cash and cash equivalents include our money market accounts, +short-term certificates of deposit and checking and savings accounts with +various banks. The amount of our interest-bearing cash and cash +equivalents as of December 31, 2008, was $78.8 million with an average annual +interest rate of 1.8%. +Based on +a sensitivity analysis of the credit facility borrowings as of December 31, +2008, it was estimated that if market interest rates were to average 1% higher +(lower) in 2009 than in 2008, our interest expense, net of tax, would increase +(decrease) by approximately $1.3 million. +Commodity Price +Risk +See Part +II, Item 7, Management’s +Discussion and Analysis of Financial Condition and Results of Operation, +Critical Accounting Policies and Estimates-Accounting for Derivatives Contracts +at Fair Value , for further discussion of the accounting for derivative +contracts. +We are +exposed to the effect of market fluctuations in the prices of oil and natural +gas as they relate to our oil and natural gas sales and marketing +activities. Price risk represents the potential risk of loss from +adverse changes in the market price of oil and natural gas +commodities. We employ established policies and procedures to manage +the risks associated with these market fluctuations using commodity +derivatives. Our policy prohibits the use of oil and natural gas +derivative instruments for speculative purposes. +Validation +of a contract’s fair value is performed internally and while we use common +industry practices to develop our valuation techniques, changes in our pricing +methodologies or the underlying assumptions could result in significantly +different fair values. While we believe these valuation methods are +appropriate and consistent with those used by other market participants, the use +of different methodologies, or assumptions, to determine the fair value of +certain financial instruments could result in a different estimate of fair +value. +Economic Hedging +Strategies. Our results of operations and operating cash flows +are affected by changes in market prices for oil and natural gas. To +mitigate a portion of the exposure to adverse market changes, we have entered +into various derivative contracts. As of December 31, 2008, our oil +and natural gas derivative instruments consisted of (i) NYMEX-based natural gas +contracts for Appalachian and Michigan production, (ii) PEPL-based contracts for +NECO production, (iii) CIG-based contracts for other Colorado production and +(iv) NYMEX-based crude oil contracts for our Colorado oil +production. +47 +Table of Contents +· +For +swap instruments, we receive a fixed price for the derivative contract and +pay a floating market price to the counterparty. The +fixed-price payment and the floating-price payment are netted, resulting +in a net amount due to or from the +counterparty. +· +Basis +protection swaps are arrangements that guarantee a price differential for +natural gas from a specified delivery point. For CIG basis +protection swaps, which have negative differentials to NYMEX, we receive a +payment from the counterparty if the price differential is greater than +the stated terms of the contract and pay the counterparty if the price +differential is less than the stated terms of the +contract. +· +Collars +contain a fixed floor price (put) and ceiling price (call). If +the market price exceeds the fixed call strike price, we receive the +market price from the purchaser and pay the difference between the call +strike price and market price to the counterparty. If the +market price falls below the fixed put strike price, we receive the market +price from the purchaser and receive the difference between the put strike +price and market price from the counterparty. If the market +price is between the call and the put strike price, no payments are due +from either party. +With +regard to our natural gas marketing activities, we enter into fixed-price +physical purchase and sale agreements that are derivative +contracts. In order to offset these fixed-price physical derivatives, +we enter into financial derivative instruments that have the effect of locking +in the prices we will receive or pay for the same volumes and period, offsetting +the physical derivative. While these derivatives are structured to +reduce our exposure to changes in price associated with the derivative +commodity, they also limit the benefit we might otherwise have received from +price changes in the physical market. We believe our derivative +instruments continue to be effective in achieving the risk management objectives +for which they were intended. +The +following table presents monthly average NYMEX and CIG closing prices for oil +and natural gas in 2008 and 2007, as well as average sales prices we realized +for the respective commodity. +Year +Ended December 31, +2008 +2007 +Average +Index Closing Price +Natural +Gas (per MMbtu) +CIG +$ +6.22 +$ +3.97 +NYMEX +9.04 +6.89 +Oil +(per Barrel) +NYMEX +104.42 +69.79 +Average +Sales Price +Natural +Gas +6.98 +5.33 +Oil +89.77 +60.65 +Based on +a sensitivity analysis as of December 31, 2008, it was estimated that a 10% +increase in oil and natural gas prices, inclusive of basis, over the entire +period for which we have derivatives currently in place would have resulted in +an increase in fair value of $13.7 million and a 10% decrease in oil and natural +gas prices would have resulted in an increase in fair value of $49.4 +million. +See Item +7, Management’s Discussion and +Analysis of Financial Condition and Results of Operations, Results of +Operations, Oil and Gas Price Risk Management, Net and Natural Gas Marketing +Activities , for a detailed discussion of the our open derivative +positions related to our oil and gas sales activities and our natural gas +marketing activities. See Note 3 , Derivative Financial +Instruments , to our accompanying consolidated financial statements +included in this report for a summary of our open derivative positions as of +December 31, 2008. +Credit +Risk +Credit +risk represents the loss that we would incur if a counterparty fails to perform +under its contractual obligations. We attempt to reduce credit risk +by diversifying our counterparty exposure and entering into transactions with +high-quality counterparties. When exposed to credit risk, we analyze +the counterparties’ financial condition prior to entering into an agreement, +establish credit limits and monitor the appropriateness of those limits on an +ongoing basis. We have had no counterparty default +losses. +48 +Table of Contents +Our +receivables are from a diverse group of companies, including major energy +companies, both upstream and mid-stream, financial institutions and end-users in +various industries related to our gas marketing group. We monitor +their creditworthiness through credit reports and rating agency +reports. +Our +commodity-based derivative contracts expose us to the credit risk of +nonperformance by the counterparty to the contracts. These contracts +consist of fixed price swaps, basis swaps and collars. We primarily +use two investment grade financial institutions as our counterparties to our +derivative contracts who are also major lenders in our credit facility +arrangement. We have evaluated the credit risk of our derivative +assets from our counterparties using relevant credit market default rates, +giving consideration to amounts outstanding for each counterparty and the +duration of each outstanding derivative position. Based on our +evaluation, we have determined that the impact of the nonperformance of our +counterparties on the fair value of our derivative instruments is +insignificant. As of December 31, 2008, no valuation allowance +was recorded. +The +recent disruption in the credit market has had a significant adverse impact on a +number of financial institutions. We monitor the creditworthiness of +the financial institutions with which we transact, giving consideration to the +reports of credit agencies and their related ratings. While we +believe that our monitoring procedures are sufficient and customary, no amount +of analysis can guarantee performance in these uncertain times. +Disclosure +of Limitations +Because +the information above included only those exposures that exist at December 31, +2008, it does not consider those exposures or positions which could arise after +that date. As a result, our ultimate realized gain or loss with +respect to interest rate and commodity price fluctuations will depend on the +exposures that arise during the period, our hedging strategies at the time, and +interest rates and commodity prices at the time. +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY +DATA +The +response to this Item is set forth herein in a separate section of this Report, +beginning on Page F-1. +Index to financial +statements. +ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON +ACCOUNTING AND FINANCIAL DISCLOSURE +As +reported on Form 8-K filed with the SEC on May 31, 2007, and incorporated herein +by reference, the Audit Committee of our Board of Directors recommended, and the +Board of Directors ratified, the dismissal of KPMG LLP as our principal +accountants on May 24, 2007. +ITEM 9A. CONTROLS AND PROCEDURES +Evaluation +of Disclosure Controls and Procedures +As of +December 31, 2008, we carried out an evaluation, under the supervision and with +the participation of our management, including our Chief Executive Officer and +Chief Financial Officer, of the effectiveness of the design and operation of our +disclosure controls and procedures pursuant to Securities Exchange Act Rule +13a-15. Based upon that evaluation, our Chief Executive Officer and +Chief Financial Officer concluded that our disclosure controls and procedures +were effective as of December 31, 2008, to ensure that the information required +to be disclosed by the Company in the reports that we file or submit under the +Exchange Act is recorded, processed, summarized and reported, within the time +periods specified in the SEC rules and forms, and that the information is +accumulated and communicated to our management, including our Chief Executive +Officer and Chief Financial Officer, as appropriate to allow timely decisions +regarding required disclosure. +Changes +in Internal Control over Financial Reporting +We made +no changes in our internal control over financial reporting (as such term is +defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934) +during the quarter ended December 31, 2008, that have materially affected or are +reasonably likely to materially affect our internal control over financial +reporting. +See Remediation of Material Weaknesses +in Internal Control below for a discussion of changes in our internal +control over financial reporting that occurred throughout 2008. +49 +Table of Contents +Remediation +of Material Weaknesses in Internal Control +We, with +oversight from the Audit Committee of our Board of Directors, have been +addressing the material weaknesses disclosed in our 2007 Form 10-K and Item 4 of +our subsequently filed Form 10-Q for each of the quarterly periods in the +nine-month period ended September 30, 2008. We have concluded, based +on our assessment, that, through the implementation of the changes in internal +controls over financial reporting described below, we have remediated these +previously reported material weaknesses as of December 31, +2008. Management’s annual report on internal control over financial +reporting and the audit report on our internal control over financial reporting +of our independent registered public accounting firm are included in response to +Item 8 of this report on pages F-2 and F-3 included +herein. +The +remediation initiatives that were undertaken during 2008 include: +· +In +the first quarter of 2008, we implemented the general ledger, accounts +receivable, and joint interest billing modules as part of a new broader +financial reporting system. We have taken the necessary steps +to monitor and maintain appropriate internal controls during this period +of change. These steps included providing training related to +business process changes and the financial reporting system software to +individuals using the financial reporting system to carry out their job +responsibilities as well as those who rely on the financial +information. The implementation of the financial reporting +system strengthened the overall internal controls due to enhanced +automation and integration of related processes. The design and +documentation of internal control process and procedures relating to the +new system has been modified to supplement and complement existing +internal controls over financial +reporting. +· +In +the third quarter of 2008, we implemented controls over key financial +statement spreadsheets that support all significant balance sheet and +income statement accounts. Specifically, we enhanced the +spreadsheet policy to provide additional clarification and guidance with +regard to risk assessment and enforced controls over: 1) the security and +integrity of the data used in the various spreadsheets, 2) access to the +spreadsheets, 3) changes to spreadsheet functionality and the related +approval process and documentation and 4) increased managements review of +the spreadsheets. +· +In +the third quarter of 2008, key personnel attended an accredited derivative +training course and a desktop procedure was implemented to ensure the +completeness and accuracy over derivative activities, which supplemented +the key controls that previously existed in the +process. +ITEM 9B. OTHER INFORMATION +None. +PART +III +ITEM 10. DIRECTORS , EXECUTIVE OFFICERS AND CORPORATE +GOVERNANCE +The +information called for by Item 10 is incorporated by reference from information +under the captions entitled Corporate Governance , Section 16(a) Beneficial Ownership +Reporting Compliance , Election of Directors and +Executive Compensation +and other relevant portions of our definitive proxy statement to be filed +pursuant to Regulation 14A no later than 120 days after the close of our fiscal +year. +ITEM 11. EXECUTIVE COMPENSATION +The information called for by Item 11 +is incorporated by reference from information under the caption entitled Executive Compensation and +other relevant portions of our definitive proxy statement to be filed pursuant +to Regulation 14A no later than 120 days after the close of our fiscal +year. +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS +AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +The +information called for by Item 12 is incorporated by reference from information +under the caption entitled Security Ownership of Certain +Beneficial Owners and Management and Related Stockholder Matters and +other relevant portions of our definitive proxy statement to be filed pursuant +to Regulation 14A no later than 120 days after the close of our fiscal +year. +50 +Table of Contents +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +AND DIRECTOR INDEPENDENCE +The +information called for by Item 13 is incorporated by reference from information +under the captions entitled Certain Relationships and Related +Transactions and +Director Independence in our definitive proxy statement to be +filed pursuant to Regulation 14A no later than 120 days after the close of our +fiscal year. +ITEM 14. PRINCIPAL ACCOUNTANT FEES AND +SERVICES +The +information called for by Item 14 is incorporated by reference from information +under caption entitled Principal Accountant Fees and +Services and other relevant portions of our definitive proxy +statement to be filed pursuant to Regulation 14A no later than 120 days after +the close of our fiscal year. +PART +IV +ITEM 15. EXHIBITS , FINANCIAL STATEMENT +SCHEDULES +(a) +(1) +Financial +Statements: +See +Index to Financial Statements and +Schedules on page F-1. +(2) +Financial +Statement Schedules: +See +Index to Financial Statements and +Schedules on page F-1. +Schedules +and Financial Statements Omitted +All +other financial statement schedules are omitted because they are not +required, inapplicable, or the information is included in the Financial +Statements or Notes thereto. +(3) +Exhibits: +See +Exhibits Index on page +56. +51 +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. +PETROLEUM +DEVELOPMENT CORPORATION +By +/s/ Richard W. McCullough +Richard +W. McCullough, +Chairman, +Chief Executive Officer, and President +By +/s/ Gysle R. Shellum +Gysle +R. Shellum, +Chief +Financial Officer +February +26, +2009 +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/ Richard W. McCullough +Richard +W. McCullough +Chairman, +Chief Executive Officer, and President (principal +executive officer) +February +26, 2009 +/s/ Gysle R. Shellum +Gysle +R. Shellum +Chief +Financial Officer (principal +financial officer) +February +26, 2009 +/s/ Darwin L. Stump +Darwin +L. Stump +Chief +Accounting Officer (principal +accounting officer) +February +26, 2009 +/s/ Daniel W. Amidon +Daniel +W. Amidon +General +Counsel, Corporate Secretary +February +26, 2009 +/s/ Steven R. Williams +Steven +R. Williams +Director +February +26, 2009 +/s/ Jeffrey C. Swoveland +Jeffrey +C. Swoveland +Director +February +26, 2009 +/s/ Vincent F. D'Annunzio +Vincent +F. D'Annunzio +Director +February +26, 2009 +/s/ Kimberly Luff Wakim +Kimberly +Luff Wakim +Director +February +26, 2009 +/s/ David C. Parke +David +C. Parke +Director +February +26, 2009 +/s/ Anthony J. +Crisafio +Anthony +J. Crisafio +Director +February +26, +2009 +/s/ Joseph E. +Casabona +Joseph +E. Casabona +Director +February +26, 2009 +/s/ Larry F. Mazza +Larry +F. Mazza +Director +February +26, +2009 +52 +Table of Contents +GLOSSARY OF OIL AND NATURAL GAS TERMS +The +following are abbreviations and definitions of terms commonly used in the oil +and gas industry and this Form 10-K. +Bbl - One barrel or 42 U.S. +gallons of liquid volume. +Bcf - One billion cubic +feet. +Bcfe - One billion cubic feet +of natural gas equivalent. +CIG - Colorado Interstate +Gas. +Completion - The installation +of permanent equipment for the production of oil or gas. +DD&A - Refers to depreciation, +depletion and amortization of our property and equipment. +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 hydrocarbons in sufficient quantities to justify +completion as an oil or gas well. +Exploratory well - A well +drilled to find and produce oil or natural gas reserves not classified as +proved, to find a new productive reservoir in a field previously found to be +productive of oil or natural gas in another reservoir or to extend a known +reservoir. +Extensions and discoveries - +As to any period, the increases to proved reserves from all sources other than +the acquisition of proved properties or revisions of previous +estimates. +Gross acres or wells - Refers +to the total acres or wells in which we have a working interest. +Horizontal drilling - A +drilling technique that permits the operator to contact and intersect a larger +portion of the producing horizon than conventional vertical drilling techniques +and may, depending on the horizon, result in increased production rates and +greater ultimate recoveries of hydrocarbons. +MBbls - One thousand +barrels. +Mcf - One thousand cubic +feet. +Mcfe - One thousand cubic feet +of natural gas equivalent, based on a ratio of 6 Mcf for each barrel of oil, +which reflects the relative energy content. +MMbtu - One million British +thermal units. One British thermal unit is the heat required to raise +the temperature of a one-pound mass of water from 58.5 to 59.5 degrees +Fahrenheit. +MMcf - One million cubic +feet. +MMcfe - One million cubic feet of +natural gas equivalent. +Net acres or wells - Refers to +gross acres or wells multiplied, in each case, by the percentage working +interest we own. +Net production - Oil and gas +production that we own, less royalties and production due others. +NYMEX - New York Mercantile +Exchange. +Oil - Crude oil or +condensate. +Operator - The individual or +company responsible for the exploration, development and/or production of an oil +or gas well or lease. +53 +Table of Contents +PEPL - Panhandle Eastern +Pipeline. +Present value of proved +reserves - The present value of estimated future revenues, discounted at +10% annually, to be generated from the production of proved reserves determined +in accordance with Securities and Exchange Commission guidelines, net of +estimated production and future development costs, using prices and costs as of +the date of estimation without future escalation, without giving effect to (i) +estimated future abandonment costs, net of the estimated salvage value of +related equipment, (ii) non-property related expenses such as general and +administrative expenses, debt service and future income tax expense, or (iii) +depreciation, depletion and amortization. +Proved developed non-producing +reserves - Reserves that consist of (i) proved reserves from wells which +have been completed and tested but are not producing due to lack of market or +minor completion problems which are expected to be corrected and (ii) proved +reserves currently behind the pipe in existing wells and which are expected to +be productive due to both the well log characteristics and analogous production +in the immediate vicinity of the wells. +Proved developed producing +reserves - +Proved reserves that can be expected to be recovered from currently +producing zones under the continuation of present operating +methods. +Proved developed reserves - The combination of proved +developed producing and proved developed non-producing reserves. +Proved reserves - 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, i.e., prices and costs as of the date the estimate is +made. Prices include consideration of changes in existing prices +provided only by contractual arrangements, but not on escalations based upon +future conditions. +Proved undeveloped reserves, +or PUD - Proved +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 - A recompletion +occurs when we reenter a well to complete (i.e., perforate) a new formation +different from that in which a well has previously been completed. +Refrac, or refracture – A +refrac is when we stimulate the present producing zone of a well to increase +production, using hydraulic, acid, gravel, etc. fracture +techniques. +Reserve replacement - +Calculated by dividing the sum of reserve additions from all sources (revisions, +extensions, discoveries and other additions and acquisitions) by the actual +production for the corresponding period. The values used for reserve +additions are derived directly from the proved reserves table located in Note 18 , Supplemental Oil and Gas +information , to our consolidated financial statements included in this +report. We use the reserve replacement ratio as an indicator of our +ability to replenish annual production volumes and grow our reserves, thereby +providing some information on the sources of future production. It +should be noted that the reserve replacement ratio is a statistical indicator +that has limitations. As an annual measure, the ratio is limited +because it typically varies widely based on the extent and timing of new +discoveries and property acquisitions. Its predictive and comparative +value is also limited for the same reasons. In addition, since the +ratio does not imbed the cost or timing of future production of new reserves, it +cannot be used as a measure of value creation. +Royalty - An interest in an +oil and gas lease that gives the owner of the interest the right to receive a +portion of the production from the leased acreage (or of the proceeds of the +sale thereof), but generally does not require the owner to pay any portion of +the costs of drilling or operating the wells on the leased +acreage. Royalties may be either landowner’s royalties, which are +reserved by the owner of the leased acreage at the time the lease is granted, or +overriding royalties, which are usually reserved by an owner of the leasehold in +connection with a transfer to a subsequent owner. +Standardized measure of discounted +future net cash flows - Present value of proved reserves, as adjusted to +give effect to (i) estimated future abandonment costs, net of the estimated +salvage value of related equipment, and (ii) estimated future income +taxes. +Undeveloped acreage - Leased +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 proved reserves. +Working interest - An interest +in an oil and gas lease that gives the owner of the interest the right to drill +for and produce oil and gas on the leased acreage and requires the owner to pay +a share of the costs of drilling and production operations. The share +of production to which a working interest is entitled will be smaller than the +share of costs that the working interest owner is required to bear to the extent +of any royalty burden. +Workover - Operations on a +producing well to restore or increase production. +54 +Table of Contents +Exhibits +Index +Incorporated +by Reference +Exhibit +Number +Exhibit +Description +Form +SEC +File Number +Exhibit +Filing +Date +Filed +Herewith +3.1 +Second +Amended and Restated Certificate of Incorporation of Petroleum Development +Corporation. +8-K +000-07246 +3.1 +07/23/2008 +3.2 +Bylaws +of Petroleum Development Corporation, amended and restated, effective +October 11, 2007. +8-K +000-07246 +3.2 +10/17/2007 +4.1 +Rights +Agreement by and between Petroleum Development Corporation and Transfer +Online, Inc., as Rights Agent, dated as of September 11, 2007, including +the forms of Rights Certificates and Summary of Stockholder Rights Plan +attached thereto as Exhibits A and B. +8-K +000-07246 +4.1 +09/14/2007 +4.2 +Indenture +dated as of February 8, 2008, by and among Petroleum Development +Corporation and The Bank of New York. +8-K +000-07246 +4.1 +02/12/2008 +4.3 +First +Supplemental Indenture dated as of February 8, 2008, by and among +Petroleum Development Corporation and the Bank of New +York. +8-K +000-07246 +4.2 +02/12/2008 +4.4 +Form +of 12% Senior Note due 2018. +8-K +000-07246 +4.3 +02/12/2008 +10.1 +Purchase +Agreement dated as of February 1, 2008, by and among Petroleum Development +Corporation and the Initial Purchasers of 12% senior notes due 2018 named +therein. +8-K +000-07246 +10.1 +02/07/2008 +10.2 +Registration +Rights Agreement dated as of February 8, 2008, by and among Petroleum +Development Corporation and the Initial Purchasers of 12% senior notes due +2018 named therein. +8-K +000-07246 +10.1 +02/12/2008 +10.3 +Amended +and Restated Credit Agreement dated as of November 4, 2005, Petroleum +Development Corporation, as borrower and JPMorgan Chase Bank, N.A and BNP +Paribas, as lenders. +8-K +000-07246 +10.1 +11/04/2005 +10.4 +First +Amendment to Amended and Restated Credit Agreement, dated as of August 9, +2007, by an among Petroleum Development Corporation, certain of its +subsidiaries, JPMorgan Chase Bank, N.A., BNP Paribas and Wachovia Bank, +N.A. +8-K +000-07246 +10.1 +08/15/2007 +10.5 +Second +Amendment to Amended and Restated Credit Agreement, dated as of October +16, 2007, by and among Petroleum Development Corporation, certain of its +subsidiaries, JPMorgan Chase Bank, N.A., BNP Paribas, Wachovia Bank, N.A., +Guaranty Bank, FSB, Bank of Oklahoma and Morgan Stanley +Bank. +8-K +000-07246 +10.1 +10/22/2007 +10.6 +Third +Amendment to Amended and Restated Credit Agreement dated as of July 15, +2008, by and among Petroleum Development Corporation, +certain of its subsidiaries, JP Morgan Chase Bank, N.A., BNP Paribas and +various other banks. +8-K +000-07246 +10.1 +07/21/2008 +10.7 +Fourth +Amendment to Amended and Restated Credit Agreement dated as of July 18, +2008, by and among the Company, certain of its subsidiaries, JP Morgan +Chase Bank, N.A., BNP Paribas and various other banks. +8-K +000-07246 +10.2 +07/21/2008 +10.8 +Fifth +Amendment to Amended and Restated Credit Agreement dated as of November +12, 2008, by and among the Company, certain of its subsidiaries, JP Morgan +Chase Bank, N.A., various other banks. +8-K +000-07246 +10.1 +11/19/2008 +55 +Table of Contents +Incorporated +by Reference +Exhibit +Number +Exhibit +Description +Form +SEC +File Number +Exhibit +Filing +Date +Filed +Herewith +10.9* +Employment +Agreement with Richard W. McCullough, Chief Executive Officer, dated as of +December 31, 2008. +X +10.10* +Employment +Agreement with Eric R. Stearns, Executive Vice President, dated as of +December 31, 2008. +X +10.11* +Employment +Agreement with Gysle R. Shellum, Chief Financial Officer, dated as of +December 31, 2008. +X +10.12* +Employment +Agreement with Barton R. Brookman, Jr., Senior Vice President of +Exploration and Production, dated as of December 31, 2008. +X +10.13* +Employment +Agreement with Daniel W. Amidon, General Counsel and Corporate Secretary, +dated as of December 31, 2008. +X +10.14* +Employment +Agreement with Darwin L. Stump, Chief Accounting Officer, dated as of +December 31, 2008. +X +10.15* +2008 +Short-Term Incentive Compensation Terms for Executive +Officers. +8-K +000-07246 +03/28/2008 +10.16* +2008 +Long-Term Incentive Program (as amended for 2008) for Executive +Officers. +8-K +000-07246 +10.1 +03/13/2008 +10.17* +Non-Employee +Director Compensation for the 2008-2009 Term. +8-K +000-07246 +03/13/2008 +10.18* +2008 +Base Salary and Short-Term Incentive Cash Bonus Program for Executive +Officers. +8-K +000-07246 +02/22/2008 +10.19* +2007 +Long-Term Incentive Program for Executive Officers. +8-K +000-07246 +10.1 +04/13/2007 +10.20* +2006 +Long-Term Equity Compensation Grants to Executive +Officers. +8-K +000-07246 +04/10/2007 +10.21* +Agreement +with Steven R. Williams, Director. +10-Q +000-07246 +10.3 +11/06/2008 +10.22* +Separation +Agreement with Thomas E. Riley, former President. +X +10.23* +Indemnification +Agreement with Directors and Officers. +10-Q +000-07246 +10.1 +08/09/2007 +10.24* +The +Petroleum Development Corporation 401(k) & Profit Sharing +Plan. +S-8 +333-137836 +4.1 +10/05/2006 +10.25* +2005 +Non-Employee Director Restricted Stock Plan amended and restated as of +March 8, 2008. +10-Q +000-07246 +10.6 +11/06/2008 +10.26* +2004 +Long-Term Equity Compensation Plan amended and restated as of March 8, +2008. +X +10.27* +Non-Employee +Director Deferred Compensation Plan. +S-8 +333-118222 +99.1 +08/13/2004 +10.28* +1999 +Incentive Stock Option and Non-Qualified Stock Plan. +S-8 +333-111825 +99.1 +01/09/2004 +14.1 +Code +of Business Conduct and Ethics. +X +21.1 +Subsidiaries. +X +23.1 +Consent +of PricewaterhouseCoopers LLP. +X +23.2 +Consent +of KPMG LLP. +X +23.3 +Consent +of Wright & Company, Inc., Petroleum Consultants. +X +23.4 +Consent +of Ryder Scott Company, L.P., Petroleum Consultants. +X +56 +Table of Contents +Incorporated +by Reference +Exhibit +Number +Exhibit +Description +Form +SEC +File Number +Exhibit +Filing +Date +Filed +Herewith +31.1 +Certification +by Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the +Exchange Act Rules, as adopted pursuant to Section 302 of the +Sarbanes-Oxley Act of 2002. +X +31.2 +Certification +by Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the +Exchange Act Rules, as adopted pursuant to Section 302 of the +Sarbanes-Oxley Act of 2002. +X +32.1 +Certifications +by Chief Executive Officer and Chief Financial Officer pursuant to Title +18 U.S.C. Section 1350, as adopted pursuant to Section 906 of +Sarbanes-Oxley Act of 2002. +X +____________ +*Management +contract or compensatory plan or arrangement. +57 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +Index +to Consolidated Financial Statements and Financial Statement +Schedule +Management's Report on Internal Control Over +Financial Reporting +F-2 +Financial +Statements: +Reports of Independent Registered Public +Accounting Firms +F-3 +Consolidated Balance Sheets - December 31, 2008 +and 2007 +F-5 +Consolidated Statements of Operations - Years +Ended December 31, 2008, 2007 and 2006 +F-6 +Consolidated Statements of Cash Flows - Years +Ended December 31, 2008, 2007 and 2006 +F-7 +Consolidated Statements of Shareholders' Equity - +Years Ended December 31, 2008, 2007 and 2006 +F-8 +Notes to Consolidated Financial +Statements +F-9 +Financial +Statement Schedule: +Schedule II – Valuation and Qualifying Accounts +and Reserves +F-48 +F-1 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +Management's Report on +Internal Control Over Financial Reporting +Management +is responsible for establishing and maintaining adequate internal control over +financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) of +the Exchange Act. 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. 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 policies +or procedures may deteriorate. +Management +has assessed the effectiveness of the Company’s internal control over financial +reporting as of December 31, 2008, based upon the criteria established in +“Internal Control – Integrated Framework” issued by the Committee of Sponsoring +Organizations of the Treadway Commission (“COSO”). Based on this +evaluation, management concluded that the Company maintained effective internal +control over financial reporting as of December 31, 2008. +The +effectiveness of Petroleum Development Corporation's internal control over +financial reporting as of December 31, 2008, has been audited by +PricewaterhouseCoopers LLP, an independent registered public accounting firm, as +stated in their report which appears herein. +PETROLEUM +DEVELOPMENT CORPORATION +/s/ +Richard W. McCullough +Richard +W. McCullough +Chairman +and Chief Executive Officer +/s/ +Gysle R. Shellum +Gysle +R. Shellum +Chief +Financial Officer +F-2 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +Report of +Independent Registered Public Accounting Firm +To the Board of +Directors and Shareholders +of Petroleum +Development Corporation +In our opinion, +the accompanying consolidated balance sheets and the related consolidated +statements of operations, shareholders' equity, and cash flows present fairly, +in all material respects, the financial position of Petroleum Development +Corporation and its subsidiaries at December 31, 2008 and 2007, and +the results of their operations and their cash flows for the years then ended in +conformity with accounting principles generally accepted in the United States of +America. In addition, in our opinion, the 2008 and 2007 information +in the financial statement schedule listed in the accompanying +index presents fairly, in all material respects, the information set forth +therein when read in conjunction with the related consolidated financial +statements. Also in our opinion, the Company maintained, in all +material respects, effective internal control over financial reporting as of +December 31, 2008, based on criteria established in Internal Control - +Integrated Framework issued by the Committee of Sponsoring Organizations of the +Treadway Commission (COSO). The Company's management is responsible +for these financial statements and financial statement schedule, 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 opinions on these +financial statements, on the 2008 and 2007 information in the financial +statement schedule, and on the Company's internal control over financial +reporting based on our integrated 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 +audits to obtain reasonable assurance about whether the financial statements are +free of material misstatement and whether effective internal control over +financial reporting was maintained in all material respects. Our +audits of the financial statements included examining, on a test basis, evidence +supporting the amounts and disclosures in the financial statements, assessing +the accounting principles used and significant estimates made by management, and +evaluating the overall financial statement presentation. Our audit of +internal control over financial reporting included obtaining an understanding of +internal control over financial reporting, assessing the risk that a material +weakness exists, and testing and evaluating the design and operating +effectiveness of internal control based on the assessed risk. Our +audits also included performing such other procedures as we considered necessary +in the circumstances. We believe that our audits provide a reasonable basis for +our opinion. +As discussed in +Note 5 to the consolidated financial statements, the Company changed the +manner in which it accounts for uncertain tax positions in 2007. +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 +(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 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. +/s/ +PricewaterhouseCoopers LLP +Pittsburgh, +Pennsylvania +February 26, +2009 +F-3 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +Report +of Independent Registered Public Accounting Firm +The Board +of Directors and Stockholders +Petroleum +Development Corporation: +We have +audited the accompanying consolidated statements of operations, shareholders’ +equity, and cash flows of Petroleum Development Corporation and subsidiaries for +the year ended December 31, 2006. In connection with our audit +of these consolidated financial statements, we also have audited the related +financial statement schedule. These consolidated financial statements +and financial statement schedule are the responsibility of the Company’s +management. Our responsibility is to express an opinion on these +consolidated 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 consolidated financial statements referred to above present fairly, +in all material respects, the results of operations and the cash flows of +Petroleum Development Corporation and subsidiaries for the year ended +December 31, 2006, in conformity with U.S. generally accepted accounting +principles. Also in our opinion, the related financial statement +schedule, when considered in relation to the basic consolidated financial +statements taken as a whole, presents fairly, in all material respects, the +information set forth therein. +As +discussed in Note 1 to the consolidated financial statements, the Company +adopted the provisions of Statement of Financial Accounting Standards No. +123(R), (“Share-Based Payment”), in 2006. +As +discussed in Note 1 to the consolidated financial statements, the Company +changed its method of quantifying errors based on SEC Staff Accounting Bulletin +No. 108 (“Considering the Effects of Prior Year Misstatements when Quantifying +Misstatements in Current Year Financial Statements”) in 2006. +KPMG +LLP +Pittsburgh, +Pennsylvania +May 22, +2007 +F-4 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +Consolidated +Balance Sheets +(in +thousands, except share and per share data) +December +31, +2008 +2007 +Assets +Current +assets: +Cash +and cash equivalents +$ +50,950 +$ +84,751 +Restricted +cash - current +19,030 +14,773 +Accounts +receivable, net +69,688 +60,024 +Accounts +receivable - affiliates +16,742 +11,537 +Fair +value of derivatives - current +116,881 +4,817 +Prepaid +expenses and other current assets +19,146 +15,891 +Total +current assets +292,437 +191,793 +Properties +and equipment, net +1,033,078 +845,864 +Other +assets +77,189 +12,822 +Total +Assets +$ +1,402,704 +$ +1,050,479 +Liabilities +and Shareholders' Equity +Current +liabilities: +Accounts +payable +$ +90,532 +$ +88,502 +Accounts +payable - affiliates +40,540 +3,828 +Production +tax liability +18,226 +21,330 +Federal +and state income taxes payable +1,591 +901 +Fair +value of derivatives +4,766 +6,291 +Advances +for future drilling contracts +1,675 +68,417 +Funds +held for distribution +50,361 +39,823 +Net +deferred income taxes - current +28,355 +- +Other +accrued expenses +25,125 +12,913 +Total +current liabilities +261,171 +242,005 +Long-term +debt +394,867 +235,000 +Net +deferred income taxes - non current +162,593 +136,490 +Other +liabilities +71,798 +40,699 +Total +liabilities +890,429 +654,194 +Commitments +and contingent liabilities +Minority +interest in consolidated limited liability company +694 +759 +Shareholders' +equity: +Preferred +shares, par value $.01 per share; authorized 50,000,000 shares; +issued: none +- +- +Common +shares, par value $.01 per share; authorized 100,000,000 shares; +issued: 14,871,870 in 2008 and 14,907,679 in +2007 +149 +149 +Additional +paid-in capital +5,818 +2,559 +Retained +earnings +505,906 +393,044 +Treasury +shares, at cost: 7,066 shares in 2008 and 5,894 in 2007 +(292 +) +(226 +) +Total +shareholders' equity +511,581 +395,526 +Total +Liabilities and Shareholders' Equity +$ +1,402,704 +$ +1,050,479 +See accompanying Notes to +Consolidated Financial Statements . +F-5 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +Consolidated +Statements of Operations +(in +thousands, except per share data) +Year +Ended December 31, +2008 +2007 +2006 +Revenues: +Oil +and gas sales +$ +321,877 +$ +175,187 +$ +115,189 +Sales +from natural gas marketing activities +140,263 +103,624 +131,325 +Oil +and gas well drilling +7,615 +12,154 +17,917 +Well +operations and pipeline income +11,474 +9,342 +10,704 +Oil +and gas price risk management gain, net +127,838 +2,756 +9,147 +Other +293 +2,172 +2,221 +Total +revenues +609,360 +305,235 +286,503 +Costs +and expenses: +Oil +and gas production and well operations cost +78,209 +49,264 +29,021 +Cost +of natural gas marketing activities +139,234 +100,584 +130,150 +Cost +of oil and gas well drilling +2,213 +2,508 +12,617 +Exploration +expense +45,105 +23,551 +8,131 +General +and administrative expense +37,715 +30,968 +19,047 +Depreciation, +depletion, and amortization +104,575 +70,844 +33,735 +Total +costs and expenses +407,051 +277,719 +232,701 +Gain +on sale of leaseholds +- +33,291 +328,000 +Income +from operations +202,309 +60,807 +381,802 +Interest +income +591 +2,662 +8,050 +Interest +expense +(28,132 +) +(9,279 +) +(2,443 +) +Income +before income taxes +174,768 +54,190 +387,409 +Provision +for income taxes +61,459 +20,981 +149,637 +Net +income +$ +113,309 +$ +33,209 +$ +237,772 +Earnings +per common share: +Basic +$ +7.69 +$ +2.25 +$ +15.18 +Diluted +$ +7.63 +$ +2.24 +$ +15.11 +Weighted +average common and common equivalent shares outstanding: +Basic +14,736 +14,744 +15,660 +Diluted +14,848 +14,841 +15,741 +See accompanying Notes to +Consolidated Financial Statements . +F-6 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +Consolidated +Statements of Shareholders' Equity +(in +thousands, except share and per share data) +Year +Ended December 31, +2008 +2007 +2006 +Common +stock, par value $.01 per share - shares issued: +Shares +at beginning of year +14,907,679 +14,834,871 +16,281,923 +Adjust +prior conversion of predecessor shares +100 +- +59,546 +Exercise +of stock options +25,699 +38,000 +8,000 +Issuance +of stock awards, net of forfeitures +21,863 +46,828 +112,902 +Retirement +of treasury shares +(83,471 +) +(12,020 +) +(1,627,500 +) +Shares +at end of year +14,871,870 +14,907,679 +14,834,871 +Treasury +stock: +Shares +at beginning of year +(5,894 +) +(4,706 +) +- +Purchase +of treasury shares +(83,471 +) +(12,020 +) +(1,627,500 +) +Retirement +of treasury shares +83,471 +12,020 +1,627,500 +Non-employee +directors' deferred compensation plan +(1,172 +) +(1,188 +) +(4,706 +) +Shares +at end of year +(7,066 +) +(5,894 +) +(4,706 +) +Common +shares outstanding +14,864,804 +14,901,785 +14,830,165 +Common +stock, $.01 par: +Balance +at beginning of year +$ +149 +$ +148 +$ +163 +Exercise +of stock options +- +- +- +Issuance +of stock awards, net of forfeitures +- +1 +1 +Retirement +of treasury shares +- +- +(16 +) +Balance +at end of year +149 +149 +148 +Additional +paid-in capital: +Balance +at beginning of year +2,559 +64 +30,423 +Reclassification +of unearned compensation pursuant to the adoption of SFAS No. +123(R) +- +- +(825 +) +Exercise +of stock options +627 +183 +31 +Issuance +of stock awards, net of forfeitures +- +(1 +) +(1 +) +Stock +based compensation expense +6,702 +2,286 +1,516 +Retirement +of treasury shares +(5,101 +) +(646 +) +(31,150 +) +Excess +tax benefit of stock based compensation +1,031 +673 +70 +Balance +at end of year +5,818 +2,559 +64 +Retained +earnings: +Balance +at beginning of year +393,044 +360,102 +158,504 +Cumulative +effect adjustment for the adoption of SAB 108, net of tax +- +- +(1,021 +) +FIN +48 adoption +- +(267 +) +- +Retirement +of treasury shares +(447 +) +- +(35,153 +) +Net +income +113,309 +33,209 +237,772 +Balance +at end of year +505,906 +393,044 +360,102 +Unamortized +stock award +Balance +at beginning of year +- +- +(825 +) +Reclassification +of unearned compensation pursuant to the adoption of SFAS No. +123(R) +- +- +825 +Balance +at end of year +- +- +- +Treasury +stock, at cost: +Balance +at beginning of year +(226 +) +(170 +) +- +Purchase +of treasury shares +(5,549 +) +(646 +) +(66,319 +) +Retirement +of treasury shares +5,549 +646 +66,319 +Non-employee +directors' deferred compensation plan +(66 +) +(56 +) +(170 +) +Balance +at end of year +(292 +) +(226 +) +(170 +) +Total +shareholders' equity +$ +511,581 +$ +395,526 +$ +360,144 +See accompanying Notes to +Consolidated Financial Statements . +F-7 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +Consolidated +Statements of Cash Flows +(in +thousands) +Year +Ended December 31, +2008 +2007 +2006 +Cash +flows from operating activities: +Net +income +$ +113,309 +$ +33,209 +$ +237,772 +Adjustments +to net income to reconcile to net cash provided by operating +activities: +Deferred +income taxes +59,079 +12,201 +86,431 +Depreciation, +depletion and amortization +104,575 +70,844 +33,735 +Allowance +for doubtful accounts +180 +50 +7 +Amortization +of debt issuance costs +1,344 +394 +- +Impairment +of oil and gas properties +22,091 +1,485 +1,519 +Accretion +of asset retirement obligation +1,230 +999 +515 +Exploratory +dry hole costs +6,504 +1,775 +1,790 +Loss +(gain) from sale of leaseholds/assets +19 +(33,322 +) +(327,991 +) +Expired +and abandoned leases +3,633 +1,786 +2,169 +Stock +based compensation +6,702 +2,286 +1,516 +Unrealized +(gains) losses on derivative transactions +(117,536 +) +4,642 +(7,620 +) +Excess +tax benefits from stock-based compensation +(1,031 +) +(673 +) +(70 +) +Changes +in current assets and liabilities: +(Increase) +decrease in restricted cash +(4,257 +) +(14,254 +) +982 +Increase +in accounts receivable +(9,844 +) +(16,506 +) +(9,942 +) +Increase +in accounts receivable - affiliates +(7,631 +) +(2,302 +) +(194 +) +(Increase) +decrease in inventories +(2,062 +) +1,285 +1,987 +(Increase) +decrease in other current assets +(5,793 +) +4,839 +(2,106 +) +Increase +(decrease) in production tax liability +9,857 +10,802 +(261 +) +Increase +(decrease) in accounts payable and accrued expenses +2,790 +(10,869 +) +13,010 +Increase +(decrease) in accounts payable - affiliates +10,282 +(3,099 +) +6,116 +(Decrease) +increase in advances for future drilling contracts +(66,742 +) +13,645 +4,773 +Increase +(decrease) in federal and state income taxes payable +1,721 +(27,124 +) +19,950 +Increase +in funds held for future distribution +10,538 +7,488 +(575 +) +Other +143 +723 +3,877 +Net +cash provided by operating activities +139,101 +60,304 +67,390 +Cash +flows from investing activities: +Capital +expenditures +(323,153 +) +(238,988 +) +(146,945 +) +Acquisition +of oil and gas properties, net of cash acquired +- +(255,661 +) +(18,512 +) +Investment +in drilling partnerships +- +- +(7,151 +) +(Increase) +decrease in restricted/designated cash +(874 +) +191,156 +(192,416 +) +Proceeds +from sale of leases to partnerships +448 +1,371 +1,798 +Proceeds +from sale of leaseholds/assets +538 +34,701 +353,600 +Net +cash used in investing activities +(323,041 +) +(267,421 +) +(9,626 +) +Cash +flows from financing activities: +Proceeds +from credit facility +419,000 +352,000 +302,000 +Proceeds +from senior notes +200,101 +- +- +Proceeds +from short-term debt +- +- +20,000 +Payment +of credit facility +(459,500 +) +(254,000 +) +(209,000 +) +Payment +of debt issuance costs +(5,571 +) +(1,468 +) +(160 +) +Proceeds +from exercise of stock options +627 +183 +31 +Excess +tax benefits from stock-based compensation +1,031 +673 +70 +Minority +interest investment +- +800 +- +Purchase +of treasury stock +(5,549 +) +(646 +) +(66,489 +) +Net +cash provided by financing activities +150,139 +97,542 +46,452 +Net +(decrease) increase in cash and cash equivalents +(33,801 +) +(109,575 +) +104,216 +Cash +and cash equivalents, beginning of year +84,751 +194,326 +90,110 +Cash +and cash equivalents, end of year +$ +50,950 +$ +84,751 +$ +194,326 +Supplemental +cash flow information: +Cash +payments for: +Interest, +net of capitalized interest +$ +19,200 +$ +9,535 +$ +1,376 +Income +taxes, net of refunds +(530 +) +43,785 +46,735 +Non-cash +investing activities: +Change +in deferred tax liability resulting from reallocation of acquisition +purchase price +- +4,188 +- +Change +in accounts payable - affiliates related to acquisition of +partnerships +- +668 +- +Change +in accounts payable related to purchases of properties and +equipment +8,197 +32,820 +1,800 +Change +in accounts payable - affiliates related to investment in drilling +partnership +- +18,712 +(7,151 +) +Change +in asset retirement obligation, with a corresponding increase to oil and +gas properties, net of disposals +1,153 +7,850 +3,164 +See +accompanying Notes to Consolidated Financial Statements . +F-8 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS +NOTE +1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +General +Petroleum +Development Corporation (“PDC,” “we,” “us” or “the Company”) is an independent +energy company engaged primarily in the drilling and development, production and +marketing of natural gas and oil. Since we began oil and gas +operations in 1969, we have grown primarily through drilling and development +activities, the acquisition of producing natural gas and oil wells and the +expansion of our natural gas marketing activities. As of December 31, +2008, we operate approximately 4,712 wells located in the Appalachian Basin, +Michigan Basin, and the Rocky Mountain Region. Our oil and natural +gas wells are located in West Virginia, Tennessee, Pennsylvania, Michigan, North +Dakota, Colorado, Kansas, Texas and Wyoming. We separate our +operations into four business segments: oil and gas sales, natural gas marketing +activities, well operations and pipeline income and oil and gas well drilling +operations. See Note 16 , Business +Segments . +Principles of +Consolidation +The +consolidated financial statements of PDC include the accounts of our +wholly-owned subsidiaries and WWWV, LLC, an entity in which we have a +controlling financial interest. All material intercompany accounts +and transactions have been eliminated in consolidation. We account +for our investment in interests in oil and gas limited partnerships under the +proportionate consolidation method. Under this method, our +consolidated financial statements include our investments in the partnerships +recorded by our working interest in each well thereby accumulating our pro rata +share of assets, liabilities and revenues and expenses respectively of the +limited partnerships in which we participate. Our proportionate share +of all significant transactions between us and the limited partnerships is +eliminated. +Use +of Estimates +The +preparation of our consolidated financial statements in accordance with +generally accepted accounting principles in the United States of America +(“U.S.”) requires us to make estimates and assumptions that affect the amounts +reported in our consolidated financial statements and accompanying +notes. Actual results could differ from those +estimates. Estimates which are particularly significant to our +consolidated financial statements include estimates of oil and gas reserves, +future cash flows from oil and gas properties, valuation of derivative +instruments and valuation of deferred income tax assets. +Cash +Equivalents +For +purposes of the statement of cash flows, we consider all highly liquid debt +instruments with original maturities of three months or less to be cash +equivalents. +Restricted Cash +Included +in our restricted cash – current as of December 31, 2007, along with interest +earned of $0.4 million, is an escrow account funded in June 2007 in the amount +of $14.1 million, representing amounts due to the limited partners of our +sponsored drilling partnerships as a result of our over withholding estimated +production taxes in years prior to 2007. In October 2008, as part of +a pre-filing agreement, we paid the Internal Revenue Service on behalf of the +limited partners an estimated tax payment of $4.2 million. As of +December 31, 2008, we had reflected in restricted cash - current $10.6 million, +including additional interest of $0.3 million earned in 2008. +Pursuant +to a preliminary court approved litigation settlement agreement reached in +October 2008, we funded an escrow account in November 2008 in the amount of $8.2 +million, of which $5.8 million represented the Company’s share of the settlement +and the remainder being that of the affiliated partnerships for which the +Company serves as the managing general partner. As of December 31, +2008, restricted cash – current includes $8.2 million related to this escrow +account. Further, our balance sheet includes a related accounts +receivable from our affiliated partnerships of $2.4 million. +We are +required by a counterparty to maintain a margin deposit for outstanding +derivative contracts. As of December 31, 2007, cash in the amount of +$0.3 million was on deposit and reflected in our consolidated balance sheets as +restricted cash - current. As of December 31, 2008, the margin +deposit requirement was insignificant. +F-9 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +We are +required by various government agencies or joint venture agreements to maintain +a bond or cash account for the plugging and abandonment of wells. As +of December 31, 2008 and 2007, we had bonds in the form of certificates of +deposit for plugging and abandonment of wells totaling $2.2 million and $1.3 +million, respectively, which are reflected in other assets. +Accounts +Receivable +Our +accounts receivable are primarily from purchasers of oil and natural gas and +third parties and affiliated partnerships for well pipeline operating +services. Inherent to our industry is the concentration of oil and +natural gas sales to a few customers. This industry concentration has +the potential to impact our overall exposure to credit risk, either positively +or negatively, in that our customers may be similarly affected by changes in +economic, industry or other conditions. +We +provide an allowance for doubtful accounts equal to the estimated uncollectible +amounts. In making our estimate, we consider our historical +write-offs, relationships and overall creditworthiness of our customers, +additional consideration is given to well production data for receivables +related to well operations. It is reasonably possible that our +estimate of uncollectible amounts will change periodically. Accounts +receivable are presented on our consolidated balance sheets net of allowance for +doubtful accounts of $0.5 million and $0.4 million at December 31, 2008 and +2007, respectively. +Inventories +Materials, +supplies and commodity inventories are stated at the lower of average cost or +market and removed at carrying value. Inventory of $4.3 million and +$2.2 million as of December 31, 2008 and 2007, respectively, is included in +prepaid expenses and other current assets on our consolidated balance +sheets. +Derivative +Financial Instruments +We +account for derivative financial instruments in accordance with Statement of +Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative +Instruments and Certain Hedging Activities , as amended. +During +2008, 2007 and 2006, none of our derivative instruments qualified for use of +hedge accounting under the terms of SFAS No. 133. Accordingly, we +recognize all derivative instruments as either assets or liabilities on our +consolidated balance sheets at fair value, and changes in the derivatives' fair +values are recorded on a net basis in our consolidated statements of +operations. Changes in the fair value of derivative instruments +related to our oil and gas sales activities are recorded in oil and gas price +risk management, net and changes in fair value of derivatives related to our +natural gas marketing activities are recorded in sales from and cost of natural +gas marketing activities. +We record +on our consolidated balance sheets the fair value of derivative instruments +entered into by us and allocated to our affiliated partnerships, recording an +offsetting receivable from or payable to those partnerships. +See Note 2 , Fair Value of Financial +Instruments , and Note 3 , Derivative Financial +Instruments , for a discussion of our derivative fair value measurements +and a summary fair value table of our open positions as of December 31, 2008 and +2007, respectively. +Properties +and Equipment +Oil +and Gas Properties. +We +account for our oil and gas properties under the successful efforts method of +accounting. Costs of proved developed producing properties, +successful exploratory wells and development dry hole costs are capitalized and +depreciated or depleted by the unit-of-production method based on estimated +proved developed producing oil and natural gas reserves. Property +acquisition costs are depreciated or depleted on the unit-of-production method +based on estimated proved oil and gas reserves. +F-10 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Our +estimates of proved reserves are based on quantities of oil and natural gas that +engineering and geological analysis demonstrates, with reasonable certainty, to +be recoverable from established reservoirs in the future under current operating +and economic conditions. Annually, we engage independent petroleum +engineers to prepare a reserve and economic evaluation of all our properties on +a well-by-well basis as of December 31. Additionally, we adjust our +oil and gas reserves for major acquisitions, new drilling and divestitures +during the year as needed. The process of estimating and evaluating +oil and natural gas reserves is complex, requiring significant decisions in the +evaluation of available geological, geophysical, engineering and economic +data. The data for a given property may also change substantially +over time as a result of numerous factors, including additional development +activity, evolving production history and a continual reassessment of the +viability of production under changing economic conditions. As a +result, revisions in existing reserve estimates occur from time to +time. Although every reasonable effort is made to ensure that reserve +estimates reported represent our most accurate assessments possible, the +subjective decisions and variances in available data for various properties +increase the likelihood of significant changes in these +estimates. Because estimates of reserves significantly affect our +depreciation, depletion and amortization (“DD&A”) expense, a change in our +estimated reserves could have an effect on our net income. +Exploration +costs, including geological and geophysical expenses and delay rentals, are +charged to expense as incurred. Exploratory well drilling costs, +including the cost of stratigraphic test wells, are initially capitalized but +charged to expense if the well is determined to be nonproductive. The +status of each in-progress well is reviewed quarterly to determine the proper +accounting treatment under the successful efforts method of +accounting. Exploratory well costs continue to be capitalized as long +as the well has found a sufficient quantity of reserves to justify our +completion as a producing well and we are making sufficient progress assessing +our reserves and economic and operating viability. If an in-progress +exploratory well is found to be unsuccessful (referred to as a dry hole) prior +to the issuance of the financial statements, the costs incurred prior to the end +of the reporting period are expensed to exploration costs. If we are +unable to make a final determination about the productive status of a well prior +to issuance of the financial statements, the costs associated with the well are +classified as “suspended well costs” until we have had sufficient time to +conduct additional completion or testing operations to evaluate the pertinent +geological and engineering data obtained. At the time when we are +able to make a final determination of a well’s productive status, the same well +is removed from the suspended well status and the proper accounting treatment is +recorded. At December 31, 2008, suspended well costs included in oil +and gas properties on our consolidated balance sheet were $1.2 +million. See Note 4 , Properties and +Equipment . +The +acquisition costs of unproved properties are capitalized when incurred, until +such properties are transferred to proved properties or charged to expense when +expired, impaired or amortized. Unproved oil and gas properties with +individually significant acquisition costs are periodically assessed, and any +impairment in value is charged to exploratory expense. The amount of +impairment recognized on unproved properties which are not individually +significant is determined by amortizing the costs of such properties within +appropriate fields based on our historical experience, acquisition dates and +average lease terms. Impairment costs are recorded in the statements +of operations as a component of exploration expense and were as follows for each +of the periods indicated: +2008 +2007 +2006 +(in +thousands) +Individually +significant unproved properties (1) +$ +9,165 +$ +1,484 +$ +473 +Insignificant +unproved properties +3,633 +1,786 +157 +Total +$ +12,798 +$ +3,270 +$ +630 +__________ +(1) +2007 +includes liquidated damages of $1.1 million related to the abandonment of +an exploration agreement with an unaffiliated +party. +The +valuation of unproved properties is subjective and requires us to make estimates +and assumptions which, with the passage of time, may prove to be materially +different from actual realizable values. +F-11 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +In +accordance with SFAS No. 144, Accounting for the Impairment or +Disposal of Long-Lived Assets , we assess our oil and gas properties for +possible impairment quarterly by comparing net capitalized costs to estimated +undiscounted future net cash flows on a field-by-field basis using estimated +production based upon prices at which we reasonably estimate the commodity to be +sold. The estimates of future prices may differ from current market +prices of oil and natural gas. Any downward revisions in estimates to +our reserve quantities, expectations of falling commodity prices or rising +operating costs could result in a reduction in undiscounted future net cash +flows and an impairment of our oil and gas properties. If net +capitalized costs exceed undiscounted future net cash flows, the measurement of +impairment is based on estimated fair value which would consider future +discounted cash flows. We recognized impairment losses on proved oil +and gas properties of $12.8 million in 2008, consisting of $7.5 million related +to our properties in the Fort Worth Basin, $3 million in our Bakken Field in +North Dakota and $2.3 million in our Nesson Field also in North +Dakota. In 2006, we recorded an impairment loss of $1.5 million in +our Nesson Field. Impairment charges related to our oil and gas +properties are included in our statements of operations as a component of +exploration expense. No impairments related to proved oil and natural gas +properties were recorded in 2007. +Upon sale +or retirement of significant portions of or complete fields of depreciable or +depletable property, the net book value thereof, less proceeds or salvage value, +is credited or charged to income. Upon sale of individual wells, the +proceeds are credited to property costs. +Other +Property and Equipment. +The +following table sets forth the estimated useful lives of our other property and +equipment. +Pipelines +and related facilities +10 +- 17 years +Transportation +and other equipment +3 - +20 years +Buildings +30 +- 40 years +Pipelines, Transportation Equipment +and Other Equipment . Pipelines, transportation equipment and +other equipment are carried at cost. Depreciation is provided +principally on the straight-line method over the assets estimated useful +lives. In accordance with SFAS No. 144 , Accounting for the Impairment or +Disposal of Long-Lived Assets , long-lived assets, such as property, plant +and equipment, are reviewed for impairment whenever events or changes in +circumstances indicate that the carrying amount of an asset may not be +recoverable. Recoverability of assets to be held and used is measured +by a comparison of the carrying amount of an asset to estimated undiscounted +future cash flows expected to be generated by the asset. If the +carrying amount of an asset exceeds our estimated future cash flows, an +impairment charge is recognized in the amount by which the carrying amount of +the asset exceeds the fair value of the asset. No impairments were +recorded in 2008, 2007or 2006. +Buildings. Buildings +are carried at cost and depreciated on the straight-line method over their +estimated useful lives. +Maintenance +and repairs on other property and equipment are charged to expense as +incurred. Major renewals and improvements are +capitalized. Upon the sale or other disposition of assets, the cost +and related accumulated depreciation, depletion and amortization are removed +from the accounts, the proceeds are applied thereto and any resulting gain or +loss is reflected in income. +Total +depreciation expense related to other property and equipment was $7.6 million, +$4.3 million and $2 million in 2008, 2007 and 2006, respectively. +Capitalized +Interest +Interest +costs are capitalized as part of the historical cost of acquiring +assets. Oil and gas investments in unproved properties and major +development projects, on which DD&A expense is not currently recorded and on +which exploration or development activities are in progress, qualify for +capitalization of interest. Major construction projects also qualify +for interest capitalization until the asset is ready for +service. Capitalized interest is calculated by multiplying our +weighted-average interest rate on our debt outstanding by the qualifying +costs. Interest capitalized may not exceed gross interest expense for +the period. As the qualifying asset is moved to the DD&A pool, +the related capitalized interest is also transferred and is amortized over the +useful life of the asset. Interest costs of $2.6 million, $3 million +and $1.6 million were capitalized in 2008, 2007 and 2006, +respectively. +F-12 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Production +Tax Liability +Production +tax liability represents estimated taxes, primarily severance and property, to +be paid to the states and counties in which we produce oil and +gas. Our share of these taxes is expensed to oil and gas production +and well operations cost. +Advances +for Future Drilling Contracts +Advances +for future drilling contracts represent funds received from our sponsored +drilling partnerships for drilling activities which have not been completed, a +portion of which will be recognized as revenue in accordance with our revenue +recognition policies. The amount advanced and outstanding as of +December 31, 2008, are primarily related to the drilling partnership sponsored +in August 2007 and represents the remaining costs to finish the wells, primarily +reclamation. No partnership was sponsored in 2008. +Income +Taxes +We +account for income taxes under the asset and liability method. We +recognize deferred tax assets and liabilities for the future tax consequences +attributable to differences between the financial statement carrying amounts of +existing assets and liabilities and their respective tax +bases. Deferred tax assets and liabilities are measured using enacted +tax rates expected to apply to taxable income in the years in which those +temporary differences are expected to be recovered or settled. The +effect on deferred tax assets and liabilities of a change in tax rates is +recognized in income in the period that includes the enactment +date. If we determine that it is more likely than not that some +portion or all of the deferred tax assets will not be realized, we record a +valuation allowance thereby reducing the deferred tax assets to what we consider +realizable. No valuation allowance was recorded at December 31, 2008 +or 2007. +Asset +Retirement Obligations +We +account for asset retirement obligations by recording the fair value of our +plugging and abandonment obligations when incurred, which is at the time the +well is completely drilled. Upon initial recognition of an asset +retirement obligation, we increase the carrying amount of the long-lived asset +by the same amount as the liability. Over time, the liabilities are +accreted for the change in their present value, through charges to oil and gas +production and well operations costs. The initial capitalized costs +are depleted over the useful lives of the related assets, through charges to +depreciation, depletion and amortization. If the fair value of the +estimated asset retirement obligation changes, an adjustment is recorded to both +the asset retirement obligation and the asset retirement +cost. Revisions in estimated liabilities can result from revisions of +estimated inflation rates, escalating retirement costs and changes in the +estimated timing of settling asset retirement obligations. See Note 7 , Asset Retirement Obligations , +for a reconciliation of asset retirement obligation activity. +Minority +Interest in Consolidated Limited Liability Company +In May +2007, we contributed $0.8 million for a 50% interest in WWWV, LLC (“LLC”), a +limited liability company for which we serve as the managing +member. One-sixth of the entity is owned by a member of our Board of +Directors, who paid the same unit price for his interest as was paid by us and +unrelated third parties for such interests in the LLC. The LLC's only +asset is an aircraft and the LLC was formed for the purpose of owning and +operating the aircraft. +The +minority interest portion of pre-tax expense incurred by and belonging to the +minority interest holders of the consolidated limited liability company is not +material and is included in our consolidated statement of operations as an +offset to DD&A expense. +Retirement +of Treasury Shares +We +have historically retired all treasury share purchases, with the exception of +shares purchased in accordance with our non-employee deferred compensation plan +for non-employee directors, see Note 9 , Common Stock . As +treasury shares are retired, we charge any excess of cost over the par value +entirely to additional paid-in-capital, to the extent we have amounts in +paid-in-capital, with any remaining excess cost being charged to retained +earnings. +Revenue +Recognition +Oil and natural gas +sales . Sales of oil are recognized when persuasive evidence of +a sales arrangement exists, the oil is verified as produced and is delivered to +a purchaser, collection of revenue from the sale is reasonably assured and the +sales price is determinable. We are currently able to sell all the +oil that we can produce under existing sales contracts with petroleum refiners +and marketers. We do not refine any of our oil +production. Our crude oil production is sold to purchasers at or near +our wells under short-term purchase contracts at prices and in accordance with +arrangements that are customary in the oil industry. +F-13 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Sales of +natural gas are recognized when natural gas has been delivered to a custody +transfer point, persuasive evidence of a sales arrangement exists, the rights +and responsibility of ownership pass to the purchaser upon delivery, collection +of revenue from the sale is reasonably assured and the sales price is fixed or +determinable. Natural gas is sold by us under contracts with terms +ranging from one month to three years. Virtually all of our contract +pricing provisions are tied to a market index, with certain adjustments based +on, among other factors, whether a well delivers to a gathering or transmission +line, quality of natural gas and prevailing supply and demand conditions, so +that the price of the natural gas fluctuates to remain competitive with other +available natural gas supplies. As a result, our revenues from the +sale of natural gas will suffer if market prices decline and benefit if they +increase. We believe that the pricing provisions of our natural gas +contracts are customary in the industry. +We +currently use the “net-back” method of accounting for transportation +arrangements of our natural gas sales. We sell gas at the wellhead +and collect a price and recognize revenues based on the wellhead sales price +since transportation costs downstream of the wellhead are incurred by the +customers and reflected in the wellhead price. +Natural gas marketing +activities . Natural gas marketing is reported on the gross +accounting method, based on the nature of the agreements between RNG, our +suppliers and our customers. RNG, our marketing subsidiary, purchases +gas from many small producers and bundles the gas together to sell in larger +amounts to purchasers of natural gas for a price advantage. RNG has +latitude in establishing price and discretion in supplier and purchaser +selection. Natural gas marketing revenues and expenses reflect the +full cost and revenue of those transactions because RNG takes title to the gas +it purchases from the various producers and bears the risks and rewards of that +ownership. Both the realized and unrealized gains and losses of the +RNG commodity based derivative transactions for natural gas marketing activities +are included in gas sales from marketing activities or cost of gas marketing +activities, as applicable. +Oil and gas well +drilling . Our drilling segment recognizes revenue from +drilling contracts with sponsored drilling programs using the percentage of +completion method based upon the percentage of contract costs incurred to date +to the estimated total contract costs for each contract. We utilize +this method since reasonably dependable estimates of the total estimated costs +can be made and recognized revenues are subject to revisions as a contract +progresses, the term of which can range from three to twelve +months. We have offered our drilling services under two types of +contractual arrangements, cost-plus or footage-based service contracts, which +result in differing risk and reward relationships, and consequently, different +revenue reporting policies pursuant to Emerging Issues Task Force (“EITF”) Issue +No. 99-19, Reporting Revenue +Gross as a Principal versus Net as an Agent . +The first +cost-plus drilling service arrangement was entered into in late 2005 with +drilling activity commencing in the first quarter of 2006. Due to the +fixed-fee-percentage nature of our revenues from these services, we have +determined that, in substance, we are acting as an agent, without risk of loss +during the performance of the drilling activities. Accordingly, our +services provided under the cost-plus drilling agreements are reported on a net +basis. We entered into our second and third cost-plus drilling +arrangements in September 2006 and August 2007 and commenced drilling +immediately. +Footage-based +contracts provide for the drilling, completion and equipping of wells at footage +rates and are generally completed within nine to twelve months after the +commencement of drilling. We provide geological, engineering, and +drilling supervision on the drilling and completion process and use +subcontractors to perform drilling and completion services and accordingly we +have the risk of loss in performing services under these +arrangements. Accordingly, we report revenue under these agreements +gross of related expenses. Anticipated losses, if any, on uncompleted +contracts are recorded at the time that the estimated total costs exceed the +estimated total contract revenue. At December 31, 2007, included as a +component of other current liabilities on the consolidated balance sheets, we +had recorded a loss contract reserve of $0.2 million. No loss +contract reserve was recorded as of December 31, 2008. +Well operations and pipeline +income . Well operations and pipeline income are recognized +when persuasive evidence of an arrangement exists, services have been rendered, +collection of revenues is reasonably assured and the sales price is fixed or +determinable. We are paid a monthly operating fee for each well we +operate and natural gas transported for outside owners including the limited +partnerships we sponsored. The fee covers monthly operating and +accounting costs, insurance and other recurring costs. We may also +receive additional compensation for special non-recurring activities, such as +reworks and recompletions. +F-14 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Stock-Based +Compensation +On +January 1, 2006, we adopted SFAS No. 123 (revised 2004), Share-Based Payment (“SFAS +No. 123R”), to account for stock-based compensation. SFAS No. 123R +eliminated the use of Accounting Principles Board Opinion (“APB”) No. 25, Accounting for Stock Issued to +Employees , and the intrinsic value method of accounting for equity +compensation and requires us to recognize the cost of employee services received +in exchange for awards of equity instruments based on fair value at the date of +grant in our financial statements. We elected to use the modified +prospective method for adoption, and accordingly, prior period financial +statements have not been restated. For all unvested options and other +equity based awards outstanding as of January 1, 2006, the previously measured +but unrecognized compensation expense, based on the fair value at the original +grant date, will be recognized in the financial statements over the remaining +requisite service period for each separately vesting portion. For +equity-based compensation awards granted or modified subsequent to January 1, +2006, compensation expense, based on the fair value on the date of grant or +modification, will be recognized in the financial statements on a straight-line +basis over the vesting period for the entire award. To the extent +compensation cost relates to employees directly involved in oil and natural gas +acquisition, exploration and development activities, such amounts are +capitalized to properties and equipment. Amounts not capitalized to +properties and equipment are recognized in the appropriate cost and expense line +item in the statement of operations. No amounts for stock-based +compensation were capitalized in 2008, 2007 and 2006. +Earnings +Per Share +Basic +earnings per common share (“EPS”) is computed by dividing net income (the +numerator) by the weighted-average number of common shares outstanding for the +period (the denominator). Diluted EPS is similarly computed except +that the denominator includes the effect, using the treasury stock method, of +our outstanding stock options, unamortized portion of restricted stock and +shares held pursuant to our non-employee director deferred compensation plan, if +including such potential shares of common stock is dilutive. +The +following is a reconciliation of the basic and diluted weighted-average shares +outstanding for the years ended December 31: +2008 +2007 +2006 +(in +thousands, except per share data) +Weighted +average common shares outstanding - basic +14,736 +14,744 +15,660 +Dilutive +effect of share-based compensation: (1) +Unamortized +portion of restricted stock +71 +44 +22 +Stock +options +35 +48 +55 +Non +employee director deferred compensation +6 +5 +4 +Weighted +average common and common share equivalents outstanding - +diluted +14,848 +14,841 +15,741 +(1) +Weighted average common share equivalents excluded from diluted +earnings per share due to their anti-dilutive affect: +Unamortized +portion of restricted stock +73 +18 +- +Stock +options +- +- +24 +Total +anti-dilutive common share equivalents +73 +18 +24 +F-15 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Recent +Accounting Standards +Recently Adopted Accounting +Standards +We +adopted the provisions of Statement of SFAS No. 157, Fair Value Measurements , +effective January 1, 2008. SFAS No. 157 defines fair value, +establishes a framework for measuring fair value and expands disclosures related +to fair value measurements. SFAS No. 157 applies broadly to financial and +nonfinancial assets and liabilities that are measured at fair value under other +authoritative accounting pronouncements, but does not expand the application of +fair value accounting to any new circumstances. In February 2008, the +Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“FSP”) +FAS No. 157-2, Effective Date +of FASB Statement No. 157 , which delays the effective date of SFAS No. +157 by one year (to January 1, 2009) for nonfinancial assets and liabilities, +except those that are recognized or disclosed at fair value in the financial +statements on a recurring basis (at least annually). Nonfinancial +assets and liabilities for which we have not applied the provisions of SFAS No. +157 include those initially measured at fair value, including our asset +retirement obligations. As of the adoption date, we have applied the +provisions of SFAS No. 157 to our recurring measurements and the impact was not +material to our underlying fair values and no amounts were recorded relative to +the cumulative effect of a change in accounting. We are currently +evaluating the potential effect that the nonfinancial assets and liabilities +provisions of SFAS No. 157 will have on our financial statements when adopted in +2009. See Note 2 , Fair Value of Financial +Instruments . +In +October 2008, the FASB issued FSP No. FAS 157-3, Determining the Fair Value of a +Financial Asset in a Market That Is Not Active , which applies to +financial assets within the scope of accounting pronouncements that require or +permit fair value measurements in accordance with SFAS No. 157. This FSP +clarifies the application of SFAS No. 157 in a market that is not active and +defines additional key criteria in determining the fair value of a financial +asset when the market for that financial asset is not active. FSP No. +FAS 157-3 was effective upon issuance and did not have a material impact on our +financial statements. +In +February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial +Assets and Financial Liabilities . SFAS No. 159 permits +entities to choose to measure, at fair value, many financial instruments and +certain other items that are not currently required to be measured at fair +value. The objective is to improve financial reporting by providing +entities with the opportunity to mitigate volatility in reported earnings caused +by measuring related assets and liabilities differently without having to apply +complex hedge accounting provisions. SFAS No. 159 establishes +presentation and disclosure requirements designed to facilitate comparisons +between entities that choose different measurement attributes for similar types +of assets and liabilities. The statement will be effective as of the +beginning of an entity's first fiscal year beginning after November 15, +2007. We have not elected to measure additional financial assets and +liabilities at fair value. +In April +2007, the FASB issued FSP No. FIN 39-1, Amendment of FASB Interpretation No. +39 (“FIN 39-1”), to amend certain portions of Interpretation +39. FIN 39-1 replaces the terms “conditional contracts” and “exchange +contracts” in Interpretation 39 with the term “derivative instruments” as +defined in Statement 133. FIN 39-1 also amends Interpretation 39 to +allow for the offsetting of fair value amounts for the right to reclaim cash +collateral or receivable, or the obligation to return cash collateral or +payable, arising from the same master netting arrangement as the derivative +instruments. FIN 39-1 applies to fiscal years beginning after +November 15, 2007, with early adoption permitted. The January 1, +2008, adoption of FSP FIN 39-1 had no impact on our financial +statements. +In June +2006, the FASB issued EITF No. 06-3, How Taxes Collected from Customers +and Remitted to Governmental Authorities Should be Presented in the Income +Statement (That Is, Gross versus Net Presentation) . EITF 06-3 +addresses the income statement presentation of any tax collected from customers +and remitted to a government authority and concludes that the presentation of +taxes on either a gross basis or a net basis is an accounting policy decision +that should be disclosed pursuant to APB No. 22, Disclosures of Accounting +Policies . For taxes that are reported on a gross basis +(included in revenues and costs), EITF 06-3 requires disclosure of the amounts +of those taxes in interim and annual financial statements, if those amounts are +significant. EITF 06-3 became effective for interim and annual +reporting periods beginning after December 15, 2006. The adoption of +the standard, effective January 1, 2007, did not have a significant effect on +our consolidated financial statements. Our existing accounting +policy, which was not changed upon the adoption of EITF 06-3, is to present +taxes within the scope of EITF 06-3 on a net basis. +In July +2006, the FASB issued FIN No. 48, Accounting for Uncertainty in Income +Taxes - an Interpretation of FASB Statement 109 , which prescribes a +comprehensive model for accounting for uncertainty in tax +positions. FIN No. 48 provides that the tax effects from an uncertain +tax position can be recognized in the financial statements, only if the position +is more likely than not of being sustained on audit by the Internal Revenue +Service (“IRS”), based on the technical merits of the position. We +adopted the provisions of FIN No. 48 effective January 1, 2007. The +cumulative effect of applying the provisions of FIN No. 48 has been accounted +for as an adjustment to retained earnings in the first quarter of +2007. The adoption of FIN No. 48 resulted in a $0.3 million +cumulative effect adjustment (see Note 5 , Income Taxes , for further +discussion). +F-16 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +In May +2007, the FASB issued FASB Staff Position FIN No. 48-1, Definition of Settlement in FASB +Interpretation No. 48 (“FIN No. 48-1”). FIN No. 48-1 amends +FIN No. 48 to provide guidance on how an entity should determine whether a tax +position is effectively settled for the purpose of recognizing previously +unrecognized tax benefits. The term “effectively settled” replaces +the term “ultimately settled” when used to describe recognition, and the terms +“settlement” or “settled” replace the terms “ultimate settlement” or “ultimately +settled” when used to describe measurement of a tax position under FIN No. +48. FIN No. 48-1 clarifies that a tax position can be effectively +settled upon the completion of an examination by a taxing authority without +being legally extinguished. For tax positions considered effectively +settled, an entity would recognize the full amount of tax benefit, even if the +tax position is not considered more likely than not to be sustained based solely +on the basis of its technical merits and the statute of limitations remains +open. The adoption of FIN No. 48-1, effective January 1, 2007, did +not have an incremental effect on our consolidated financial +statements. +In +September 2006, the Securities and Exchange Commission (“SEC”) issued Staff +Accounting Bulletin (“SAB”) No. 108, Considering the Effects of Prior +Year Misstatements when Quantifying Misstatements in Current Year Financial +Statements . SAB No. 108 provides guidance on how the effects +of prior year misstatements should be considered in quantifying misstatements in +the current year financial statements. SAB No. 108 requires +registrants to quantify misstatements using both the income statement +(“rollover”) and balance sheet (“iron curtain”) approach and evaluate whether +either approach results in a misstatement that, when all relevant quantitative +and qualitative factors are considered, is material. Historically, we +evaluated uncorrected misstatements using the “rollover” method which resulted +in an accumulation of quantitatively and qualitatively immaterial misstatements +to our consolidated financial statements. SAB No. 108 provides for a +one time transitional adjustment to retained earnings for errors which were not +deemed material to prior year financial statements, but which is material under +guidance of SAB No. 108. We adopted SAB No. 108 during the fourth +quarter of 2006 and recorded a one-time adjustment to reduce retained earnings +by $1.0 million. +In +December 2004, the FASB issued SFAS No. 123(R), Share-Based +Payment . In March 2005, the SEC issued Staff Accounting +Bulletin (“SAB”) No. 107, Share-Based Payment , +regarding the interaction between SFAS No. 123(R) and certain SEC rules and +regulations. Effective January 1, 2006, we adopted SFAS No. 123(R). +We elected to use the modified prospective method for adoption, which requires +compensation expense to be recognized in the statement of operations for all +unvested stock options and other equity-based compensation beginning in the +first quarter of adoption. Prior to the adoption of SFAS No. 123(R), +we followed the intrinsic value method in accordance with APB No. 25 (as +amended) to account for employee stock-based compensation. The +adoption of SFAS No. 123(R) required the unamortized stock award recorded under +APB No. 25 related to stock-based compensation awards as of January 1, 2006, in +the amount of $0.8 million to be eliminated against additional +paid-in-capital. See Stock-Based Compensation +policy above and Note 9, Common Stock , for further +discussion of the Company's accounting for share-based compensation +awards. +Recently Issued Accounting +Standards +In +December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (“SFAS +No. 141R”). SFAS No. 141R requires an acquirer to recognize the +assets acquired, the liabilities assumed and any noncontrolling interest in the +acquiree at their acquisition-date fair values. SFAS No. 141R also +requires disclosure of the information necessary for investors and other users +to evaluate and understand the nature and financial effect of the business +combination. Additionally, SFAS No. 141R requires that +acquisition-related costs be expensed as incurred. The provisions of +SFAS No. 141R will become effective for acquisitions completed on or after +January 1, 2009; however, the income tax provisions of SFAS No. 141R will become +effective as of that date for all acquisitions, regardless of the acquisition +date. SFAS No. 141R amends SFAS No. 109, Accounting for Income Taxes , +to require the acquirer to recognize changes in the amount of its deferred tax +benefits recognizable due to a business combination either in income from +continuing operations in the period of the combination or directly in +contributed capital, depending on the circumstances. SFAS No. 141R +further amends SFAS No. 109 and FIN 48, Accounting for Uncertainty in Income +Taxes , to require, subsequent to a prescribed measurement period, changes +to acquisition-date income tax uncertainties to be reported in income from +continuing operations and changes to acquisition-date acquiree deferred tax +benefits to be reported in income from continuing operations or directly in +contributed capital, depending on the circumstances. Upon our +adoption of SFAS No. 141R effective January 1, 2009, we will recognize expense +of $1.4 million in deferred acquisition related costs. +In +December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in +Consolidated Financial Statements—An Amendment of ARB No. +51 . SFAS No. 160 states that accounting and reporting for +minority interests will be recharacterized as non-controlling interests and +classified as a component of equity. Additionally, SFAS No. 160 +establishes reporting requirements that provide sufficient disclosures which +clearly identify and distinguish between the interests of the parent and the +interests of the non-controlling owners. SFAS No. 160 is effective as +of the beginning of an entity’s first fiscal year beginning after December 15, +2008. We are evaluating the impact that SFAS No. 160 will have, if +any, on our consolidated financial statements and related disclosures when it is +adopted in 2009. +F-17 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +In March +2008, the FASB issued SFAS No. 161, Disclosures about Derivative +Instruments and Hedging Activities—An Amendment of FASB Statement No. +133 , which changes the disclosure requirements for derivative instruments +and hedging activities. Enhanced disclosures are required to provide +information about (a) how and why an entity uses derivative instruments, (b) how +derivative instruments and related hedged items are accounted for under +Statement 133 and its related interpretations and (c) how derivative instruments +and related hedged items affect an entity’s financial position, financial +performance and cash flows. SFAS No. 161 is effective for financial +statements issued for fiscal years and interim periods beginning after November +15, 2008, with early application encouraged. As SFAS No. 161 is +disclosure related, we do not expect its adoption to have a material impact on +our financial statements. +In +January 2009, the SEC published its final rule, Modernization of Oil and Gas +Reporting , which modifies the SEC’s reporting and disclosure rules for +oil and natural gas reserves. The most notable changes of the final +rule include the replacement of the single day period-end pricing to value oil +and natural gas reserves to a 12-month average of the first day of the month +price for each month within the reporting period. The final rule also +permits voluntary disclosure of probable and possible reserves, a disclosure +previously prohibited by SEC rules. The revised reporting and +disclosure requirements are effective for our Form 10-K for the year ended +December 31, 2009. Early adoption is not permitted. We are +evaluating the impact that adoption of this final rule will have on our +consolidated financial statements, related disclosure and management’s +discussion and analysis. +NOTE +2 – FAIR VALUE OF FINANCIAL INSTRUMENTS +Derivative Financial +Instruments . +Determination of fair +value . We measure fair value based upon quoted market +prices, where available. Our valuation determination includes: (1) +identification of the inputs to the fair value methodology through the review of +counterparty statements and other supporting documentation, (2) determination of +the validity of the source of the inputs, (3) corroboration of the original +source of inputs through access to multiple quotes, if available, or other +information and (4) monitoring changes in valuation methods and +assumptions. The methods described above may produce a fair value +calculation that may not be indicative of future fair values. Our +valuation determination also gives consideration to our nonperformance risk on +our own liabilities as well as the credit standing of our +counterparties. We primarily use two investment grade financial +institutions as our counterparties to our derivative contracts. We +have evaluated the credit risk of our derivative assets from our counterparties +using relevant credit market default rates, giving consideration to amounts +outstanding for each counterparty and the duration of each outstanding +derivative position. Based on our evaluation, we have determined that +the impact of the nonperformance of our counterparties on the fair value of our +derivative instruments is insignificant. As of December 31, +2008, no valuation allowance was recorded. Furthermore, while +we believe these valuation methods are appropriate and consistent with that used +by other market participants, the use of different methodologies, or +assumptions, to determine the fair value of certain financial instruments could +result in a different estimate of fair +value. +Valuation +hierarchy . SFAS No. 157 establishes a fair value hierarchy +that requires an entity to maximize the use of observable inputs and minimize +the use of unobservable inputs when measuring fair value. The +valuation hierarchy is based upon the transparency of inputs to the valuation of +an asset or liability as of the measurement date, giving the highest priority to +quoted prices in active markets (Level 1) and the lowest priority to +unobservable data (Level 3). In some cases, the inputs used to +measure fair value might fall in different levels of the fair value +hierarchy. The lowest level input that is significant to a fair value +measurement in its entirety determines the applicable level in the fair value +hierarchy. Assessing the significance of a particular input to the +fair value measurement in its entirety requires judgment, considering factors +specific to the asset or liability. The three levels of inputs that +may be used to measure fair value are defined as: +Level 1 – Quoted prices +(unadjusted) in active markets for identical assets or +liabilities. Instruments included in Level 1 consist of our commodity +derivatives for New York Mercantile Exchange (“NYMEX”)-based natural gas +swaps. +Level 2 – Inputs other than +quoted prices included within Level 1 that are either directly or indirectly +observable for the asset or liability, including (i) quoted prices for similar +assets or liabilities in active markets, (ii) quoted prices for identical or +similar assets or liabilities in inactive markets, (iii) inputs other than +quoted prices that are observable for the asset or liability and (iv) inputs +that are derived from observable market data by correlation or other +means. +Level 3 – Unobservable inputs +for the asset or liability, including situations where there is little, if any, +market activity for the asset or liability. Instruments included in +Level 3 consist of our commodity derivatives for Colorado Interstate Gas (“CIG”) +and Panhandle Eastern Pipeline (“PEPL”)-based natural gas swaps, oil swaps, +natural gas basis protection swaps, oil and natural gas options, and physical +sales and purchases. +F-18 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +The +following table presents, for each hierarchy level, our assets and liabilities, +including both current and non-current portions, measured at fair value on a +recurring basis as of December 31, 2008: +Level +1 +Level +3 +Total +(in +thousands) +Assets: +Commodity +based derivatives +$ +19,359 +$ +144,677 +$ +164,036 +Liabilities: +Commodity +based derivatives +(658 +) +(9,828 +) +(10,486 +) +Net +fair value of commodity based derivatives +$ +18,701 +$ +134,849 +$ +153,550 +The +following table sets forth a reconciliation of our Level 3 fair value +measurements: +Year +Ended +December 31, +2008 +(in +thousands) +Fair +value, net asset (liability), beginning of period +$ +(2,368 +) +Unrealized +gains (losses) included in statement of operations line +item: +Cost +of natural gas marketing activities +(1,079 +) +Unrealized +gains (losses) included in balance sheet line item: +Accounts +receivable - affiliates +821 +Accounts +payable - affiliates +35,338 +Purchases +Oil +and gas sales activities +105,214 +Sales +from natural gas marketing activities +438 +Cost +of natural gas marketing activities +(4,590 +) +Settlements +Oil +and gas sales activities +549 +Sales +from natural gas marketing activities +(129 +) +Cost +of natural gas marketing activities +655 +Fair +value, net asset (liability), end of period +$ +134,849 +Change +in unrealized gains (losses) relating to assets (liabilities) still held +as of December 31, 2008, included in statement of operations line +item: +Oil +and gas price risk management, net +$ +105,214 +Sales +from natural gas marketing activities +438 +Cost +of natural gas marketing activities +(5,669 +) +$ +99,983 +See Note 3 , Derivative Financial +Instruments , for additional disclosure related to our derivative +financial instruments. +Non-Derivative Financial Assets and +Liabilities . +The +carrying values of the financial instruments comprising cash and cash +equivalents, restricted cash, accounts receivable and accounts payable +approximate fair value due to the short-term maturities of these +instruments. +F-19 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +The +portion of our long-term debt related to our credit facility, approximates fair +value due to the variable nature of its related interest rate. We +estimate the fair value of the portion of our long-term debt related to our +senior notes to be approximately $127 million or approximately 62.5% of par +value as of December 31, 2008. We determined this valuation based +upon measurements of trading activity and quotes provided by brokers and traders +participating in the trading of the securities. +NOTE +3 – DERIVATIVE FINANCIAL INSTRUMENTS +We +are exposed to the effect of market fluctuations in the prices of oil and +natural gas as they relate to our oil and natural gas sales and natural gas +marketing segments. Price risk represents the potential risk of loss +from adverse changes in the market price of oil and natural gas +commodities. We employ established policies and procedures to manage +the risks associated with these market fluctuations using commodity +derivatives. Our policy prohibits the use of oil and natural gas +derivative instruments for speculative purposes. +Concentration of +Credit Risk . A significant portion of our +liquidity is concentrated in derivative instruments that enable us to manage a +portion of our exposure to price volatility from producing oil and natural +gas. These arrangements expose us to credit risk from our +counterparties. These contracts consist of fixed price swaps, basis +swaps and collars. We primarily use two investment grade financial +institutions as our counterparties to our derivative contracts who are also +major lenders in our credit facility arrangement. We have evaluated +the credit risk of our derivative assets from our counterparties using relevant +credit market default rates, giving consideration to amounts outstanding for +each counterparty and the duration of each outstanding derivative +position. Based on our evaluation, we have determined that the impact +of the nonperformance of our counterparties on the fair value of our derivative +instruments is insignificant. As of December 31, 2008, no +valuation allowance was recorded. +As of +December 31, 2008, the following counterparties expose us to credit +risk. +Fair +Value of Derivatives +As +of December 31, 2008 +Counterparty +Name +Assets +Liabilities +Net +(in +thousands) +JPMorgan +Chase Bank, N.A. +(1) +$ +83,291 +$ +(322 +) +$ +82,969 +BNP Paribas +(1) +79,316 +- +79,316 +Various +(2) +1,429 +(10,164 +) +(8,735 +) +Total +$ +164,036 +$ +(10,486 +) +$ +153,550 +(1) +Major lender in our credit facility, see Note 6. +(2) +Represents a total of 48 counterparties, includes two lenders in our +credit faciity. +Economic Hedging +Strategies . Our results of operations and operating cash flows +are affected by changes in market prices for oil and natural gas. To +mitigate a portion of the exposure to adverse market changes, we have entered +into various derivative contracts. As of December 31, 2008, our oil +and natural gas derivative instruments were comprised of futures, swaps, basis +protection swaps and collars. These instruments generally consist of +NYMEX-traded natural gas futures contracts and option contracts for Appalachian +and Michigan production, PEPL-based contracts for NECO production and CIG-based +contracts for other Colorado production and NYMEX-based crude oil swaps for our +Colorado oil production. +· +For +swap instruments, we receive a fixed price for the hedged commodity and +pay a floating market price to the counterparty. The +fixed-price payment and the floating-price payment are netted, resulting +in a net amount due to or from the +counterparty. +· +Basis +protection swaps are arrangements that guarantee a price differential for +natural gas from a specified delivery point. For CIG basis +protection swaps, which have negative differentials to NYMEX, we receive a +payment from the counterparty if the price differential is greater than +the stated terms of the contract and pay the counterparty if the price +differential is less than the stated terms of the +contract. +· +Collars +contain a fixed floor price (put) and ceiling price (call). If +the market price exceeds the call strike price or falls below the fixed +put strike price, we receive the fixed price and pay the market +price. If the market price is between the call and the put +strike price, no payments are due from either +party. +F-20 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +We +purchase puts and set collars and swaps for our own and affiliated partnerships’ +production to protect against price declines in future periods while retaining +much of the benefits of price increases. RNG enters into fixed-price +physical purchase and sale agreements that are derivative +contracts. In order to offset these fixed-price physical derivatives, +we enter into financial derivative instruments that have the effect of locking +in the prices we will receive or pay for the same volumes and period, offsetting +the physical derivative. While these derivatives are structured to +reduce our exposure to changes in price associated with the derivative +commodity, they also limit the benefit we might otherwise have received from +price changes in the physical market. We believe our derivative +instruments continue to be effective in achieving the risk management objectives +for which they were intended. +Validation +of a contract’s fair value is performed internally and while we use common +industry practices to develop our valuation techniques, changes in our pricing +methodologies or the underlying assumptions could result in significantly +different fair values. At December 31, 2008 and 2007, we had the +following open commodity based derivative instruments designed as an economic +hedge for a portion of our oil and natural gas production for periods after +December 2008: +Year +Ended December 31, +2008 +2007 +(in +thousands) +Derivative +net assets (liabilities) +Oil +and gas sales activities: +Fixed-price +natural gas swaps +$ +55,747 +$ +- +Natural +gas collars +50,752 +2,969 +Natural +gas basis protection swaps +(4,292 +) +- +Natural +gas floors +- +105 +Fixed-price +oil swaps +51,508 +(5,097 +) +153,715 +(2,023 +) +Natural +gas marketing activities: +Fixed-price +natural gas swaps +(159 +) +649 +Natural +gas basis protection swaps +(13 +) +- +Natural +gas collars +7 +- +(165 +) +649 +Estimated +net fair value of derivative instruments +$ +153,550 +$ +(1,374 +) +In +addition to including the gross assets and liabilities related to our share of +oil and gas production, the above table and our consolidated balance sheets +include the gross assets and liabilities related to derivative contracts we +entered into and those that we allocate to our affiliated partnerships as the +managing general partner. See Note 11 , Transactions with Affiliates , +for a discussion of our allocation methodology. For those derivative +contracts which we have allocated to the affiliated partnerships, we have on our +consolidated balance sheets a corresponding payable to and receivable from the +partnerships of $37.5 million and $1.6 million, respectively, as of December 31, +2008, and $1 million and $2.4 million as of December 31, 2007, +respectively. +F-21 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +The +following table identifies the fair value of commodity based derivatives as +classified in our consolidated balance sheets. +December +31, +2008 +2007 +(in +thousands) +Classification +in the Condensed Consolidated Balance Sheets: +Fair +value of derivatives - current asset +$ +116,881 +$ +4,817 +Other +assets - long-term asset +47,155 +193 +164,036 +5,010 +Fair +value of derivatives - current liability +4,766 +6,291 +Other +liabilities - long-term liability +5,720 +93 +10,486 +6,384 +Net +fair value of commodity based derivatives - asset +(liability) +$ +153,550 +$ +(1,374 +) +The +following changes in the fair value of commodity based derivatives are reflected +in our consolidated statements of operations. +Year +Ended December 31, +2008 +2007 +2006 +Statement +of operations line item +Realized +Unrealized +Realized +Unrealized +Realized +Unrealized +(in +thousands, gain/(loss)) +Oil +and gas price risk management gain (loss), net +(1) +$ +9,487 +$ +118,351 +$ +7,173 +$ +(4,417 +) +$ +1,895 +$ +7,252 +Sales +from natural gas marketing activities +(2) +(1,882 +) +4,614 +3,870 +(1,736 +) +2,592 +12,291 +Cost +of natural gas marketing activities +(2) +32 +(5,429 +) +(482 +) +1,511 +(1,908 +) +(11,923 +) +__________ +(1) +Includes +realized and unrealized gains and losses on commodity based derivative +instruments related to PDC. +(2) +Includes +realized and unrealized gains and losses on commodity based derivatives +instruments related to RNG only. +NOTE +4 – PROPERTIES AND EQUIPMENT +December +31, +2008 +2007 +(in +thousands) +Properties +and equipment, net: +Oil +and gas properties (successful efforts method of +accounting) +Proved +$ +1,245,316 +$ +953,904 +Unproved +32,768 +41,023 +Total +oil and gas properties +1,278,084 +994,927 +Pipelines +and related facilities +34,067 +22,408 +Transportation +and other equipment +31,693 +23,669 +Land +and buildings +14,570 +11,303 +Construction +in progress +(1) +275 +2,929 +1,358,689 +1,055,236 +Accumulated +DD&A +(325,611 +) +(209,372 +) +$ +1,033,078 +$ +845,864 +(1) At +December 31, 2007 includes costs primarily related to a new integrated oil and +gas financial software system. +F-22 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Suspended +Well Costs +The +following table identifies the capitalized exploratory well costs that are +pending the determination of proved reserves and included in oil and gas +properties on the consolidated balance sheets. +2008 +2007 +2006 +(in +thousands, except for number of wells) +Beginning +balance at January 1 +$ +2,300 +$ +765 +$ +1,918 +Additions +to capitalized exploratory well costs pending the determination of proved +reserves +15,644 +3,953 +12,016 +Reclassifications +to wells, facilities and equipment based on the determination of proved +reserves +(10,259 +) +(878 +) +(13,169 +) +Capitalized +exploratory well costs charged to expense +(6,505 +) +(1,540 +) +- +Ending +balance at December 31 +$ +1,180 +$ +2,300 +$ +765 +Number +of wells pending determination at December 31 +6 +3 +1 +As of +December 31, 2008, none of the wells awaiting the determination of proved +reserves have been capitalized for more than one year after the completion of +drilling. +NOTE +5 - INCOME TAXES +For each +of the years in the three-year period ended December 31, 2008, we utilized our +tax election to currently expense approximately $30 million, $44 million and $55 +million, respectively, of intangible drilling costs (“IDC”). This +election substantially reduced our current tax expense but resulted in a +correspondingly higher deferred tax expense as shown +below. Additionally, in 2006, we had a substantial taxable gain from +the sale of undeveloped oil and gas properties, see Note 13 , Sale of Oil and Gas +Properties . We have chosen to use the favorable deferral +aspects of the Internal Revenue Code (“IRC”) Section 1031 like-kind exchange +(“LKE”) rules to +defer the tax liability on a portion of the gain realized by purchasing +replacement properties, see Note 14 , Acquisitions . Accordingly, +our current and deferred provision for income taxes increased proportionately in +2006 due to the current and deferred tax associated with this large taxable +gain. The components of our tax expense consisted of the +following: +2008 +2007 +2006 +(in +thousands) +Current: +Federal +$ +6,198 +$ +7,579 +$ +54,467 +State +(3,818 +) +1,201 +8,739 +Total +current income taxes +2,380 +8,780 +63,206 +Deferred: +Federal +55,500 +11,074 +74,003 +State +3,579 +1,127 +12,428 +Total +deferred income taxes +59,079 +12,201 +86,431 +Total +income taxes +$ +61,459 +$ +20,981 +$ +149,637 +F-23 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Income +tax expense differed from the amounts computed by applying the U.S. federal +income tax rate of 35%. +2008 +2007 +2006 +(in +thousands) +Computed +"expected" tax +$ +61,169 +$ +18,966 +$ +135,594 +State +income tax, net +5,265 +1,907 +13,744 +Percentage +depletion +(1,150 +) +(624 +) +(545 +) +Domestic +production activities deduction +(249 +) +(374 +) +- +Other +(3,576 +) +1,106 +844 +$ +61,459 +$ +20,981 +$ +149,637 +In order +to reduce current income taxes payable, we elected to expense, for income tax +purposes, a large amount of IDC in each of the three years presented +above. This expensing election reduces our domestic production +activities deduction, which in 2008 and 2007 was statutorily equal to six +percent of our qualified production activity income (“QPAI”), to $0.7 million +and $1.1 million, respectively. In 2006, due to our decision to +expense $55 million of IDC, our domestic production deduction, which in 2006 was +statutorily equal to three percent of QPAI, was zero. In addition, +the amount in “Other” for 2008 was primarily for discrete tax benefit realized +upon the implementation of state tax strategies during the second and third +quarters. The amount in “Other” for 2007 was primarily nondeductible +tax penalties. +The +federal examination of our 2005 and 2006 tax returns is currently ongoing with +no significant adjustments noted as of December 31, 2008. +The tax +effects of temporary differences that give rise to significant portions of the +deferred tax assets and deferred tax liabilities at December 31, 2008 and 2007, +are presented below. +2008 +2007 +(in +thousands) +Deferred +tax assets: +Allowance +for doubtful accounts +$ +205 +$ +138 +Drilling +notes +27 +31 +Allowance +for lease impairment +4,910 +912 +Litigation +allowance +- +578 +Deferred +revenue related to cash withheld for future plugging +cost +1,043 +1,011 +Deferred +compensation +2,846 +2,058 +Asset +retirement obligations +8,519 +7,782 +Unrealized +loss - derivatives +- +703 +Employee +benefits +547 +456 +State +tax credit - carryforward +309 +- +Other +57 +16 +Total +gross deferred tax assets +18,463 +13,685 +Less +valuation allowance +- +- +Deferred +tax assets +18,463 +13,685 +Deferred +tax liabilities: +Properties +and equipment +(165,212 +) +(145,499 +) +Unrealized +gains - derivatives +(44,199 +) +(55 +) +Total +gross deferred tax liabilities +(209,411 +) +(145,554 +) +Net +deferred tax liability +$ +(190,948 +) +$ +(131,869 +) +Classification +in the Consolidated Balance Sheets: +Net +current deferred tax (liabilities) assets* +$ +(28,355 +) +$ +4,621 +Net +non-current deferred tax liability +(162,593 +) +(136,490 +) +Net +deferred tax liability +$ +(190,948 +) +$ +(131,869 +) +______________ +* +Included in other current assets on the consolidated balance +sheets. +F-24 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +As noted +above, deferred tax liabilities for properties and equipment increased in 2008 +and 2007, primarily as a result of our election to expense $30 million and $44 +million of IDC for income tax purposes. +In +assessing whether a valuation allowance for the deferred tax assets should be +recorded, we consider whether it is more likely than not that some portion or +all of the deferred tax assets will not be realized. The ultimate +realization of deferred tax assets is dependent upon the generation of future +taxable income during the periods in which those temporary differences become +deductible. Based upon the level of historical taxable income and +projections for future taxable income over the periods in which the deferred tax +assets are deductible, we believe it is more likely than not that we will +realize the benefits of these deductible differences. The amount of +the deferred tax asset considered realizable, however, could be reduced in the +near term if estimates of future taxable income during the carry-forward period +are reduced. +We +adopted the provisions of FIN No. 48 effective January 1, 2007. As a +result of adoption, retained earnings decreased by $0.3 million, deferred income +taxes payable decreased by $0.9 million, current income taxes payable increased +by $0.2 million and the liability for unrecognized tax benefit increased by $1 +million. +The +following table sets forth a reconciliation of the total amounts of unrecognized +tax benefits for 2008: +(in +thousands) +Balance, +December 31, 2007 +$ +888 +Gross +increases for tax positions of prior years +216 +Gross +increases for tax positions of current year +167 +Balance, +December 31, 2008 +$ +1,271 +Interest +and penalties related to uncertain tax positions are recognized in income tax +expense. As of January 1, 2008, and December 31, 2008, we have +approximately $0.1 and $0.3 million of accrued interest related to uncertain tax +positions, respectively. In addition, at December 31, 2008, $0.3 +million of income tax penalties were accrued compared to $0.2 million accrued at +January 1, 2008. The total amount of unrecognized tax benefits that +would affect the effective tax rate, if recognized, is $0.9 million as of +December 31, 2008 and $0.5 million as of January 1, 2008. We expect +the unrecognized tax benefit at December 31, 2008, to decrease in the next +twelve months because of the ongoing IRS examination of our 2005 and 2006 tax +years that will be finalized in 2009. It is currently estimated that +the decrease in our unrecognized tax benefits during the next year will be +approximately $0.8 million. +The +statute of limitations for tax years 2004-2007 remains open for both federal and +state taxing jurisdictions. However, due to the July 31, +2007, completion date of the federal examination of our 2003 and 2004 tax years, +we believe that certain tax positions related to these tax years have been +“effectively settled” for federal tax purposes. Additionally, for the +majority of our state tax jurisdictions, the statute of limitations for the 2003 +tax year remains open at December 31, 2008. +Our +subsidiary, Unioil Inc., which was acquired on December 6, 2006, filed separate +tax returns for years prior to the acquisition date. Unioil’s +2003-2006 tax returns remain open to examination at December 31, +2008. Any unrecognized tax benefit associated with Unioil's tax +returns is included in the above table amount. +NOTE +6 - LONG-TERM DEBT +December +31, +2008 +2007 +(in +thousands) +Credit +facility +$ +194,500 +$ +235,000 +12% +Senior notes due 2018, net of discount of $2.6 million +200,367 +- +Total +long-term debt +$ +394,867 +$ +235,000 +F-25 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Credit +facility +We have a +credit facility co-arranged by JPMorgan Chase Bank, N.A. ("JPMorgan") and BNP +Paribas, as amended last on November 12, 2008, dated as of November 4, 2005, +with an available commitment of $375 million as of December 31, +2008. The credit facility, through a series of amendments, includes +commitments from: Wachovia Bank N.A.; Bank of America, N.A.; Bank of Oklahoma; +Allied Irish Banks p.l.c.; Guaranty Bank, FSB; Royal Bank of Canada; The Royal +Bank of Scotland, plc; Calyon New York Branch; Compass Bank; The Bank of Nova +Scotia; and BMO Capital Markets Financing, Inc. The maximum allowable +commitment under the current credit facility is $400 million. The +credit facility is subject to and secured by required levels of oil and natural +gas reserves. The credit facility requires an aggregated security of +a value no less than 80% of the value of the direct interests included in the +borrowing base properties. Our credit facility borrowing base is +subject to size redeterminations each April and October based upon a +quantification of our reserves at December 31st and +June 30th, respectively. A commodity price deck reflective of the +current and future commodity pricing environment, as agreed upon by us and our +lenders, is utilized to quantify our reserve reports and determine the +underlying borrowing base. +We are +required to pay a commitment fee of .5% per annum on the unused portion of the +activated credit facility. Interest accrues at an alternative base +rate ("ABR") or adjusted LIBOR at our discretion. The ABR is the +greater of JPMorgan's prime rate, an adjusted secondary market rate for a +three-month certificate of deposit plus 1% or the federal funds effective rate +plus .5%. ABR borrowings are assessed an additional margin spread up +to 1.375% and adjusted LIBOR borrowings are assessed an additional margin spread +of 1.625% to 2.375% based upon the outstanding balance as a percentage of the +available balance. The credit agreement requires, among other things, +the maintenance of certain working capital and tangible net worth +ratios. No principal payments are required until the credit agreement +expires on November 4, 2010. +The +credit facility contains covenants customary for agreements of this type, +including, but not limited to, limitations on our ability to: (a) incur +additional indebtedness and guarantees, (b) create liens and other encumbrances +on our assets, (c) consolidate, merge or sell assets, (d) pay dividends and +other distributions, (e) make certain investments, loans and advances, (f) enter +into sale/leaseback transactions, (g) enter into transactions with our +affiliates, (h) change the character of our business, (i) engage in hedging +activities unless certain requirements are satisfied, (j) issue certain types of +stock, and (k) make certain amendments to our organizational +documents. The credit facility also requires us to execute and +deliver specified mortgages and other evidences of security and to deliver +specified opinions of counsel and other evidences of title. In +addition, we are required to comply with certain financial tests and maintain +certain financial ratios. The financial tests and ratios include requirements +to: (a) maintain a minimum ratio of consolidated current assets to consolidated +current liabilities, or working capital ratio, and (b) not to exceed a maximum +leverage ratio. +As of +December 31, 2008, we had drawn $194.5 million from our credit facility compared +to $235 million as of December 31, 2007. The borrowing rate on the +outstanding balance was 4.6% as of December 31, 2008 compared to 7.1% as of +December 31, 2007. Amounts outstanding under our credit facility are +secured by substantially all of our properties. We were in compliance +with all covenants at December 31, 2008, and expect to remain in compliance +throughout 2009. +12% +Senior Notes Due 2018 +Our +outstanding 12% senior notes were issued on February 8, 2008. The +principal amount of the senior notes is $203 million, which is payable at +maturity on February 15, 2018. Interest is payable in cash +semi-annually in arrears on each February 15 and August 15. The +senior notes were issued at a price of 98.572% of the principal +amount. In addition, $5.4 million in costs associated with the +issuance of the debt has been capitalized as a deferred loan +cost. The original discount and the deferred loan costs are being +amortized to interest expense over the term of the debt using the effective +interest method. As a result of recent negative global financial +market conditions, we estimate that the fair value of the senior notes was +approximately $127 million or approximately 62.5% of par. We +determined this valuation based upon measurements of trading activity and quotes +provided by brokers and traders participating in the trading of the +securities. +The +indenture governing the notes contains customary representations and warranties +as well as typical restrictive covenants that, among other things, limit our +ability and the ability of our restricted subsidiaries to: (a) incur additional +debt, (b) make certain investments or pay dividends or distributions on our +capital stock or purchase or redeem or retire capital stock, (c) sell assets, +including capital stock of our restricted subsidiaries, (d) pay dividends or +other payments by restricted subsidiaries, (e) create liens that secure debt, +(f) enter into transactions with affiliates, and (g) merge or consolidate with +another company. Additionally, we are subject to two incurrence +covenants: 1) earnings before interest, taxes, depreciation, amortization and +capital expenditures (“EBITDAX”) of at least two times interest expense and 2) +total debt of less than 4.0 times EBITDAX. As of December 31, 2008, +our EBITDAX was 8.3 times interest expense and total debt was 1.8 time +EBITDAX. We were in compliance with all covenants as of December 31, +2008, and expect to remain in compliance throughout 2009. +The notes +are senior unsecured obligations and rank, in right of payment, equally with all +of our existing and future senior unsecured indebtedness and senior to any of +our existing and future subordinated indebtedness. The notes are +effectively subordinated to any of our existing or future secured indebtedness +to the extent of the assets securing such indebtedness. +F-26 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +The notes +are not initially guaranteed by any of our subsidiaries. However, +subsidiaries may be obligated to guarantee the notes if: +• a +subsidiary is a guarantor under our senior credit facility; and +• the +subsidiary has consolidated tangible assets that constitute 10% or more of our +consolidated tangible assets. +Subject +to specified exceptions, any subsidiary guarantor will be restricted from +entering into certain transactions including the disposition of all or +substantially all of its assets or merging with or into another +entity. Subsidiary guarantors may be released from a guarantee under +circumstances specified in the indenture. As of December 31, 2008, +none of our subsidiaries were obligated as guarantors of our senior +notes. +The +indenture provides that at any time, which may be more than once, before +February 15, 2011, we may redeem up to 35% of the outstanding notes with +proceeds from one or more equity offerings at a redemption price of 112% of the +principal amount of the notes redeemed, plus accrued and unpaid interest, as +long as: +• +at +least 65% of the aggregate principal amount of the notes issued on +February 8, 2008, remains outstanding after each such redemption; +and +• +the redemption occurs within 180 days after the closing of the equity +offering. +The notes +also provide that we may, at our option, redeem all or part of the notes, at any +time prior to February 15, 2013, at the make-whole price set forth in the +indenture, and on or after February 15, 2013, at fixed redemption prices, plus +accrued and unpaid interest, if any, to the date of +redemption. Further, the indenture provides that upon a change of +control, we must give holders of the notes the opportunity to put their notes to +us for repurchase at a repurchase price of 101% of the principal amount, plus +accrued and unpaid interest. +In +connection with the issuance of the notes, we entered into a registration rights +agreement with the initial purchasers in which we agreed to file a registration +statement with the SEC related to an offer to exchange the notes for other +freely tradable notes and to use commercially reasonable efforts to cause the +registration statement to become effective on or prior to February 7, +2009. On April 24, 2008, we filed the related registration statement +on Form S-4. The registration statement was declared effective May +23, 2008. +NOTE +7 - ASSET RETIREMENT OBLIGATIONS +Changes +in carrying amounts of the asset retirement obligations associated with our +working interest in oil and gas properties are as follows: +2008 +2007 +(in +thousands) +Balance +at beginning of year +$ +20,781 +$ +11,966 +Obligations +assumed with development activities and acquisitions +1,189 +7,909 +Obligations +discharged with disposed properties and asset retirements +(114 +) +(93 +) +Accretion +expense +1,230 +999 +Balance +at end of year +$ +23,086 +$ +20,781 +If the +fair value of the estimated asset retirement obligation changes, an adjustment +is recorded to both the asset retirement obligation and the asset retirement +cost. Approximately $0.1 million of the asset retirement obligations +were classified as short-term and included in other accrued expenses as of +December 31, 2008 and 2007. +F-27 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +NOTE +8 - COMMITMENTS AND CONTINGENCIES +Drilling and Development +Agreements . We are a party to a pipeline expansion agreement +with an unrelated third party, which is also currently the purchaser of the +majority of our Wattenberg Field natural gas production. Pursuant to +the agreement, we have agreed to invest a minimum of $65 million to develop +specified acreage in the Wattenberg Field, during a three-year period ending +December 31, 2009. Such capital spending will include costs to drill +new wells and the cost to recomplete existing wells in this +area. Should we not meet the minimum commitment by December 31, 2009, +we will be required to pay liquidated damages of $2 million, prorated based on +our actual capital investment made to date. As of December 31, 2008, +our total capital expenditures pursuant to the agreement were $61.3 million, +resulting in a maximum potential liquidating damages charge of $0.1 +million. +In +connection with the acquisition of oil and gas properties in October 2007 from +an unaffiliated party, we are obligated to drill 100 wells in the Appalachian +Basin by January 2016. We will retain a majority interest in each +well drilled. For each well we fail to drill, we are obligated to pay +to the seller liquidated damages of $25,000 per undrilled well for a total +contingent obligation of $2.5 million or reassign to the seller the interest +acquired in the number of undrilled well locations. As of December +31, 2008, we have drilled 28 wells pursuant to this agreement. +We have +entered into contracts that provide firm transportation, sales and processing +charges on pipeline systems which we transport or sale our natural gas and the +natural gas of other companies, working interest owners and our affiliated +partnerships. The remaining terms of the contracts range from two to +14 years and require us to pay these transportation and processing charges +regardless if the required volumes are delivered or not. The table +below represents our gross future minimum firm transportation, sales and +processing charges as of December 31, 2008, for the periods +indicated. We will record in our financial statements only our share +based upon our working and net revenue interest in the wells. +Year +(in +thousands) +2009 +$ +8,391 +2010 +19,047 +2011 +18,443 +2012 +25,071 +2013 +25,262 +Thereafter +121,281 +$ +217,495 +In +September 2008, we entered into a pipeline and processing plants expansion +agreement with an unrelated party, which is currently the purchaser of the +majority of our Wattenberg Field natural gas production. Pursuant to +the agreement, we have agreed to make a capital investment of $60 million, for +our own benefit, over a three-year period commencing on January 1, 2009, to +develop or facilitate production in our Wattenberg Field dedicated to this +purchaser. If the purchaser fails to complete the pipeline and +processing plants in accordance with the agreement, then the agreement +effectively terminates. The agreement also provides for certain +volume commitments to be obtained by December 31, 2012. Qualifying +capital expenditures include the cost to drill new wells and the cost to +recomplete existing wells in this area. Failure to meet our drilling +commitment would result in a maximum payment to the counterparty of $15 million +in 2012; failure to meet our volume delivery commitment by December 31, 2012, +would result in a maximum payment to the counterparty of $10 million in +2013. +Partnership Repurchase +Provision . Substantially all of our drilling programs contain +a repurchase provision where investing partners may request that we purchase +their partnership units at any time beginning with the third anniversary of the +first cash distribution. The provision provides that we are obligated +to purchase an aggregate of 10% of the initial subscriptions per calendar year +(at a minimum price of four times the most recent 12 months' cash +distributions), if repurchase is requested by investors, and subject to our +financial ability to do so. The maximum annual repurchase obligation +as of December 31, 2008, was approximately $15.9 million. We have +adequate liquidity to meet this obligation. During 2008 and 2007, we +paid $1.8 million and $1.6 million, respectively, under this provision for the +repurchase of partnership units. As of December 31, 2008, outstanding +repurchase offers to investing partners totaled $0.7 million, of which $0.2 +million were consummated in 2009 prior to expiration. +Performance +Supplements . Our drilling programs formed from 1996 through +the second quarter of 2005 contain a performance supplement that provides for +changes in the distribution of partnership profits if certain levels of +performance are not met. The terms of this provision in the +partnership agreements are not a guarantee of a rate of return on an investment +in the partnership. Under those specific conditions, such changes can +result in our share of an affected partnership’s profits being reduced by up to +one half of the amount to which we otherwise would be entitled in the affected +period. In no event would we be obligated to assume a +disproportionate share of losses in such partnerships; should the partnerships +that contain this provision in the partnership agreements incur a loss, our +share of such losses would be unaffected by the terms of this +provision. In accordance with these provisions, our share of +partnership profits was reduced by an aggregate of $1 million, $0.6 million, and +$1 million during 2008, 2007and 2006, respectively. As of December +31, 2008 and 2007, based on production through December 31 of the corresponding +year, we had accrued $0.3 million and $0.2 million, respectively. +Partnership Casualty +Losses. As Managing General Partner of 33 partnerships, we +have liability for any potential casualty losses in excess of the partnership +assets and insurance. We believe the casualty insurance coverage that +we and our subcontractors carry is adequate to meet this potential +liability. +Drilling Rig +Contracts. In order to secure the services for drilling rigs, +we made commitments to the drilling contractors, which call for a minimum +commitment of $12,500 daily for a specified amount of time if we cease to use +the drilling rigs and a maximum commitment of $40,680 daily for a specified +amount of time for daily use of the drilling rigs. As of December 31, +2008, commitments for these two separate contracts expire in August 2009 and +July 2010. As of December 31, 2008, we have an outstanding minimum +commitment for $4.2 million and an outstanding maximum commitment for $15.9 +million, which includes $5.1 million related to a rig sublet to a third party +and remains our obligation should the third party default on terms of the sublet +agreement. +F-28 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Litigation . +Colorado +royalty . On May 29, 2007, Glen Droegemueller, individually and +as representative plaintiff on behalf of all others similarly situated, filed a +class action complaint against the Company in the District Court, Weld County, +Colorado alleging that we underpaid royalties on natural gas produced from wells +operated by us in parts of the State of Colorado (the “Droegemueller +Action”). The plaintiff sought declaratory relief and to recover an +unspecified amount of compensation for underpayment of royalties paid by us +pursuant to leases. We removed the case to Federal Court on June 28, +2007. On October 10, 2008, the court preliminarily approved a +settlement agreement between the plaintiffs and the Company, on behalf of itself +and the partnerships for which the Company is the managing general +partner. Based on the settlement terms, the settlement amount payable +by the Company is $5.8 million. Such moneys, in addition to moneys +related to the settlement on behalf of the partnerships for which the Company is +the managing general partner, were deposited in an escrow account on November 3, +2008. We have accrued as of December 31, 2008, and included in other +accrued expenses in our consolidated balance sheets, a related $5.8 million +litigation reserve. We believe that the amount accrued is adequate to +satisfy this obligation. Notice of the settlement was mailed to +members of the class action suit in the fourth quarter of 2008. The +final settlement approval hearing is expected on April 7, 2009. +See Note 17 , Subsequent Events , regarding +two West Virginia royalty lawsuits filed in January 2009. +Colorado Stormwater +Permit . On December 8, 2008, we received a Notice of Violation +/Cease and Desist Order (the “Notice”) from the Colorado Department of Public +Health, related to the stormwater permit for the Garden Gulch +Road. The Company manages this private road for Garden Gulch +LLC. The Company is one of four equal owners of Garden Gulch LLC, all +of which are oil and gas companies operating in the Piceance region of +Colorado. The Notice alleges a deficient and/or incomplete stormwater +management plan, failure to implement best management practices and failure to +conduct required permit inspections. The Notice requires corrective +action and states that the recipient shall cease and desist such alleged +violations. The Notice states that a violation could result in civil +penalties up to $10,000 per day. The Company’s initial response was +submitted on February 6, 2009. No civil penalties have been imposed +or requested at this time. Given the preliminary stage of this +proceeding and the inherent uncertainty in litigation, the Company is unable to +predict the ultimate outcome of this suit at this time. +We are +involved in various other legal proceedings that we consider normal to our +business. Although the results cannot be known with certainty, we +believe that the ultimate results of such proceedings will not have a material +adverse effect on our financial position or results of operations. +Employment Agreements with Executive +Officers . We have employment agreements with our Chief +Executive Officer, Chief Financial Officer, Chief Accounting Officer and other +executive officers. The employment agreements provide for annual base +salaries, eligibility for performance bonus compensation, and other various +benefits, including retirement and termination benefits. +In the +event of termination without cause or if an executive officer terminates +employment for good reason, which includes a change in control, the executive +officer is entitled to receive a payment in the amount up to three times the sum +of his highest base salary during the previous two years of employment +immediately preceding the termination date and his highest bonus received during +the same two year period. The executive officer is also entitled to +(i) vesting of any unvested equity compensation, (ii) reimbursement for any +unpaid expenses, (iii) retirement benefits earned under the current and/or +previous agreements, (iv) continued coverage under our medical plan for up to 18 +months, and (v) payment of any earned and unpaid bonus amounts. In +addition, the executive officer is entitled to receive any benefits that he +would have otherwise been entitled to receive under our 401(k) and profit +sharing plan, although those benefits are not increased or +accelerated. +In the +event that an executive officer is terminated for just cause, we are required to +pay the executive officer his base salary through the termination date plus any +bonus (only for periods completed and accrued, but not paid), incentive, +deferred, retirement or other compensation, and to provide any other benefits, +which have been earned or become payable as of the termination date but which +have not yet been paid or provided. +In the +event that an executive officer voluntarily terminates his employment for other +than good reason, he is entitled to receive (i) his base salary, bonus and +incremental retirement payment prorated for the portion of the year that the +executive officer is employed, (ii) any incentive, deferred or other +compensation which has been earned or has become payable, but which has not yet +been paid under the schedule originally contemplated in the agreement under +which they were granted or in full without discount within 60 days of the +termination date at our discretion, (iii) any unpaid expense reimbursement upon +presentation by the executive officer of an accounting of such expenses in +accordance with our normal practices, and (iv) any other payments for benefits +earned under the employment agreement or our plans. +F-29 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +In the +event of death or disability, the executive is entitled to receive (i) his base +salary and bonus for the portion of the year the executive officer is employed; +(ii) the base salary that would have been earned for six months after +termination; (iii) immediate vesting of all equity and option awards; (iv) the +payment of deferred retirement compensation based upon the schedule originally +contemplated in the deferred retirement compensation agreement or in a lump-sum +no later than two and one-half months following the close of the calendar year +in which the death or disability occurred; (v) reimbursement for any unpaid +expenses; (vi) and benefits earned under the 401(k) and profit sharing plan; and +(vii) continued coverage under our medical plan for up to 18 +months. +Derivative +Contracts . We would be exposed to oil and natural gas price +fluctuations on underlying purchase and sale contracts should the counterparties +to our derivative instruments or the counterparties to our gas marketing +contracts not perform. Nonperformance is not +anticipated. There were no counterparty default losses in 2008, 2007 +or 2006. +NOTE +9 - COMMON STOCK +Stock-Based +Compensation Plans +As +approved by the shareholders in June 2004, we maintain a long-term equity +compensation plan for our officers and certain key employees (the “2004 +Plan”). In accordance with the plan, awards may be issued in the form +of stock options, stock appreciation rights, restricted stock or performance +shares. A total of 750,000 new shares of common stock have been +reserved for issuance. Awards pursuant to the plan vest over periods +set at the discretion of the Compensation Committee of our Board of Directors +(“Board”) and have a maximum exercisable period of ten years. As of +December 31, 2008, 312,418 common shares remain available for future +awards. +As +approved by the shareholders, we also maintain a restricted stock plan for +non-employee directors. A total of 100,000 new shares of common stock +have been reserved for issuance under the plan. During 2008, 2007 and +2006, 14,000, 12,710 and 6,551 common shares, respectively, were awarded in +accordance with the plan. Compensation expense for each of the years +ended December 31, 2008, 2007 and 2006, related to these restricted shares was +$1 million, $0.2 million and $0.1 million, respectively. As of +December 31, 2008, 59,844 common shares remain available for future +awards. +In August +1999, the shareholders approved the 1999 Incentive Stock Option and +Non-Qualified Stock Option Plan. A total of 500,000 shares of our +common stock were reserved for issuance upon the exercise of stock +options. All shares authorized to be awarded pursuant to this plan +were awarded in years prior to 2002. As of December 31, 2007, options +for 11,000 common shares remained outstanding and exercisable; in 2008, +these outstanding options were exercised. +The +following table provides a summary of the effect of our stock based compensation +plans on the results of operations for the periods presented. +Year +Ended December 31, +2008 +2007 +2006 +(in +thousands) +Total +stock-based compensation expense (1) +$ +6,702 +$ +2,286 +$ +1,516 +Income +tax benefit +(2,557 +) +(882 +) +(585 +) +Net +income impact +$ +4,145 +$ +1,404 +$ +931 +______________ +(1) 2008 +includes $1.1 million related to a separation agreement with our former +president and $1.5 million related to a retirement agreement with our former +chief executive officer. +Stock Option +Awards. As of December 31, 2008, all outstanding stock options +were issued pursuant to our 2004 Plan. Outstanding options expire ten +years from the date of grant and become vested and exercisable ratably over a +four year period. We have not granted any new stock option awards +since 2006. In 2008, pursuant to a separation agreement with our +former president and an agreement with our former chief executive officer, we +modified options to purchase 9,905 shares by accelerating the vesting schedule, +none of which would have vested pursuant to the original terms of the +award. The incremental change in fair value per share of the modified +awards was immaterial. The fair value of options modified in 2008 and +granted in 2006, were estimated at the date of modification or grant using a +Black-Scholes option-pricing model assuming no dividends and the following +weighted average assumptions, with the exception of 4,678 shares in 2008, which +were estimated to approximate fair value on the date of modification due to the +short-term nature of the award: +F-30 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Year +Ended December 31, +2008 +2006 +Expected +volatility +43.0% +40.4% +Expected +term (in years) +- +6.0 +Risk-free +interest rate +1.6% +4.2% +Weighted-average +grant date fair value per share +$ +18.03 +$ +20.30 +Expected +volatilities are based on our historical volatility. The expected +life of an award is estimated using historical exercise behavior +data. The risk-free interest rate is based on the U.S. Treasury +yields in effect at the time of grant and extrapolated to approximate the +expected life of the award. We do not expect to pay dividends, nor do +we expect to declare dividends in the foreseeable future. +The +following table provides a summary of our stock option award activity for the +year ended December 31, 2008: +Weighted +Weighted +Average +Number +of +Average +Remaining +Shares +Exercise +Contractual +Underlying +Price +Term +Options +Per +Share +(years) +Outstanding +at December 31, 2007 +51,567 +$ +33.55 +6.4 +Modified +9,905 +43.03 +Exercised +(25,699 +) +24.41 +Forfeited +(17,422 +) +43.86 +Outstanding +at December 31, 2008 +18,351 +41.68 +6.8 +Vested +and expected to vest at December 31, 2008 +18,351 +41.68 +6.8 +Exercisable +at December 31, 2008 +12,736 +40.41 +6.6 +Year +Ended December 31, +2008 +2007 +2006 +(in +thousands, except market price) +Total +intrinsic value of options exercised +$ +659 +$ +1,691 +$ +281 +Total +intrinsic value of options outstanding +- +1,319 +1,984 +Total +intrinsic value of options exercisable +- +971 +1,934 +Market +price per common share as of December 31 +24.07 +59.13 +43.05 +The +intrinsic value of options exercised represents the amount by which the market +value of our stock at date of exercise exceeds the exercise price of the +option. The intrinsic values of the options outstanding and +exercisable represent the amount by which the closing market price of our common +stock at the last trading day of the year exceeds the exercise price of the +options. Total compensation cost related to stock options +granted under the 2004 Plan not yet recognized as of December 31, 2008, was $0.1 +million. This cost is expected to be recognized over a weighted +average period of 1.5 years. +F-31 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Restricted +Stock Awards +We have +issued restricted stock awards with vesting conditions that are either +time-based or market-based. +Time-Based +Awards . The fair value +of the time-based awards is amortized ratably over the requisite service period, +primarily over four years. Time-based awards for non-employee directors vest on +July 1 of the year following the date of grant. Total intrinsic value +is based upon the closing market price of our common stock on the last trading +date of the year. In 2008, pursuant to a separation agreement with +our former president and an agreement with our former chief executive officer, +we modified time-based awards to vest 25,027 shares by accelerating the vesting +schedule, none of which would have vested pursuant to the original terms of the +award, resulting in an increase in the original fair value of $0.4 +million. +The +following table sets forth the changes in non-vested time-based awards for the +year ended December 31, 2008: +Weighted +Average +Grant-Date +Shares +Fair +Value +Non-vested +at December 31, 2007 +201,845 +$ +37.97 +Granted/modified +161,982 +57.64 +Vested +(110,562 +) +34.59 +Forfeited +(35,205 +) +45.53 +Non-vested +at December 31, 2008 +218,060 +$ +52.59 +Year +Ended December 31, +2008 +2007 +2006 +(in +thousands, except market price) +Total +intrinsic value of time-based awards vested +$ +6,710 +$ +2,208 +$ +844 +Total +intrinsic value of time-based awards non-vested +5,249 +10,161 +5,671 +Market +price per common share as of December 31 +24.07 +59.13 +43.05 +Total +intrinsic value of time-based awards vested is based on the closing market price +of our common stock on the date of vest. Total intrinsic value of +time-based awards not yet vested is based on the closing market price of our +common stock on the last trading day of the year. The total +compensation cost related to non-vested time-based awards not yet recognized as +of December 31, 2008, was $8.8 million. This cost is expected to be +recognized over a weighted-average period of 2.9 years. +Market-Based +Awards . The fair value of the market-based awards is amortized +ratably over the requisite service period, primarily over three years for +market-based awards. The market-based shares vest only upon the +achievement of certain per share price thresholds and continuous employment +during the vesting period. All compensation cost related to the +market based-awards will be recognized if the requisite service period is +fulfilled, even if the market condition is not achieved. In 2008, +pursuant to a separation agreement with our former president, we modified +market-based awards to vest 1,539 shares by accelerating the vesting schedule, +none of which would have vested pursuant to the original terms of the award; +pursuant to an agreement with our former chief executive officer, we modified +market-based awards to vest 37,440 shares by accelerating the vesting +schedule, none of which would have vested, nor was expected to vest, pursuant to +the original terms of the award. The incremental change in fair value +per share of the modified awards was immaterial. +The +weighted average grant date fair value per market-based share, including shares +modified pursuant to an agreement with our former chief executive officer, was +computed using the Monte Carlo pricing model using the following weighted +average assumptions: +Year +Ended December 31, +2008 +2007 +Expected +term of award +3 +years +3 +years +Risk-free +interest rate +2.7% +4.7% +Volatility +45.6% +44.0% +Weighted +average grant date fair value per share +$ +43.61 +$ +36.07 +F-32 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +The +following table sets forth the changes in non-vested market-based awards for the +year ended December 31, 2008: +Weighted +Average +Grant-Date +Shares +Fair +Value +Non-vested +at December 31, 2007 +31,972 +$ +36.07 +Granted/modified +87,384 +43.61 +Vested +(3,078 +) +52.00 +Forfeited +(43,595 +) +40.81 +Non-vested +at December 31, 2008 +72,683 +$ +41.62 +The +intrinsic value of market-based awards not yet vested at December 31, 2008 and +2007, was $1.7 million and $1.9 million, respectively, based upon the closing +market price of our common stock on the last trading date of the year. The total +compensation cost related to non-vested market-based awards not yet recognized +as of December 31, 2008, is $1.4 million. This cost is expected to be +recognized over a weighted-average period of 1.1 years. +Treasury +Share Purchases +In +January 2006, we announced that our Board authorized the purchase of up to 10% +(1,627,500 shares) of our common stock during 2006. Stock purchases +under this program were made in the open market or in private transactions, at +times and in amounts that we deemed appropriate. In October 2006, we +completed our January 2006 program. Total shares purchased pursuant +to the program were 1,627,500 common shares at a cost of $66.3 million ($40.75 +average price paid per share), including 100,000 shares from one of our +executive officers at a cost of $4.1 million ($40.66 price paid per +share). All shares purchased in accordance with the program have +subsequently been retired. +On +October 16, 2006, our board of directors of approved a second 2006 purchase +program authorizing us to purchase up to 10% (1,477,109 shares) of our then +outstanding common stock through April 2008. Stock purchases under +this program were made in the open market or in private transactions, at times +and in amounts that we deem appropriate. There were 1,465,089 shares +that were authorized but not yet purchased as of December 31, +2007. Total shares purchased in 2008 pursuant to the program were +64,263 common shares at a cost of $4.4 million ($67.97 average price paid per +share), including 63,756 shares from our executive officers at a cost of $4.3 +million ($67.98 price paid per share). Shares purchased in 2008 +from employees, excluding executive officers, were generally purchased at fair +market value based on the closing price on the date of purchase and were +primarily purchased to satisfy the statutory minimum tax withholding requirement +for restricted stock that vested in 2008. Shares purchased from +executive officers in 2008 were primarily pursuant to a separation agreement +with our former president and to satisfy the statutory minimum tax withholding +requirements for shares vested in 2008. Shares purchased in prior +years were generally purchased at fair market value based on the closing price +on the date of purchase and were primarily purchased to satisfy the statutory +minimum tax withholding requirement for shares vesting in prior +years. The authorization to purchase the remaining 1,400,826 shares +effectively expired on April 30, 2008. All shares purchased in +accordance with the program have been subsequently retired. +Pursuant +to our senior notes indenture entered on February 8, 2008, any future purchases +are limited, see Note 6 , Long-Term Debt . +Shareholders’ Rights +Agreement +On +September 11, 2007, we entered into a rights agreement, with Transfer Online, +Inc., as rights agent. The rights agreement is designed to improve +the ability of our board of directors to protect the interest of our +shareholders in the event of an unsolicited takeover attempt. Our +Board declared a dividend of one right for each outstanding share of our common +stock. The right dividend was paid to shareholders of record on +September 14, 2007. A “distribution date,” as defined in the rights +agreement, can occur after any individual shareholder exceeds 15% ownership of +our outstanding common stock. After the occurrence of a “distribution +date,” the right entitles each registered holder (other than the acquiring +shareholder who triggered the “distribution date”), to purchase shares of our +common stock (or, in certain circumstances, cash, property or other securities) +having a then-current value equal to two times the exercise price of the right +(i.e., for the $240 exercise price, the rights holder receives $480 worth of +common stock). The exercise price is subject to adjustment for +various corporate actions which affect all shareholders, such as a stock +split. The rights agreement and all rights will expire on September +11, 2017. +F-33 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Common +and Preferred stock +Effective +July 17, 2008, pursuant to shareholder approval, we amended and restated our +Articles of Incorporation to: (1) increase the number of the Company's +authorized shares of common stock, par value $0.01, from 50,000,000 shares to +100,000,000 shares, and (2) authorize 50,000,000 shares of Company preferred +stock, par value $0.01, which may be issued in one or more series, with such +rights, preferences, privileges and restrictions as shall be fixed by our Board +of Directors from time to time. As of December 31, 2008, no preferred +stock had been issued. +NOTE +10 - EMPLOYEE BENEFIT PLANS +We +sponsor a qualified retirement plan covering substantially all of our +employees. The plan consists of a 401(k) component and a profit +sharing component. The 401(k) component enables eligible employees to +contribute a portion of their compensation through pre-tax payroll deductions in +accordance with specific guidelines. We provide a discretionary +matching contribution based on a percentage of the employees' contributions up +to certain limits. Our contribution to the profit sharing component +is discretionary. Our total combined expense for both 401(k) and +profit sharing in 2008, 2007 and 2006, was $1.9 million, $1.4 million and $3.1 +million, respectively. +We +provide a supplemental retirement benefit of deferred compensation under terms +of the various employment agreements with certain executive +officers. During 2008, 2007 and 2006, we charged $0.2 million, $0.4 +million and $0.3 million related to this plan to general and administrative +expenses, respectively, and we have recorded a related liability in the amount +$2.4 million and $2.2 million as of December 31, 2008 and 2007, +respectively. +In +addition to the supplemental retirement benefit of deferred compensation, we +offer a supplemental healthcare benefit covering certain executive officers and +their spouses in accordance with each officer's employment +agreement. Expense incurred during 2008 and 2007 related to this plan +was immaterial. As of December 31, 2008 and 2007, we had a recorded +liability of $0.6 million. +We +maintain a non-qualified deferred compensation plan for our non-employee +directors. The amount of compensation deferred by each participant is +based on participant elections. The amounts deferred pursuant to the +plan are invested in our common stock, maintained in a rabbi trust and are +classified in the balance sheet as treasury shares as a component of +shareholders' equity. The plan may be settled in either cash or +shares as requested by the participant. As of December 31, 2008 and +2007, we had recorded a long-term liability of $0.2 million and $0.3 million, +respectively, which is included in other liabilities in our consolidated balance +sheets. +NOTE +11 - TRANSACTIONS WITH AFFILIATES +Funds +held for future distribution on our consolidated balance sheets represent +amounts owed to affiliated partnerships and others for production proceeds +received by us on their behalf and undistributed as of December 31, 2008 and +2007. +Amounts +due from/to the affiliated partnership are primarily related to derivative +positions, unbilled well lease operating expenses, and costs resulting from +audit and tax preparation services. +We enter +into derivative instruments for our own production as well as for our 33 +affiliated partnerships’ production. We enter into these derivative +instruments for us and, as the managing general partner, for the affiliated +partnerships jointly by area of operation. Prior to September 30, +2008, as volumes produced changed, the allocation between us and the affiliated +partnerships changed. As of September 30, 2008, we fixed the +allocation of the derivative positions between us and each affiliated +partnership. Fixed quantities of each of the then existing positions +were allocated to us and the affiliated partnerships based upon current +estimated future production. For positions entered into subsequent to +September 30, 2008, specific designations of the quantities between us and the +affiliated partnerships are made at the time the positions are entered into +based on estimated future production. As of December 31, 2008, we +have recorded a payable to affiliates of $37.5 million representing their +allocated portion of the fair value of our gross derivative assets and a due +from affiliates of $1.6 million representing their allocated portion of the fair +value of our gross derivative liabilities. +Our +natural gas marketing segment manages the marketing of oil and natural gas for +our affiliated partnerships in the Appalachian Basin. Our sales from +natural gas marketing activities include $12.4 million, $9.3 million and $17.6 +million in 2008, 2007 and 2006, respectively, related to the marketing of oil +and natural gas on behalf of our affiliated partnerships. Included in +our cost of natural gas marketing activities is $12.1 million, $9.1 million and +$17.3 million for 2008, 2007 and 2006, respectively, related to these sales . +F-34 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +We +provided oil and gas well drilling services to our affiliated +partnerships. Pursuant to our cost-plus drilling arrangements and our +corresponding net presentation, we performed drilling services for our +affiliated partnerships totaling $68 million, $68.4 million and $87 million in +2008, 2007 and 2006, for which we recognized $7.6 million, $11.4 million and +$12.4 million in oil and gas well drilling operations revenue, +respectively. As part of the oil and gas well drilling services we +provide to our affiliated partnerships, we sell to them at cost the oil and gas +leases upon which the wells are drilled. For the years ended December +31, 2008, 2007 and 2006, we sold to our affiliated partnerships leases in the +amounts of $0.5 million, $1.4 million and $1.8 million, +respectively. Further, we provide well operations and pipeline +services to our affiliated partnerships. Substantially all of our +revenue and expenses related to oil and gas well drilling operations and +revenues from well operations and pipeline income are associated with services +provided to our affiliated partnerships. +Revenues +from oil and gas well drilling operations and costs of oil and gas well drilling +operations each include $0.1 million during 2006 related to investments made by +executive officers for working interests in wells drilled during in +2006. Amounts invested by the executive officers during 2007 were +immaterial. No amounts were invested by the executive officers during +2008. +Management +fees collected from the affiliated partnerships were $1.3 million in each of the +years 2007 and 2006. Management fees are included in other income on +our consolidated statements of operations. In 2008, we did not offer +a drilling partnership; therefore, no management fee was collected from an +affiliated partnership in 2008. +Through +our wholly-owned subsidiary, PDC Securities Incorporated, we act as +Dealer-Manager of the drilling partnerships. PDC Securities receives +the applicable commissions and marketing allowances from the Escrow Agent of the +drilling program and distributes them to the soliciting broker/dealers who sell +the programs. The commissions and marketing allowances received by +PDC Securities are included in other income net of the commissions distributed +to the soliciting broker/dealer. The commissions and marketing +allowances retained by PDC Securities were $0.5 million and $0.6 million and +those distributed to the soliciting broker/dealers amounted to $8.3 million and +$8.8 million for the years ended December 31, 2007 and 2006, +respectively. In 2008, we did not offer a drilling partnership; +therefore, no commissions and marketing allowances were received, distributed or +retained by PDC Securities. +NOTE +12 - LEASE OBLIGATIONS +We +have entered into operating leases principally for the leasing of natural gas +compressors, office space in Denver and Bridgeport, and general office +equipment. The future minimum lease payments under these +non-cancelable operating leases as of December 31, 2008, are as +follows: +Year +(in +thousands) +2009 +$ +2,687 +2010 +1,645 +2011 +1,081 +2012 +309 +2013 +74 +Thereafter +44 +$ +5,840 +Operating +lease expense for the years ended December 31, 2008, 2007 and 2006, was $2.5 +million, $1.5 million and $0.4 million, respectively. +NOTE +13 - SALE OF OIL AND GAS PROPERTIES +Grand +Valley Field Properties +In July +2006, we sold to an unaffiliated company a portion of our undeveloped leasehold +located in Grand Valley Field, Garfield County, Colorado. The sale +encompassed 100% of the working interest in approximately 8,700 acres, including +approximately 6,400 acres of the Chevron leasehold and 2,300 acres of the +Puckett Land Company leasehold. We retained approximately 475 +undeveloped locations on 10 acre spacing on the Grand Valley Field leasehold in +addition to all of our producing properties in the field. The +proceeds from the sale were $353.6 million. We recorded a gain on +sale of leaseholds of $328 million and a deferred gain on sale of leaseholds of +$25.6 million. +F-35 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Pursuant +to the purchase and sale agreement, we were obligated to either drill 16 wells +on specifically identified acreage over the next three years or pay liquidated +damages of $1.6 million per un-drilled well for a total contingent obligation of +$25.6 million, which was reflected as a deferred gain on sale of leaseholds on +the balance sheet as of December 31, 2006. In May 2007, we entered +into a letter agreement amending the original purchase and sale +agreement. The letter agreement relieved us of the obligation, in its +entirety, to either drill 16 wells or pay liquidated damages, resulting in the +recognition of the remaining $25.6 million deferred gain on sale of leaseholds +in the second quarter of 2007. Pursuant to the letter agreement, we +were obligated to drill six wells on specifically identified +acreage. As of December 31, 2007, we had drilled all six wells, which +were drilled on the unaffiliated party's leasehold for its benefit and at its +cost. +In +conjunction with the purchase and sale agreement described above, we entered +into a LKE agreement, in accordance with Section 1031 of the Internal Revenue +Code, with a “qualified intermediary.” Proceeds in the amount of $300 +million were transferred directly to the qualified intermediary to be held in +trust pursuant to the terms of the LKE agreement. We had until +mid-January 2007 to close any acquisition of suitable like-kind property, +allowing us to take advantage of the income tax deferral benefits of a LKE +transaction. +In +December 2007, we sold to the same unaffiliated party above a portion of our +North Dakota properties for approximately $34.7 million. The +properties, located in Dunn, Williams and McKenzie Counties, North Dakota, +include interests in five producing Bakken wells and approximately 72,000 net +undeveloped acres. The reduction in our production and proved +reserves as a result of this transaction is not material. We recorded +a gain on sale of leaseholds of $7.7 million in the fourth quarter of +2007. Following the sale, we retain ownership in three producing +wells in Dunn County, ten producing wells in Burke County and approximately +60,000 acres of undeveloped leasehold in Burke County. +NOTE +14 – ACQUISITIONS +2007 +Acquisitions +Acquisition +of Internal Revenue Code Section 1031 – Like-Kind Exchange +Properties +During +the first quarter of 2007, we completed the acquisition of suitable like-kind +properties in accordance with the LKE agreement we entered into in connection +with our sale of undeveloped leaseholds located in Grand Valley Field, Garfield +County, Colorado in July 2006. We acquired, for cash, qualifying oil +and gas properties totaling $188.9 million, including costs of acquisition, as +described below. +EXCO +Properties. On January 5, 2007, we completed the purchase of +producing properties and undeveloped drilling locations and acreage in the +Wattenberg Field of the DJ Basin, Colorado from EXCO Resources Inc., an +unaffiliated party. The acquisition included substantially all of +EXCO’s assets in the area and encompassed 144 oil and natural gas wells +(approximating 25.5 Bcfe proved developed reserves as of December 31, 2005) and +8,160 acres of leasehold interests. The wells and leases acquired are +located in Weld, Adams, Larimer, and Broomfield Counties, +Colorado. We operate the assets and hold a majority working interest +in the properties . +Company Sponsored +Partnerships . On January 10, 2007, we completed the purchase +of the remaining working interests in 44 of our sponsored +partnerships. The transaction resulted in an increase in our +ownership in 718 gross (423 net) wells that we currently operate. The +wells are located primarily in the Appalachian Basin and Michigan. +The +following table presents the adjusted purchase price for the like-kind exchange +property acquisitions described above as of December 31, 2007. +EXCO +Partnerships +(in +thousands) +Cash +consideration paid +$ +128,672 +$ +57,776 +Plus: +direct costs of acquisition +1,662 +1,664 +Less: +acquisition cost adjustments +(119 +) +(2,792 +) +Total acquisition +cost +$ +130,215 +$ +56,648 +F-36 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +The +following table presents, as of the respective date of acquisition, the final +allocations of the purchase prices based on estimates of fair +value. +EXCO +Partnerships +(in +thousands) +Current +assets acquired +$ +91 +$ +- +Proved +oil and gas properties +117,099 +59,081 +Unproved +oil and gas properties +14,960 +- +Asset +retirement obligation +(422 +) +(2,433 +) +Other +liabilities assumed +(1,513 +) +- +Total acquisition +cost +$ +130,215 +$ +56,648 +The +assessment of fair value of proved oil and gas properties acquired was based +primarily on projections of expected discounted future cash flows of acquired +oil and natural gas reserves. To compensate for the inherent risk of +estimating and valuing unproved properties, the discounted future net revenues +of probable reserves were reduced by additional risk-weighting factors in that +valuation. +Other. In January +2007, we acquired from unaffiliated parties other like-kind undeveloped +leaseholds in Erath County, Texas for $2.1 million, including costs of +acquisition. Acreage in this area is prospective for development of +oil and natural gas reserves in the Barnett Shale. +Other +Acquisitions +On +February 22, 2007, we acquired, from an unaffiliated party, 28 producing wells +and associated undeveloped acreage located in Colorado (Wattenberg Field) for a +purchase price of $12 million, which was allocated to oil and gas +properties. +On +October 30, 2007, with an effective date of October 1, 2007, we purchased from +unrelated parties, Castle Gas Company, et.al., a majority working interest in +762 natural gas wells located in southwestern Pennsylvania for approximately $54 +million. We estimated that the acquisition included approximately 47 +Bcfe of reserves, or 31 Bcfe of proved reserves and 16 Bcfe of unproved +reserves. The purchase also included associated pipelines, equipment, +real estate and undeveloped acreage. +The +following table presents the adjusted purchase price for the Castle acquisition +described above as of December 31, 2007. +(in +thousands) +Cash +consideration paid +$ +53,041 +Plus: +direct costs of acquisition +443 +Plus: +acquisition cost adjustments +583 +Total acquisition +cost +$ +54,067 +The +following table presents, as of the respective date of acquisition, the final +allocation of the purchase price based on estimates of fair value. +(in +thousands) +Current +assets acquired +$ +185 +Proved +oil and gas properties +55,778 +Unproved +oil and gas properties +217 +Real +estate and equipment, and other assets +2,115 +Non +current assets +783 +Asset +retirement obligation +(4,043 +) +Other +liabilities assumed +(968 +) +Total acquisition +cost +$ +54,067 +F-37 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +The +assessment of fair value of proved oil and gas properties acquired was based +primarily on projections of expected discounted future cash flows of acquired +oil and natural gas reserves. To compensate for the inherent risk of +estimating and valuing unproved properties, the discounted future net revenues +of probable reserves were reduced by additional risk-weighting factors in that +valuation. +Pro +Forma Financial Information +The +results of operations for all of the above acquisitions have been included in +our consolidated financial statements from the dates of +acquisition. The pro forma effect of the inclusion in our +consolidated statement of operations for the year ended December 31, 2007, of +the results of operations for the January and February 2007 acquisitions +described above, individually and in the aggregate, was not +material. +The +following unaudited pro forma financial information presents a summary of our +consolidated results of operations for the years ended December 31, 2007 and +2006, assuming the acquisitions of the EXCO properties, our sponsored +partnerships and the Castle properties had been completed as of January 1, 2006, +including adjustments to reflect the allocation of the purchase price to the +acquired net assets. The pro forma effect of the inclusion of the +results of operations for all of the other acquisitions described above, +individually and in the aggregate, was not material. +Year +Ended December 31, +2007 +2006 +(in +thousands, except per share data) +Total +revenues +$ +310,351 +$ +315,492 +Net +income +$ +34,571 +$ +243,105 +Earnings +per common share: +Basic +$ +2.34 +$ +15.52 +Diluted +$ +2.33 +$ +15.44 +The pro +forma results of operations are not necessarily indicative of what our results +of operations would have been had the EXCO properties, our sponsored +partnerships and the Castle properties been acquired at the beginning of the +periods indicated, nor does it purport to represent our results of operations +for any future periods. +2006 +Acquisitions +On +December 6, 2006, we completed a cash tender offer and purchased approximately +95.5% or 9,112,750 shares of the outstanding common stock of Unioil, an +independent energy company with properties in northern Colorado and southern +Wyoming. The acquisition of more than 90% of the outstanding shares +of common stock allowed us to effect a short-form merger of Unioil and one of +our wholly-owned subsidiaries, resulting in the acquisition of the remaining +428,719 shares of Unioil. Each share of Unioil common stock not +tendered through the offer was converted into the right to receive $1.91 in +cash, the same consideration paid for shares in the tender offer. The +total price paid for 100% of Unioil’s outstanding common stock was $18.6 +million, including $0.4 million in direct costs of the +acquisition. The final acquisition cost allocation as reflected on +our consolidated balance sheets as of December 31, 2007, included $25.8 million +in properties and equipment, current assets of $0.7 million, a deferred tax +liability of $6.8 million and other liabilities assumed of $1 +million. The pro forma effect of the inclusion of Unioil in our 2006 +results of operations was not material. +F-38 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +NOTE +15 – MAJOR CUSTOMERS +The +following table identifies sales to individual customers constituting 10% or +more of oil and natural gas sales, including natural gas sales by our natural +gas marketing activities segment, and total revenues. +Oil +and Gas Sales +Total +Revenues +Year +Ended December 31, +Year +Ended December 31, +2008 +2007 +2006 +2008 +2007 +2006 +Customer +Williams +Production RMT Company +16.3 +% +14.1 +% +8.7 +% +12.4 +% +12.9 +% +7.5 +% +Tepco +Crude Oil, LLC +14.3 +% +14.8 +% +14.9 +% +10.8 +% +13.5 +% +12.9 +% +DCP +Midstream, LP +8.8 +% +7.8 +% +10.6 +% +6.6 +% +7.1 +% +9.1 +% +Sempra +Energy Trading +5.4 +% +6.0 +% +10.3 +% +4.1 +% +5.5 +% +8.9 +% +NOTE +16 - BUSINESS SEGMENTS +We +separate our operating activities into four segments: oil and gas +sales, natural gas marketing, well operations and pipeline income and oil and +gas well drilling operations. All material inter-company accounts and +transactions between segments have been eliminated. +Oil and Gas Sales. Our +oil and gas sales segment represents revenues and expenses from the production +and sale of oil and natural gas. Segment revenue includes oil and gas +price risk management, net. Segment profit consists of oil and gas +sales revenues less its proportionate share of oil and gas production and well +operations cost, exploration expense, direct general and administrative expense +and DD&A expense. Segment DD&A expense was $100.2 million, +$68.1 million and $31.3 million in 2008, 2007 and 2006, +respectively. +Natural Gas Marketing +Activities. Our +natural gas marketing segment is composed of our wholly owned subsidiary, RNG, +through which we purchase, aggregate and resell natural gas produced by us and +others. Segment profit primarily represents sales from natural gas +marketing activities and direct interest income less costs of natural gas +marketing activities, direct general and administrative expense. +Well Operations and Pipeline +Income. We +charge our affiliated partnerships and other third parties competitive industry +rates for well operations and natural gas gathering. Segment revenue +includes monthly operating and gas gathering fees we charge for each well in +which we operate that is owned by others, including our sponsored +partnerships. Segment profit consists of well operations and pipeline +income revenues less its proportionate share of oil and gas production and well +operations cost and direct DD&A expense. Segment DD&A expense +was $1.9 million, $1.2 million and $1.9 million in 2008, 2007, 2006, +respectively. +Oil and Gas Well Drilling +Operations. We drill natural gas +wells for Company-sponsored drilling partnerships and retain an interest in each +well. Our drilling and development segment reflects results of drilling and +development activities conducted for affiliated and non-affiliated +parties. Segment profit consists of oil and gas well drilling +revenues less cost of oil and gas well drilling. +Other. This +segment includes unallocated corporate general administrative expense, direct +DD&A expense, direct interest income and interest expense. +F-39 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Segment +information for the years ended December 31, 2008, 2007 and 2006 is presented +below. +Year +Ended December 31, +2008 +2007 +2006 +Revenues: +(in +thousands) +Oil +and gas sales +$ +449,715 +$ +177,943 +$ +124,336 +Natural +gas marketing activities +140,263 +103,624 +131,326 +Well +operations and pipeline income +11,474 +9,342 +10,704 +Oil +and gas well drilling operations +7,615 +12,154 +17,917 +Unallocated +amounts +293 +2,172 +2,220 +Total +$ +609,360 +$ +305,235 +$ +286,503 +Segment +Income Before Income Taxes: +Oil +and gas sales +$ +231,885 +$ +42,068 +$ +61,868 +Natural +gas marketing activities +1,329 +3,822 +1,816 +Well +operations and pipeline income +3,933 +3,136 +2,823 +Oil +and gas well drilling operations +5,402 +9,646 +5,300 +Unallocated +amounts +(67,781 +) +(4,482 +) +315,602 +Total +$ +174,768 +$ +54,190 +$ +387,409 +Expenditures +for Segment Long-Lived Assets: +Oil +& gas sales +$ +309,395 +$ +226,801 +$ +133,401 +Natural +gas marketing activities +- +- +- +Well +operations and pipeline income +7,564 +6,715 +1,419 +Oil +and gas well drilling operations +- +- +- +Unallocated +amounts +6,194 +5,472 +12,125 +Total +$ +323,153 +$ +238,988 +$ +146,945 +As +of December 31, +Segment +Assets: +Oil +& gas sales +$ +1,247,687 +$ +862,237 +$ +394,952 +Natural +gas marketing activities +50,117 +40,269 +39,899 +Well +operations and pipeline income +50,052 +26,156 +28,895 +Oil +and gas well drilling operations +2,028 +4,959 +87,746 +Unallocated +amounts +52,820 +116,858 +332,795 +Total +$ +1,402,704 +$ +1,050,479 +$ +884,287 +NOTE +17 – SUBSEQUENT EVENTS +West +Virginia royalty litigation . On January 26, 2009, we received notice of a lawsuit +filed in West Virginia state court in Barbour County, Beymer +and Beymer v. Petroleum Development Corporation and Riley National Gas +Company , CA No. 09-C-3 (“Beymer lawsuit”) , alleging a class action for +failure to properly pay royalties. The allegations state that the +Company improperly deducted certain charges and costs before applying the +royalty percentage. Punitive damages are requested in addition to +breach of contract, tort, and fraud allegations. On February 25, +2009, we filed to remove the action to federal court. +On +January 30, 2009, the Company was served with another lawsuit alleging class +action related to royalty payments file in West Virginia state court in Harrison +County, Gobel, +Phares and Cather v. Petroleum Development Corporation , CA No. +09-40-2. West Virginia oil and gas production constitutes +approximately 8% of the Company’s current oil and gas sales. Given +the preliminary stage of these proceedings and the inherent uncertainty in +litigation, the Company is unable to predict the ultimate outcome of these suits +at this time. +F-40 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +NOTE +18 – SUPPLEMENTAL OIL AND GAS INFORMATION – UNAUDITED +Costs +Incurred in Oil and Gas Property Acquisition, Exploration and Development +Activities +We +incurred costs in oil and gas property acquisition, exploration and development +are presented below. +Year +Ended December 31, +2008 +2007 +2006 +(in +thousands) +Acquisition +of properties: +Proved +properties +$ +6,147 +$ +257,330 +$ +802 +Unproved +properties +6,890 +13,701 +11,926 +Development +costs +257,656 +194,031 +114,487 +Exploration +costs: +Exploratory +drilling +26,499 +12,972 +18,660 +Geological +and Geophysical +2,121 +6,299 +2,234 +Total +costs incurred +$ +299,313 +$ +484,333 +$ +148,109 +The +proved reserves attributable to the development costs in the above table were +125,198 MMcf and 2,354 MBbls for 2008, 216,383 MMcf +and 3,700 MBbls for 2007 and 64,126 MMcf and 2,955 MBbls for 2006. Of +the above development costs incurred for the years ended December 31, 2008, 2007 +and 2006, the amounts of $66.2 million, $37.1 million, and $20.1 million, +respectively, were incurred to develop proved undeveloped properties from the +prior year end. +Property +acquisition costs include costs incurred to purchase, lease or otherwise acquire +a property. Development costs include costs incurred to gain access +to and prepare development well locations for drilling, to drill and equip +development wells, recompletions and to provide facilities to extract, treat, +gather and store oil and gas. Exploration costs include costs +incurred in identifying areas that may warrant examination and in examining +specific areas that are considered to have prospects of containing oil and gas +reserves. +Capitalized +Oil and Gas Costs +Aggregate +capitalized costs for related to oil and gas exploration and production +activities with applicable accumulated depreciation, depletion and amortization +are presented below: +December +31, +2008 +2007 +(in +thousands) +Proved +oil and gas properties +$ +1,245,316 +$ +953,904 +Unproved +oil and gas properties +32,768 +41,023 +1,278,084 +994,927 +Less +accumulated depreciation, depletion and amortization +306,142 +196,310 +$ +971,942 +$ +798,617 +F-41 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Results +of Operations for Oil and Gas Producing Activities +The +results of operations for oil and gas producing activities, excluding natural +gas marketing activities, are presented below. +Year +Ended December 31, +2008 +2007 +2006 +(in +thousands) +Revenue: +Oil +and gas sales +$ +321,877 +$ +175,187 +$ +115,189 +Oil +and gas price risk management gain, net +127,838 +2,756 +9,147 +449,715 +177,943 +124,336 +Expenses: +Production +costs +72,518 +44,238 +20,855 +Depreciation, +depletion and amortization +100,207 +68,086 +30,988 +Exploration +costs +45,105 +23,551 +8,131 +217,830 +135,875 +59,974 +Results +of operations for oil and gas producing activities before provision for +income taxes +231,885 +42,068 +64,362 +Provision +for income taxes +86,493 +16,280 +24,818 +Results +of operations for oil and gas producing activities, excludes corporate +overhead and interest costs +$ +145,392 +$ +25,788 +$ +39,544 +Production +costs include those costs incurred to operate and maintain productive wells and +related equipment, including costs such as labor, repairs, maintenance, +materials, supplies, fuel consumed, insurance and production and severance +taxes. In addition, production costs include administrative expenses +and depreciation applicable to support equipment associated with these +activities. Depreciation, depletion and amortization expense includes those +costs associated with capitalized acquisition, exploration and development +costs, but does not include the depreciation applicable to support +equipment. The provision for income taxes is computed using effective +tax rates. +Net +Proved Oil and Gas Reserves +We +utilized the services of independent petroleum engineers to estimate our oil and +gas reserves. For the years ended December 31, 2008 and 2007, our +reserve estimates for the Appalachian and Michigan Basins are based on reserve +reports prepared by Wright & Company and for the Rocky Mountain Region, +reserve estimates are based on reserve reports prepared by Ryder Scott Company, +L.P. For the year ended December 31, 2006, our reserve estimates for +the Appalachian and Michigan Basins and NECO Area were based on reserve reports +prepared by Wright & Company and our reserve estimates for the Rocky +Mountain Region, with the exception of the NECO properties, were based on +reserve reports prepared by Ryder Scott. These reserve estimates have +been prepared in compliance with professional standards and the reserves +definitions prescribed by the SEC. +Proved +reserves are the estimated quantities of oil and natural gas that geologic and +engineering data demonstrate with reasonable certainty to be recoverable in +future years from known reservoirs under existing economic and operating +conditions. Estimates of proved reserves may change, either +positively or negatively, as additional information becomes available and as +contractual, economic and political conditions change. The Company's +net proved reserve estimates have been adjusted as necessary to reflect all +contractual agreements, royalty obligations and interests owned by others at the +time of the estimate. +Proved +developed reserves are the quantities of oil and natural gas expected to be +recovered through existing wells with existing equipment and operating +methods. In some cases, proved +undeveloped reserves may require substantial new investments in +additional wells and related facilities. +F-42 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +An +analysis of the change in estimated quantities of oil and gas reserves, all of +which are located within the U.S., is shown below. +Oil +(MBbl) +Gas +(MMcf) +Total +(MMcfe) +Proved +Reserves: +Proved +reserves, January 1, 2006 +4,538 +247,288 +274,516 +Revisions +of previous estimates +226 +(21,721 +) +(20,365 +) +Extensions, +discoveries and other additions +Michigan +Basin +- +225 +225 +Rocky +Mountain Region +2,955 +63,901 +81,631 +Purchases +of reserves +Appalachian +Basin +- +222 +222 +Michigan +Basin +- +35 +35 +Rocky +Mountain Region +276 +3,504 +5,160 +Dispositions +to partnerships +(92 +) +(1,215 +) +(1,767 +) +Production +(631 +) +(13,161 +) +(16,947 +) +Proved +reserves, December 31, 2006 +7,272 +279,078 +322,710 +Revisions +of previous estimates +1,375 +14,177 +22,427 +Extensions, +discoveries and other additions +Appalachian +Basin +- +5,493 +5,493 +Michigan +Basin +- +488 +488 +Rocky +Mountain Region +3,700 +210,402 +232,602 +Purchases +of reserves +Appalachian +Basin +2 +63,014 +63,026 +Michigan +Basin +- +6,059 +6,059 +Rocky +Mountain Region +4,490 +39,239 +66,179 +Dispositions +to partnerships +(591 +) +(1,874 +) +(5,420 +) +Production +(910 +) +(22,513 +) +(27,973 +) +Proved +reserves, December 31, 2007 +15,338 +593,563 +685,591 +Revisions +of previous estimates +(1,538 +) +(25,216 +) +(34,444 +) +Extensions, +discoveries and other additions +Appalachian +Basin +- +24,875 +24,875 +Rocky +Mountain Region +2,354 +100,323 +114,447 +Purchases +of reserves +Appalachian +Basin +- +83 +83 +Michigan +Basin +- +46 +46 +Rocky +Mountain Region +106 +1,712 +2,348 +Dispositions +to partnerships +(63 +) +(769 +) +(1,147 +) +Production +(1,160 +) +(31,760 +) +(38,720 +) +Proved +reserves, December 31, 2008 +15,037 +662,857 +753,079 +Proved +Developed Reserves (1) , +as of: +January +1, 2006 +2,848 +146,664 +163,752 +December +31, 2006 +3,503 +144,672 +165,690 +December +31, 2007 +5,219 +286,570 +317,884 +December +31, 2008 +5,438 +297,041 +329,669 +______________ +(1) +December +31, 2008, 2007, 2006, and January 1, 2006, reserve amounts reflect the +reclassification of our Rocky Mountain Region refrac and behind pipe +reserves of 75,863 MMcfe, 49,801 MMcfe, 21,062 MMcfe and 14,762 MMcfe, +respectively, from proved developed to proved +undeveloped. +F-43 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +2008 +Activity. In 2008, we +recorded a downward revision of our previous estimate of proved reserves of +approximately 34 Bcfe. The revision was primarily due to a decrease +of approximately 50 Bcfe due to lower commodity prices, 26 Bcfe due to increased +operating costs, and 15 Bcfe due to adjustments to proved undeveloped reserve +values, partially offset be an increase of 55 Bcfe due to asset +performance. New discoveries and extensions of 139 Bcfe in 2008 are +due to drilling of 229 net wells and the addition of new proved undeveloped +reserves. Approximately 25 Bcfe were added in the Appalachian Basin, +and approximately 114 Bcfe were added in the Rocky Mountain Region with 26 Bcfe +in the Wattenberg Field, 80 Bcfe in Grand Valley Field, and 8 Bcfe in the NECO +area. We acquired approximately 2 Bcfe of proved reserves through the +purchases of interest in some of our existing properties. We +primarily acquired reserves in the Wattenberg Field with the remaining reserves +being split between the Appalachian Basin, Michigan, Piceance, the NECO area and +North Dakota. We sold proved reserves of approximately 1 Bcfe to +unaffiliated third parties and to our sponsored partnerships for drilling +activity. +2007 Activity . In +2007, we recorded an upward revision to our previous estimate of proved reserves +of approximately 22 Bcfe. The revision was primarily due to an +increase of approximately 25 Bcfe and 12 Bcfe, respectively, due to asset +performance and higher commodity prices, partially offset by a decrease of +approximately 15 Bcfe due primarily to increased operating costs, adjustments to +proved undeveloped reserve values and change in well ownership +interests. New discoveries and extensions of 239 Bcfe in 2007 are due +to the drilling of 218 net wells and the addition of new proved undeveloped +reserves. Approximately 233 Bcfe were added in the Rocky Mountain +Region, with 43 Bcfe in the Wattenberg Field, 170 Bcfe in Grand Valley Field and +19 Bcfe in the NECO area. We acquired approximately 135 Bcfe of +proved reserves through purchases of oil and natural gas +properties. In the Rocky Mountain Region approximately 66 Bcfe of +proved reserves were acquired in the Wattenberg Field, in the Appalachian Basin +approximately 75 Bcfe were acquired and approximately 6 Bcfe in the Michigan +Basin. We sold proved reserves of approximately 5 Bcfe to +unaffiliated third parties and to our sponsored partnerships for drilling +activity. +2006 Activity. In +2006 we recorded a downward revision to our previous estimate of proved reserves +of approximately 20 Bcfe. The revision was primarily due to a +decrease of 3 Bcfe due to asset performance and a decrease of 10 Bcfe due to +lower commodity prices and a decrease of approximately 7 Bcfe due to changes in +proved undeveloped reserve value, operating expense, and well ownership +interests. New discoveries and extensions in 2006 of approximately 82 +Bcfe were primarily due to the drilling of 91 net wells and adding new proved +undeveloped reserves in the Rocky Mountain Region. Approximately 34 +Bcfe were added in Wattenberg Field, 33 Bcfe in Grand Valley Field and 12 Bcfe +in the NECO area. We acquired approximately 5 Bcfe of proved reserves +through purchases of oil and natural gas properties in Wattenberg +Field. We sold proved reserves of approximately 2 Bcfe to our +sponsored partnerships. +Standardized +Measure of Discounted Future Net Cash Flows and Changes Therein Relating to +Proved Oil and Gas Reserves +Summarized +in the following table is information with respect to the standardized measure +of discounted future net cash flows relating to proved oil and gas +reserves. Future cash inflows are computed by applying year-end +prices of oil and gas relating to our proved reserves to the year-end quantities +of those reserves. Future production, development, site restoration +and abandonment costs are derived based on current costs assuming continuation +of existing economic conditions. Future income tax expenses are +computed by applying the statutory rate in effect at the end of each year to the +future pretax net cash flows, less the tax basis of the properties and gives +effect to permanent differences, tax credits and allowances related to the +properties. +2008 +2007 +2006 +(in +thousands) +Future +estimated cash flows +$ +3,867,461 +$ +5,257,962 +$ +1,804,796 +Future +estimated production costs +(1,325,362 +) +(1,374,027 +) +(571,346 +) +Future +estimated development costs +(1,100,533 +) +(876,961 +) +(373,460 +) +Future +estimated income tax expense +(384,676 +) +(1,159,489 +) +(334,536 +) +Future +net cash flows +1,056,890 +1,847,485 +525,454 +10% +annual discount for estimated timing of cash flows +(700,085 +) +(1,094,414 +) +(309,792 +) +Standardized +measure of discounted future +estimated net cash flows +$ +356,805 +$ +753,071 +$ +215,662 +F-44 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +The +following table summarizes the principal sources of change in the standardized +measure of discounted future estimated net cash flows. +2008 +2007 +2006 +(in +thousands) +Sales +of oil and gas production net of production costs +$ +(261,692 +) +$ +(137,725 +) +$ +(94,337 +) +Net +changes in prices and production costs +(479,894 +) +157,797 +(301,132 +) +Extensions, +discoveries, and improved recovery, less related costs +80,859 +317,031 +46,109 +Sales +of reserves +(2,012 +) +(7,846 +) +(3,356 +) +Purchase +of reserves +4,280 +342,792 +11,003 +Development +costs incurred during the period +88,008 +42,510 +20,051 +Revisions +of previous quantity estimates +(79,536 +) +92,462 +(22,090 +) +Changes +in estimated income taxes +239,054 +(335,327 +) +120,818 +Accretion +of discount +122,409 +38,660 +62,838 +Timing +and other +Timing +(20,117 +) +27,055 +(29,672 +) +Net +changes in future development costs +(87,625 +) +- +- +Total +$ +(396,266 +) +$ +537,409 +$ +(189,768 +) +It is +necessary to emphasize that the data presented should not be viewed as +representing the expected cash flow from, or current value of, existing proved +reserves since the computations are based on a large number of estimates and +arbitrary assumptions. Reserve quantities cannot be measured with +precision and their estimation requires many judgmental determinations and +frequent revisions. The required projection of production and related +expenditures over time requires further estimates with respect to pipeline +availability, rates of demand and governmental control. Actual future +prices and costs are likely to be substantially different from the current +prices and costs utilized in the computation of reported amounts. Any +analysis or evaluation of the reported amounts should give specific recognition +to the computational methods utilized and the limitations inherent +therein. +The +estimated present value of future cash flows relating to proved reserves is +extremely sensitive to prices used at any measurement period. The +average December 31 price used for each commodity at December 31, 2008, 2007 and +2006 is presented below. +Average +Price +As +of December 31, +Oil +Gas +2008 +$ +37.85 +$ +4.98 +2007 +80.67 +6.77 +2006 +57.70 +4.96 +F-45 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +NOTE +19 - QUARTERLY FINANCIAL DATA (UNAUDITED) +Quarterly +financial data for the years ended December 31, 2008 and 2007, are presented +below The sum of the quarters may not equal the total of the +year's net income per share due to changes in the weighted average shares +outstanding throughout the year. +2008 +Quarter +Ended +3/31/2008 +6/30/2008 +9/30/2008 +12/31/2008 +Year +Ended +(in +thousands, except per share data) +Revenues: +Oil +and gas sales +$ +71,646 +$ +94,549 +$ +99,422 +$ +56,260 +$ +321,877 +Sales +from natural gas marketing activities +23,325 +30,941 +53,372 +32,625 +140,263 +Oil +and gas well drilling +3,083 +2,887 +1,232 +413 +7,615 +Well +operations and pipeline income +2,352 +2,438 +3,356 +3,328 +11,474 +Oil +and gas price risk management gain (loss), net +(42,310 +) +(101,798 +) +169,402 +102,544 +127,838 +Other +income +3 +34 +20 +236 +293 +Total +revenues +58,099 +29,051 +326,804 +195,406 +609,360 +Costs +and expenses: +Oil +and gas production and well operations costs +18,132 +20,815 +22,173 +17,089 +78,209 +Cost +of natural gas marketing activities +22,121 +30,117 +54,372 +32,624 +139,234 +Cost +of oil and gas well drilling +78 +518 +501 +1,116 +2,213 +Exploration +expense +4,283 +3,467 +10,212 +27,143 +45,105 +General +and administrative expense +9,823 +9,231 +8,106 +10,555 +37,715 +Depreciation, +depletion and amortization +21,131 +22,105 +28,645 +32,694 +104,575 +Total +costs and expenses +75,568 +86,253 +124,009 +121,221 +407,051 +Income +(loss) from operations +(17,469 +) +(57,202 +) +202,795 +74,185 +202,309 +Interest +income +271 +75 +151 +94 +591 +Interest +expense +(4,932 +) +(6,394 +) +(7,817 +) +(8,989 +) +(28,132 +) +Income +(loss) before income taxes +(22,130 +) +(63,521 +) +195,129 +65,290 +174,768 +Provision +(benefit) for income taxes +(8,202 +) +(22,809 +) +68,233 +24,237 +61,459 +Net +income (loss) +$ +(13,928 +) +$ +(40,712 +) +$ +126,896 +$ +41,053 +$ +113,309 +Earnings +per common share: +Basic +$ +(0.95 +) +$ +(2.76 +) +$ +8.59 +$ +2.78 +$ +7.69 +Diluted +$ +(0.95 +) +$ +(2.76 +) +$ +8.55 +$ +2.78 +$ +7.63 +Weighted +average common and common equivalent shares outstanding: +Basic +14,738 +14,742 +14,767 +14,778 +14,736 +Diluted +14,738 +14,742 +14,835 +14,791 +14,848 +F-46 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +2007 +Quarter +Ended +3/31/2007 +6/30/2007 +9/30/2007 +12/31/2007 +Year +Ended +(in +thousands, except per share data) +Revenues: +Oil +and gas sales +$ +34,016 +$ +39,246 +$ +44,437 +$ +57,488 +$ +175,187 +Sales +from natural gas marketing activities +21,987 +29,924 +19,934 +31,779 +103,624 +Oil +and gas well drilling +4,030 +1,739 +1,573 +4,812 +12,154 +Well +operations and pipeline income +3,298 +1,292 +2,092 +2,660 +9,342 +Oil +and gas price risk management (loss) gain, net +(5,645 +) +3,742 +6,345 +(1,686 +) +2,756 +Other +income +226 +2 +1,894 +50 +2,172 +Total +revenues +57,912 +75,945 +76,275 +95,103 +305,235 +Costs +and expenses: +Oil +and gas production costs and well operations costs +9,035 +11,628 +12,645 +15,956 +49,264 +Cost +of natural gas marketing activities +21,512 +28,780 +19,810 +30,482 +100,584 +Cost +of oil and gas well drilling +564 +246 +749 +949 +2,508 +Exploration +expense +2,678 +6,780 +5,337 +8,756 +23,551 +General +and administrative expense +7,424 +6,886 +7,513 +9,145 +30,968 +Depreciation, +depletion and amortization +13,074 +17,429 +20,354 +19,987 +70,844 +Total +costs and expenses +54,287 +71,749 +66,408 +85,275 +277,719 +Gain +on sale of leaseholds +- +25,600 +- +7,691 +33,291 +Income +from operations +3,625 +29,796 +9,867 +17,519 +60,807 +Interest +income +1,143 +454 +462 +603 +2,662 +Interest +expense +(831 +) +(1,450 +) +(2,544 +) +(4,454 +) +(9,279 +) +Income +before income taxes +3,937 +28,800 +7,785 +13,668 +54,190 +Income +taxes +1,436 +10,749 +3,326 +5,470 +20,981 +Net +income +$ +2,501 +$ +18,051 +$ +4,459 +$ +8,198 +$ +33,209 +Earnings +per common share: +Basic +$ +0.17 +$ +1.22 +$ +0.30 +$ +0.56 +$ +2.25 +Diluted +$ +0.17 +$ +1.21 +$ +0.30 +$ +0.55 +$ +2.24 +Weighted +average common and common equivalent shares outstanding: +Basic +14,726 +14,740 +14,757 +14,758 +14,744 +Diluted +14,854 +14,860 +14,827 +14,859 +14,841 +F-47 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Schedule +II -VALUATION AND QUALIFYING ACCOUNTS +Description +Beginning +Balance +January 1 +Charged +to +Costs +and Expenses +Deductions +Ending +Balance +December 31 +(in +thousands) +2008: +Allowance +for doubtful accounts +(a) +$ +357 +$ +180 +$ +- +$ +537 +Valuation +allowance for unproved oil and gas properties +(b) +$ +2,365 +$ +12,798 +$ +2,293 +$ +12,870 +2007: +Allowance +for doubtful accounts +(a) +$ +415 +$ +50 +$ +108 +$ +357 +Valuation +allowance for unproved oil and gas properties +(b) +$ +596 +$ +2,183 +$ +414 +$ +2,365 +2006: +Allowance +for doubtful accounts +(a) +$ +409 +$ +7 +$ +1 +$ +415 +Valuation +allowance for unproved oil and gas properties +(b) +$ +33 +$ +653 +$ +90 +$ +596 +(a) +Deductions represent the write-off of accounts receivable deemed +uncollectible. +(b) +Deductions represent amortization of expired or abandoned unproved +oil and gas +properties. +F-48 \ No newline at end of file diff --git a/raw/filings/0000077877/2008/0001140361-09-005340/filing_metadata.csv b/raw/filings/0000077877/2008/0001140361-09-005340/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..8cad86edc13dcf4f6a555c2f41671602d12b7de1 --- /dev/null +++ b/raw/filings/0000077877/2008/0001140361-09-005340/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 +0000077877,PDCE,"PDC ENERGY, INC.",10-K,2009-02-27,2008-12-31,2009-02-27T20:47:28.000Z,0001140361-09-005340,form10k.htm,PETROLEUM DEVELOPMENT CORP 10-K 12-31-2008,6647224,0,0,https://www.sec.gov/Archives/edgar/data/77877/000114036109005340/form10k.htm,https://www.sec.gov/Archives/edgar/data/77877/000114036109005340/,2008,2008,1 diff --git a/raw/filings/0000077877/2008/0001140361-09-005340/item1.txt b/raw/filings/0000077877/2008/0001140361-09-005340/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..86038dd17a7bdef1e73e7bef5f39a1ab04716e08 --- /dev/null +++ b/raw/filings/0000077877/2008/0001140361-09-005340/item1.txt @@ -0,0 +1,10303 @@ +Item 1 and in Note +1 , Summary of +Significant Accounting Policies , to our consolidated financial statements +included in this report. +Substantially +all of our oil and natural gas properties have been mortgaged or pledged as +security for our credit facility. See Note 6, Long Term Debt , to our +accompanying consolidated financial statements included in this +report. +Facilities +We own +our 32,000 square feet corporate office building located in Bridgeport, West +Virginia. We lease approximately 5,000 and 17,000 square feet of +office space in two buildings near our current corporate office through March +2010 and November 2011, respectively. We lease 15,700 square feet of +office space in downtown Denver, Colorado through March 2012, which effective +March 1, 2009, will become our corporate headquarters. +We own or +lease field operating facilities in the following locations: +· +West +Virginia: Bridgeport, Glenville and West +Union +· +Michigan: Ossineke +· +Colorado: Evans, +Parachute and Wray +· +Pennsylvania: Indiana +and Mahaffey +ITEM 3. LEGAL PROCEEDINGS +Information regarding our legal proceedings can be found in Note 8 , Commitments and Contingencies – +Litigation and Note 17 , Subsequent Events , to our +consolidated financial statements included in this report. +ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY +HOLDERS +None. +PART +II +ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY, +RELATED STOCKHOLDERS MATTERS AND ISSUER PURCHASES OF EQUITY +SECURITIES. +Our +authorized capital stock consists of 100,000,000 shares of common stock, par +value $0.01 per share. Our common stock is traded on the NASDAQ +Global Select Market under the ticker symbol PETD. +26 +Table of Contents +The +following table sets forth the range of high and low sales prices for our common +stock as reported on the NASDAQ Global Select Market for the periods indicated +below. +High +Low +2008 +First +Quarter +$ +73.92 +$ +50.75 +Second +Quarter +79.09 +66.37 +Third +Quarter +68.76 +34.15 +Fourth +Quarter +44.75 +11.50 +2007 +First +Quarter +$ +55.20 +$ +40.53 +Second +Quarter +55.24 +44.59 +Third +Quarter +51.13 +35.73 +Fourth +Quarter +61.91 +41.65 +As of +February 23, 2009, we had approximately 1,107 shareholders of +record. +We +have not paid any dividends on our common stock and currently intend to retain +earnings for use in our business. We do not expect to declare cash +dividends in the foreseeable future. +The +following table presents information about our purchases of our common stock +during the three months ended December 31, 2008. +Period +Total Number of +Shares Purchased (1) +Average Price Paid per +Share +Total Number of +Shares Purchased as Part of Publicly Announced Plans or +Programs +Maximum Number of Shares that May Yet Be Purchased +Under the Plans or Programs +October +1 - 31, 2008 +118 +$ +20.71 +- +- +November +1-30, 2008 +351 +15.74 +- +- +December +1-31, 2008 +827 +24.88 +- +- +Total +fourth quarter purchases +1,296 +22.02 +______________ +(1) +Pursuant +to our stock-based compensation plans, the 1,296 shares purchased +during the quarter represent purchases from our employees for their +payment of tax liabilities related to the vesting of +securities. +On +October 16, 2006, our Board of Directors approved a share purchase program +authorizing us to purchase up to 10% of our then outstanding common stock +(1,477,109 shares) through April 2008. There were 1,465,089 shares +that were authorized but not yet purchased as of December 31, +2007. Total shares purchased in 2008 pursuant to the program were +64,263 common shares at a cost of $4.4 million ($67.97 average price paid per +share), including 63,756 shares from our executive officers at a cost of $4.3 +million ($67.98 price paid per share). Shares purchased from +employees, excluding executive officers, were generally purchased at fair market +value based on the closing price on the date of purchase and were primarily +purchased to satisfy the statutory minimum tax withholding requirement for +restricted stock that vested in 2008. Shares purchased from executive +officers were primarily pursuant to a separation agreement with our former +president and to satisfy the statutory minimum tax withholding requirements for +shares vested in 2008. The authorization to purchase the remaining +1,400,826 shares effectively expired on April 30, 2008. All shares +purchased in accordance with the program have been subsequently +retired. +27 +Table of Contents +SHAREHOLDER +PERFORMANCE GRAPH +The +performance graph below compares the cumulative total return of our common stock +over a five year period ended December 31, 2008, with the cumulative total +returns for the same period for a Standard Industrial Code Index, or SIC, and +the Standard and Poor's, or S&P, 500 Index. The SIC Code Index is +a weighted composite of 158 crude petroleum and natural gas +companies. The cumulative total shareholder return assumes that $100 +was invested, including reinvestment of dividends, if any, in our common stock +on December 31, 2003, and in the S&P 500 Index and the SIC Code Index on the +same date. The results shown in the graph below are not necessarily +indicative of future performance. +Year +Ended December 31, +2003 +2004 +2005 +2006 +2007 +2008 +PETROLEUM +DEVELOPMENT CORPORATION +$ +100 +$ +163 +$ +141 +$ +182 +$ +249 +$ +102 +SIC +CODE INDEX +100 +127 +183 +237 +334 +195 +S&P +500 INDEX +100 +111 +116 +135 +142 +90 +28 +Table of Contents +ITEM 6. SELECTED FINANCIAL DATA +Year +Ended December 31, +2008 +2007 +2006 +2005 +2004 +(in +thousands, except per share data) +Revenues: +Oil +and gas sales +$ +321,877 +$ +175,187 +$ +115,189 +$ +102,559 +$ +69,492 +Sales +from natural gas marketing activities +140,263 +103,624 +131,325 +121,104 +94,627 +Oil +and gas well drilling operations (1) +7,615 +12,154 +17,917 +99,963 +94,076 +Well +operations and pipeline income +11,474 +9,342 +10,704 +8,760 +7,677 +Oil +and gas price risk management gain (loss), net (2) +127,838 +2,756 +9,147 +(9,368 +) +(3,085 +) +Other +293 +2,172 +2,221 +2,180 +1,696 +Total +revenues +609,360 +305,235 +286,503 +325,198 +264,483 +Costs +and expenses: +Oil +and gas production and well operations costs +78,209 +49,264 +29,021 +20,400 +17,713 +Cost +of natural gas marketing activities +139,234 +100,584 +130,150 +119,644 +92,881 +Cost +of oil and gas well drilling operations (1) +2,213 +2,508 +12,617 +88,185 +77,696 +Exploration +expense +45,105 +23,551 +8,131 +11,115 +- +General +and administrative expense +37,715 +30,968 +19,047 +6,960 +4,506 +Depreciation, +depletion and amortization +104,575 +70,844 +33,735 +21,116 +18,156 +Total +costs and expenses +407,051 +277,719 +232,701 +267,420 +210,952 +Gain +on sale of leaseholds (3) +- +33,291 +328,000 +7,669 +- +Income +from operations +202,309 +60,807 +381,802 +65,447 +53,531 +Interest +income +591 +2,662 +8,050 +898 +185 +Interest +expense +(28,132 +) +(9,279 +) +(2,443 +) +(217 +) +(238 +) +Income +before income taxes +174,768 +54,190 +387,409 +66,128 +53,478 +Provision +for income taxes +61,459 +20,981 +149,637 +24,676 +20,250 +Net +income +$ +113,309 +$ +33,209 +$ +237,772 +$ +41,452 +$ +33,228 +Basic +earnings per common share +$ +7.69 +$ +2.25 +$ +15.18 +$ +2.53 +$ +2.05 +Diluted +earnings per share +$ +7.63 +$ +2.24 +$ +15.11 +$ +2.52 +$ +2.00 +As +of December 31, +2008 +2007 +2006 +2005 +2004 +Total +assets +$ +1,402,704 +$ +1,050,479 +$ +884,287 +$ +444,361 +$ +329,453 +Working +capital (deficit) +$ +31,266 +$ +(50,212 +) +$ +29,180 +$ +(16,763 +) +$ +231 +Long-term +debt +$ +394,867 +$ +235,000 +$ +117,000 +$ +24,000 +$ +21,000 +Shareholders' +equity +$ +511,581 +$ +395,526 +$ +360,144 +$ +188,265 +$ +154,021 +______________ +(1) +In +December 2005, we began entering into cost-plus drilling service +arrangements, which are recorded on a net basis unlike our footage based +arrangements which are recorded on a gross basis. See Note 1 , +“Summary of Significant Accounting Policies,” to our accompanying +consolidated financial statements included in this +report. Further, we have not sponsored a drilling program since +August 2007, related revenue continued to be recognized through +2008. +(2) +See +Note 3 , +“Derivative Financial Instruments”, to our accompanying consolidated +financial statements included in this +report. +(3) +In +July 2006, we sold a portion of our undeveloped leasehold located in Grand +Valley Field, Garfield County, Colorado. See Note 13 , “Sale +of Oil and Gas Properties,” to our accompanying consolidated financial +statements included in this +report. +29 +Table of Contents +ITEM 7. MANAGEMENT'S +DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF +OPERATIONS +The +following discussion and analysis, as well as other sections in this Form 10-K, +should be read in conjunction with our accompanying consolidated financial +statements and related notes to consolidated financial statements included in +this report. Further, we encourage you to revisit Special Note Regarding +Forward-Looking Statements on page 1 of this +report. +2008 +Overview +The year +2008 was a year of unprecedented events: oil and natural gas prices soared to +record and near record highs, respectively, through July; then, in the midst of +U.S. credit turmoil and a worldwide economic slump, in December, oil prices fell +to their lowest in four years and natural gas prices dropped almost by +half. Our reaction to these events is one of +caution. While we certainly felt the impact of these events, we +believe that we were successful in managing our operations in such a manner that +we were able to minimize the negative impacts while capitalizing on the positive +impacts. Our strong derivative position eased the impact of the fall +in oil and natural gas prices. We exit 2008 with $7.6 million in net +realized derivative gains, $31.4 million in the fourth quarter +alone. Further, we estimate the net fair value of our derivative +positions, excluding the derivative positions attributed to our affiliated +partnerships, as of December 31, 2008, to be $117.8 million. See +2009 Outlook and Liquidity and Capital +Resources sections below for a discussion of the steps we plan to take in +this uncertain economic environment. +For the +second consecutive year, our net wells drilled increased double digits, up 20.7% +in 2008 from 2007, which was up 100.1% from 2006. The increased +drilling activity was fueled by the July 2006 sale of an undeveloped leasehold +located in Grand Valley Field, Garfield County, Colorado, providing us with cash +proceeds of $353.6 million and our February 2008 senior notes offering with net +proceeds of $196 million. We ended 2008 with interests in 4,712 +gross, 3,259 net, wells located in the Rocky Mountain Region and the Appalachian +and Michigan Basins. In 2008, we recompleted 104 wells in the +Wattenberg Field and 21 wells in the Appalachian Basin. +The +decline in prices during the fourth quarter of 2008 has resulted in $118.4 +million in unrealized gains on derivatives for the year ended December 31, +2008. The $118.4 million in unrealized gains for the year is the fair +value of the derivative positions as of December 31, 2008, less the related +unrealized amounts recorded in prior periods. An unrealized gain is a +non-cash item and there will be further gains or losses as prices decrease or +increase until the positions mature or are closed. While the required +accounting treatment for derivatives that do not qualify for hedge accounting +treatment under SFAS No. 133 may result in significant swings in operating +results over the life of the derivatives, the combination of the settled +derivative contracts and the revenue received from the oil and gas sales at +delivery are expected to result in a more predictable cash flow stream than +would the sales contracts without the associated derivatives. +The +average NYMEX and CIG prices for the next 24 months (forward curve) from the +respective dates below are as follows: +December 31, +June 30, +December 31, +February 13, +Commodity +Index +2007 +2008 +2008 +2009 +Natural +gas: +NYMEX +$ +8.12 +$ +12.52 +$ +6.62 +$ +5.87 +CIG +6.78 +8.86 +4.49 +4.13 +Oil: +NYMEX +90.79 +140.15 +57.49 +53.07 +The +dramatic commodity price declines from June 30, 2008, through December 31, 2008, +relative to our current derivative positions, resulted in the significant +unrealized derivative gains in 2008. If there are further price +declines in 2009, unrealized derivatives gains on our current positions are +expected to continue. +30 +Table of Contents +2009 +Outlook +We +project that our 2009 production will be approximately 44.4 Bcfe or a 15% +increase over 2008 production. Our 2009 capital budget of $120 +million to $140 million represents an approximate 60% decrease compared to +2008. We selected this level of spending with the goal of remaining +debt neutral to help maintain adequate liquidity during 2009. We +realize that oil and gas prices may vary considerably from our +projections. We use oil and natural gas derivatives contracts in +order to reduce the effects of volatile commodity prices. As of +December 31, 2008, we had oil and natural gas hedges in place covering 52% of +our expected oil production and 62% of our expected natural gas production in +2009. +For 2009, +our drilling plans continue to be focused primarily in the Rocky Mountain +Region. We plan to drill approximately 166 gross wells, excluding +exploratory wells, of which 154 are in the Rocky Mountain Region and 12 are in +the Appalachian Basin. We are currently evaluating the exploration +potential of the Marcellus Formation in the Appalachian +Basin. Through a combination of lease, farmout and wellbore +ownership, we operate over 2,100 wells within the Marcellus “Fairway” +area. We currently have three wells drilled, two of which are in +line, and seven additional vertical tests are planned in 2009. +Due to +the continued decline in natural gas prices, in early 2009, we temporarily +ceased all of our drilling operations in the Piceance Basin, resulting in the +demobilization of the three contracted drilling rigs in this area. We +have included in our approved 2009 capital budget $40.4 million for drilling and +completion activities in the Piceance Basin. Should natural gas +prices change materially from the projected levels, we will reevaluate our +drilling options. +Results +of Operations +Summary +Operating Results +The +following table sets forth selected information regarding our results of +operations, including production volumes, oil and gas sales, average sales +prices received, average sales price including realized derivative gains and +losses, average lifting cost, other operating income and expenses for the years +ended December 31, 2008, 2007 and 2006. +31 +Table of Contents +Summary +Operating Results for the +Year Ended December 31, +Change +2008 +2007 +2006 +2008-2007 +2007-2006 +Production (1) +Oil +(Bbls) +1,160,408 +910,052 +631,395 +27.5 +% +44.1 +% +Natural +gas (Mcf) +31,759,792 +22,513,306 +13,160,784 +41.1 +% +71.1 +% +Natural +gas equivalent (Mcfe) (2) +38,722,240 +27,973,618 +16,949,154 +38.4 +% +65.0 +% +Oil and Gas +Sales (in thousands) +Oil +sales +$ +104,168 +$ +55,196 +$ +37,460 +88.7 +% +47.3 +% +Gas +sales +221,734 +119,991 +77,729 +84.8 +% +54.4 +% +Royalty +litigation provision +(4,025) +- +- +* +* +Total +oil and gas sales +$ +321,877 +$ +175,187 +$ +115,189 +86.0 +% +52.1 +% +Realized Gain (Loss) on +Derivatives, net (in thousands) +Oil +derivatives - realized loss +$ +(3,145 +) +$ +(177 +) +$ +- +* +* +Natural +gas derivatives - realized gain +12,632 +7,350 +1,895 +71.9 +% +* +Total +realized gain on derivatives, net +$ +9,487 +$ +7,173 +$ +1,895 +32.3 +% +* +Average +Sales Price +Oil +(per Bbl) (3) +$ +89.77 +$ +60.65 +$ +59.33 +48.0 +% +2.2 +% +Natural +gas (per Mcf) (3) +$ +6.98 +$ +5.33 +$ +5.91 +31.0 +% +-9.8 +% +Natural +gas equivalent (per Mcfe) +$ +8.42 +$ +6.26 +$ +6.80 +34.4 +% +-7.9 +% +Average +Sales Price (including realized gain (loss) on +derivatives) +Oil +(per Bbl) +$ +87.06 +$ +60.46 +$ +59.33 +44.0 +% +1.9 +% +Natural +gas (per Mcf) +$ +7.38 +$ +5.66 +$ +6.05 +30.5 +% +-6.5 +% +Natural +gas equivalent (per Mcfe) +$ +8.66 +$ +6.52 +$ +6.91 +32.9 +% +-5.6 +% +Average Lifting Cost per +Mcfe (4) +$ +1.07 +$ +0.90 +$ +0.76 +18.9 +% +18.4 +% +Other Operating +Income (5) (in +thousands) +Natural +gas marketing activities +$ +1,029 +$ +3,040 +$ +1,175 +-66.2 +% +158.7 +% +Oil +and gas well drilling operations +$ +5,402 +$ +9,646 +$ +5,300 +-44.0 +% +82.0 +% +Costs and Expenses (in +thousands) +Exploration +expense +$ +45,105 +$ +23,551 +$ +8,131 +91.5 +% +189.6 +% +General +and administrative expense +$ +37,715 +$ +30,968 +$ +19,047 +21.8 +% +62.6 +% +Depreciation, +depletion and amortization +$ +104,575 +$ +70,844 +$ +33,735 +47.6 +% +110.0 +% +Interest Expense (in +thousands) +$ +28,132 +$ +9,279 +$ +2,443 +203.2 +% +* +*Percentage +change not meaningful or equal to or greater than +250% +Amounts +may not calculate due to +rounding +_______________ +(1) +Production +is net and determined by multiplying the gross production volume of +properties in which we have an interest by the percentage of the leasehold +or other property interest we own. +(2) +A +ratio of energy content of natural gas and oil (six Mcf of natural gas +equals one Bbl of oil) was used to obtain a conversion factor to convert +oil production into equivalent Mcf of natural +gas. +(3) +We +utilize commodity based derivative instruments to manage a portion of our +exposure to price volatility of our natural gas and oil +sales. This amount excludes realized and unrealized gains and +losses on commodity based derivative +instruments. +(4) +Production +costs represent oil and gas operating expenses which exclude production +taxes. +(5) +Includes +revenues and operating +expenses. +32 +Table of Contents +Oil +and Gas Sales Activity +Oil +and Natural Gas Production and Sales Activity by Area +Year +Ended December 31, +Change +2008 +2007 +2006 +2008-2007 +2007-2006 +Production +Oil +(Bbls) +Appalachian +Basin +6,623 +5,490 +1,837 +20.6 +% +198.9 +% +Michigan +Basin +3,469 +4,301 +4,439 +-19.3 +% +-3.1 +% +Rocky +Mountain Region +1,150,316 +900,261 +625,119 +27.8 +% +44.0 +% +Total +1,160,408 +910,052 +631,395 +27.5 +% +44.1 +% +Natural +gas (Mcf) +Appalachian +Basin +3,902,183 +2,711,300 +1,451,729 +43.9 +% +86.8 +% +Michigan +Basin +1,609,984 +1,678,155 +1,399,852 +-4.1 +% +19.9 +% +Rocky +Mountain Region +26,247,625 +18,123,851 +10,309,203 +44.8 +% +75.8 +% +Total +31,759,792 +22,513,306 +13,160,784 +41.1 +% +71.1 +% +Natural +gas equivalent (Mcfe) +Appalachian +Basin +3,941,921 +2,744,240 +1,462,751 +43.6 +% +87.6 +% +Michigan +Basin +1,630,798 +1,703,961 +1,426,486 +-4.3 +% +19.5 +% +Rocky +Mountain Region +33,149,521 +23,525,417 +14,059,917 +40.9 +% +67.3 +% +Total +38,722,240 +27,973,618 +16,949,154 +38.4 +% +65.0 +% +Average +Sales Price (excluding derivative gains/losses) +Oil +(per Bbl) +Appalachian +Basin +$ +88.80 +$ +59.08 +$ +60.14 +50.3 +% +-1.8 +% +Michigan +Basin +100.79 +68.31 +61.07 +47.5 +% +11.9 +% +Rocky +Mountain Region +89.73 +60.62 +59.31 +48.0 +% +2.2 +% +Weighted +average price +89.77 +60.65 +59.33 +48.0 +% +2.2 +% +Natural +gas (per Mcf) +Appalachian +Basin +$ +9.21 +$ +6.99 +$ +7.37 +31.8 +% +-5.2 +% +Michigan +Basin +8.41 +6.12 +6.53 +37.4 +% +-6.3 +% +Rocky +Mountain Region +6.57 +5.01 +5.62 +31.1 +% +-10.9 +% +Weighted +average price +6.98 +5.33 +5.91 +31.0 +% +-9.8 +% +Natural +gas equivalent (per Mcfe) +Appalachian +Basin +$ +9.24 +$ +7.02 +$ +7.39 +31.6 +% +-5.0 +% +Michigan +Basin +8.52 +6.20 +6.60 +37.4 +% +-6.1 +% +Rocky +Mountain Region +8.32 +6.18 +6.75 +34.6 +% +-8.4 +% +Weighted +average price +8.42 +6.26 +6.80 +34.5 +% +-7.9 +% +Our oil +and natural gas sales revenues have increased in each of the past two years, +primarily due to increased volumes and higher average sales prices in 2008 and +increased volumes partially offset by lower average sales prices in +2007. Increased volumes contributed $90.5 million and $75 million to +the increase in oil and gas sales revenues in 2008 and 2007, +respectively. The increases in oil and natural gas volumes over the +past two years is attributable to the significant increase in the number of +wells drilled for our own account in 2008 and 2007 compared to those drilled in +prior years, and to a lesser extent, the acquisition of producing oil and gas +properties in the fourth quarter of 2006. The production volumes and +oil and gas sales revenue generated in 2007 from the acquisition of oil and gas +properties made in early 2007 and December 2006 and their subsequent development +were 6.5 Bcfe and $45.8 million, respectively. +33 +Table of Contents +Oil and Natural +Gas Pricing. Financial results depend +upon many factors, particularly the price of oil and natural gas and our ability +to market our production effectively. Oil and natural gas prices have +been among the most volatile of all commodity prices. These price +variations have a material impact on our financial results. Oil and +natural gas prices also vary by region and locality, depending upon the distance +to markets, and the supply and demand relationships in that region or +locality. This can be especially true in the Rocky Mountain +Region. The combination of increased drilling activity and the lack +of local markets have resulted in a local market oversupply situation from time +to time. Like most producers in the region, we rely on major +interstate pipeline companies to construct these facilities to increase pipeline +capacity, rendering the timing and availability of these facilities beyond our +control. Oil pricing is also driven strongly by supply and demand +relationships. +The price +we receive for a large portion of the natural gas produced in the Rocky Mountain +Region is based on a market basket of prices, which generally includes gas sold +at CIG prices as well as gas sold at Mid-Continent or other nearby region +prices. The CIG Index, and other indices for production delivered to +other Rocky Mountain pipelines, has historically been less than the price +received for natural gas produced in the eastern regions, which is NYMEX +based. +Although +82.6% of our 2008 natural gas production came from the Rocky Mountain Region, +much of our Rocky Mountain natural gas pricing is based upon other indices in +addition to CIG. The table below identifies the pricing basis of our +oil and natural gas pricing based on sales volumes for the year ended December +31, 2008. The pricing basis is the index that most closely relates to +the price under which our oil and natural gas is sold. +Energy +Market Exposure +as +of December 31, 2008 +Area +Pricing +Basis +Commodity +Percent +of +Oil +and Gas +Sales +Piceance/Wattenberg +Colorado +Interstate Gas (CIG) +Gas +39% +Colorado/North +Dakota +NYMEX +Oil +16% +NECO +Mid +Continent (Panhandle Eastern) +Gas +12% +Piceance +San +Juan Basin/Southern California +Gas +16% +Appalachian +NYMEX +Gas +10% +Michigan +Mich-Con/NYMEX +Gas +4% +Wattenberg +Colorado +Liquids +Gas +2% +Other +Other +Gas/Oil +1% +100% +Lifting +Costs . Lifting costs per +Mcfe , +excluding production taxes which fluctuate with oil and natural gas prices, have +increased approximately 18% annually since 2006, an increase of approximately +41% from 2006 to 2008. The increase is primarily due to general oil +field services and wage inflation pressures. As production volumes +increase when we add new wells, we can expect to see modest decreases in lifting +costs as we work on improving and stabilizing our lifting costs. In +our Rocky Mountain Region, we traditionally experience higher lifting costs due +to severe winter conditions for costs such as snow removal from well and access +roads, along with other weather related problems. +Oil and Gas +Production and Well Operations Costs . In addition to increased +production and the significant number of new wells operated, the increase in oil +and gas production and well operations costs in each of the past two years is +also attributable to additional personnel in the production and engineering +staffs, increased maintenance and operating cost of the new pipeline and +compressor upgrades and improvements, increased production enhancements and +workovers +associated with the early 2007 and December 2006 acquisitions and significant +general oil field services inflation pressures. Oil and gas +production and well operations cost includes our lifting cost, production taxes, +the cost to operate wells and pipelines for our sponsored partnerships and other +third parties (whose income is included in well operations and pipeline income) +and certain production and engineering staff related overhead +costs. In October 2007, in conjunction with the acquisition of oil +and gas properties (762 wells) located in southwestern Pennsylvania, we acquired +a well services operation. The costs related to this operation are +included in the statement of operations line item Oil and Gas Production and well +Operations Costs . +34 +Table of Contents +Oil +and Gas Price Risk Management, Net +Year +Ended December 31, +2008 +2007 +2006 +(in +thousands) +Oil +and gas price risk management, net: +Realized +gain (loss) +Oil +$ +(3,145 +) +$ +(177 +) +$ +- +Natural +gas +12,632 +7,350 +1,895 +Total +realized gain, net +9,487 +7,173 +1,895 +Unrealized +gain (loss), net +118,351 +(4,417 +) +7,252 +$ +127,838 +$ +2,756 +$ +9,147 +Oil and +gas price risk management, net includes realized gains and losses and unrealized +changes in the fair value of oil and natural gas derivatives related to our oil +and natural gas production. Oil and gas price risk management, net +does not include commodity based derivative transactions related to transactions +from natural gas marketing activities, which are included in sales from and cost +of natural gas marketing activities. See Note 2 , Fair Value of Financial +Instruments , and Note 3, Derivative Financial +Instruments , to the accompanying consolidated financial statements for +additional details of our derivative financial instruments. +Oil and +Gas Derivative Activities . We use various +derivative instruments to manage fluctuations in oil and natural gas +prices. We have in place a series of collars, fixed price swaps and +basis swaps on a portion of our oil and natural gas production. Under +the collar arrangements, if the applicable index rises above the ceiling price +or swap, we pay the counterparty; however, if the index drops below the floor or +swap, the counterparty pays us. Our production volumes for the +quarter ended December 31, 2008, were 326,000 Bbls of oil and 9.3 Bcf of natural +gas. +35 +Table of Contents +The +following table identifies our derivative positions (excluding the derivative +positions allocated to our affiliated partnerships) related to oil and gas sales +activities in effect as of December 31, 2008, on our production by +area. No new positions have been entered into subsequent to December +31, 2008, through the date of this filing. +Floors +Ceilings +Swaps +(Fixed Prices) +Basis +Swaps +Commodity/ +Index/ Operating +Area +Quantity +(Gas-MMbtu Oil-Bbls) +Weighted +Average Contract +Price +Quantity +(Gas-MMbtu Oil-Bbls) +Weighted +Average Contract +Price +Quantity +(Gas-MMbtu Oil-Bbls) +Weighted +Average Contract +Price +Quantity +(Gas-MMbtu Oil-Bbls) +Weighted +Average Contract +Price +Fair +Value +a t December 31, +2008 +(in thousands) +Natural +Gas +CIG +Piceance +Basin +1Q +2009 +- +$ +- +- +$ +- +2,388,158 +$ +8.08 +- +$ +- +$ +9,340 +2Q +2009 +2,116,233 +5.75 +2,116,233 +8.90 +- +- +- +- +4,358 +3Q +2009 +2,116,233 +5.75 +2,116,233 +8.90 +- +- +- +- +3,523 +4Q +2009 +1,536,701 +6.70 +1,536,701 +10.25 +584,500 +9.20 +6,490 +2010 +1,672,131 +6.80 +1,672,131 +10.90 +876,751 +9.20 +4,274,703 +1.88 +7,788 +2011 +637,795 +4.75 +637,795 +9.45 +- +- +4,698,955 +1.88 +689 +2012 +- +- +- +- +- +- +4,733,113 +1.88 +(1,907 +) +2013 +- +- +- +- +- +- +4,250,630 +1.88 +(2,846 +) +Wattenberg +Field +1Q +2009 +- +- +- +- +1,702,203 +8.07 +- +- +6,640 +2Q +2009 +1,524,639 +5.75 +1,524,639 +8.89 +- +- +- +- +3,140 +3Q +2009 +1,524,639 +5.75 +1,524,639 +8.89 +- +- +- +- +2,538 +4Q +2009 +1,119,322 +6.71 +1,119,322 +10.26 +424,381 +9.20 +- +- +4,725 +2010 +1,170,071 +6.90 +1,170,071 +10.98 +636,571 +9.20 +2,682,613 +1.88 +5,410 +2011 +380,112 +4.75 +380,112 +9.45 +- +- +2,951,819 +1.88 +429 +2012 +- +- +- +- +- +- +2,953,958 +1.88 +(1,190 +) +2013 +- +- +- +- +- +- +2,637,419 +1.88 +(1,766 +) +PEPL +NECO +1Q +2009 +- +- +- +- +810,000 +8.46 +- +- +3,315 +2Q +2009 +720,000 +6.14 +720,000 +10.81 +- +- +- +- +1,332 +3Q +2009 +720,000 +6.14 +720,000 +10.81 +- +- +- +- +984 +4Q +2009 +580,000 +7.81 +580,000 +12.68 +240,000 +10.91 +- +- +2,669 +2010 +1,410,000 +6.59 +1,410,000 +10.91 +1,060,000 +7.99 +- +- +3,741 +2011 +300,000 +6.00 +300,000 +10.10 +- +- +- +- +92 +NYMEX +Appalachian +and Michigan Basins +1Q +2009 +260,103 +8.40 +260,103 +13.05 +972,279 +9.71 +- +- +4,469 +2Q +2009 +905,212 +7.13 +905,212 +12.85 +429,743 +9.09 +- +- +2,836 +3Q +2009 +905,212 +7.13 +905,212 +12.85 +429,743 +9.09 +- +- +2,625 +4Q +2009 +868,186 +9.00 +868,186 +15.66 +429,457 +9.09 +- +- +3,367 +2010 +1,547,849 +8.22 +1,547,849 +14.19 +1,704,946 +9.08 +- +- +5,968 +2011 +232,277 +6.75 +232,277 +12.13 +800,844 +9.60 +- +- +1,731 +2012 +- +- +- +- +155,211 +9.89 +- +- +306 +Total +Natural Gas +80,796 +Oil +NYMEX +Watenberg +Field +1Q +2009 +- +- +- +- +154,188 +90.52 +- +- +6,428 +2Q +2009 +- +- +- +155,903 +90.52 +- +- +5,729 +3Q +2009 +- +- +- +- +157,615 +90.52 +- +- +5,291 +4Q +2009 +- +- +- +- +157,615 +90.52 +- +- +4,856 +2010 +- +- +- +- +529,664 +92.96 +- +- +14,702 +Total +Oil +37,006 +Total +Natural Gas and Oil +$ +117,802 +36 +Table of Contents +Natural +Gas Marketing Activities +The +increase in sales from natural gas marketing activities in 2008 compared to 2007 +is primarily due to an increase in prices and increased unrealized gains on +derivative instruments. The increase in costs of natural gas +marketing activities in 2008 compared to 2007 is primarily due to an increase in +prices and increased unrealized losses on derivative instruments. +In 2008, +prices on sales and purchases were 31.8% higher on average than in 2007, +resulting in a $27.8 million increase in sales and costs. The sales +related unrealized gain on derivatives increased by $6.4 million and the cost of +sales related unrealized loss on derivatives increased by $6.9 million. Volumes +sold and purchased for resale decreased slightly by 2%. +The +decrease in sales from natural gas marketing activities in 2007 compared to 2006 +is primarily due to a decrease in prices and volumes sold and a decrease in +unrealized gains on derivative instruments. The decrease in costs of +natural gas marketing activities in 2007 compared to 2006 is also due to a +decrease in prices and volumes purchased and a decrease in unrealized losses on +derivative instruments. +In 2007, +prices on sales and purchases were 5% lower on average than in 2006, resulting +in a $5 million decrease in sales and costs. In January 2007, we +acquired all of the outstanding partnership interests in 44 of our sponsored +drilling partnerships. Natural gas sales and purchases related to the +net 423 wells acquired no longer flowed through marketing activities; the result +was a decline in sales from and costs of natural gas marketing activities of +$12.2 million. This decline in partnership volumes was offset by an +increase in non-partnership volumes sold and purchased amounting to $3.7 +million, for a net volume effect of an $8.5 million decrease compared to +2006. The gain on unrealized sales decreased $14 million from a $12.3 +million gain in 2006 to a $1.7 million loss in 2007. The gain on +unrealized costs decreased $13.4 million from an $11.9 million loss in 2006 to a +$1.5 million gain in 2007. +Our +natural gas marketing segment specializes in the purchase, aggregation and sale +of natural gas production in our eastern operating areas. Through our +natural gas marketing segment, we market the natural gas we produce as well as +our purchases of natural gas from other producers in the Appalachian Basin, +including our affiliated partnerships. Our derivative activities +related to natural gas marketing activities include both physical and +cash-settled derivatives. We offer fixed-price derivative contracts +for the purchase or sale of physical gas and enter into cash-settled derivative +positions with counterparties in order to offset those same physical +positions. We do not take speculative positions on commodity +prices. +37 +Table of Contents +Natural Gas Marketing +Derivative Activities . +The +following table identifies our derivative positions related to our gas marketing +activities in effect as of December 31, 2008. +Floors +Ceilings +Swaps +(Fixed Prices) +Basis +Swaps +Commodity/ +Derivative Instrument +Quantity +(Gas-MMbtu Oil-Bbls) +Weighted +Average Contract +Price +Quantity +(Gas-MMbtu Oil-Bbls) +Weighted +Average Contract +Price +Quantity +(Gas-MMbtu Oil-Bbls) +Weighted +Average Contract +Price +Quantity +(Gas-MMbtu Oil-Bbls) +Weighted +Average Contract +Price +Fair +Value +a t December 31, +2008 +(in thousands) +Natural Gas +Physical +Sales +1Q +2009 +20,000 +$ +6.50 +- +$ +- +112,400 +$ +8.59 +290,021 +$ +0.37 +$ +230 +2Q +2009 +- +- +- +- +43,132 +9.20 +72,493 +0.29 +119 +3Q +2009 +- +- +- +- +31,320 +9.55 +66,578 +0.29 +88 +4Q +2009 +- +- +- +- +9,293 +8.36 +38,266 +0.51 +14 +2010 +- +- +- +- +15,610 +8.45 +30,410 +0.80 +19 +Financial +Purchases +1Q +2009 +20,000 +6.50 +- +- +152,400 +7.31 +- +- +(207 +) +2Q +2009 +- +- +- +- +43,132 +8.11 +- +- +(99 +) +3Q +2009 +- +- +- +- +31,191 +8.48 +- +- +(74 +) +4Q +2009 +- +- +- +- +29,293 +10.77 +- +- +(113 +) +2010 +- +- +- +- +45,610 +10.86 +- +- +(157 +) +Financial +Sales +1Q +2009 +- +- +10,000 +10.30 +580,900 +9.13 +226,665 +0.32 +1,879 +2Q +2009 +- +- +- +322,500 +9.27 +211,272 +0.32 +1,116 +3Q +2009 +- +- +- +- +250,500 +9.39 +141,250 +0.32 +812 +4Q +2009 +- +- +- +- +248,500 +8.90 +166,050 +0.32 +540 +2010 +- +- +- +- +695,000 +8.71 +- +- +1,040 +2011 +- +150,000 +8.44 +- +- +125 +Physical +Purchases +1Q +2009 +- +- +10,000 +10.30 +581,395 +9.29 +46,935 +0.32 +(1,762 +) +2Q +2009 +- +- +- +- +322,995 +9.44 +46,874 +0.32 +(1,079 +) +3Q +2009 +- +- +- +- +250,995 +9.56 +46,752 +0.32 +(788 +) +4Q +2009 +- +- +- +- +228,665 +9.60 +15,584 +0.32 +(597 +) +2010 +- +- +- +- +665,000 +9.14 +- +- +(1,146 +) +2011 +- +- +- +- +150,000 +8.61 +- +- +(125 +) +Total +Natural Gas +$ +(165 +) +Oil +and Gas Well Drilling +The +decrease in oil and gas well drilling operations revenue was due to our decision +not to sponsor a drilling partnership in 2008 and our change from footage-based +drilling arrangements to cost-plus drilling arrangements, which have differing +revenue recognition presentations. +In +January 2008, we announced that we did not plan to sponsor new drilling +partnerships in 2008. In August 2007, we completed our only sponsored +drilling partnership offering in 2007. Drilling for the partnership +commenced during the third quarter of 2007. From inception to +December 31, 2008, $12.7 million in revenues had been recognized related to the +2007 drilling program. Advances for future drilling contracts held as +of December 31, 2008, will be used for completion activities to be conducted in +2009. Currently, we do not plan to sponsor a drilling partnership in +2009 or in the foreseeable future. Consequently, we anticipate that our oil and +gas drilling segment’s contribution to operating income, which was $5.4 million, +$9.6 million and $5.3 million in 2008, 2007 and 2006, respectively, will decline +substantially in 2009. Thereafter, our oil and gas well drilling +contribution to operating income will cease unless we undertake new drilling +ventures. +Beginning +with the last sponsored partnership in 2005 (for which revenue generating +activities began in 2006), our partnership wells have been drilled on a +“cost-plus” basis, which means that we charge the partnerships for the actual +cost of the wells plus an agreed upon mark-up above that cost. Prior +to that partnership, we had conducted most of our third-party drilling +activities on a footage basis, pursuant to which we drilled the wells for a +fixed price per foot drilled with additional chargeable items as provided for in +the drilling agreement. Our services provided under the cost-plus +drilling arrangements are reported net of recovered costs and reflected as +revenue in oil and gas well drilling operations, whereas the revenues under the +footage-based arrangements were recorded gross of related +expenses. For the year ended December 31, 2006, the oil and gas well +drilling segment’s results included $5.4 million in revenues and $10 million in +expenses related to footage based arrangements. +38 +Table of Contents +Well +Operations and Pipeline Income +In +January 2007, we acquired all of the outstanding partnership interests in 44 of +our sponsored drilling partnerships. Having acquired 423 net wells +pursuant to the acquisition, we no longer record income for operating these +wells and related pipelines. This decrease in revenue was offset in +part by an increase in the number of new wells drilled and placed in service and +pipeline systems we operate for our sponsored drilling partnerships as well as +third parties. In October 2007, in conjunction with the acquisition +of oil and gas properties located in southwestern Pennsylvania, we acquired a +well services operation. The revenues related to this operation are +included in the statement of operations line item Well Operations and Pipeline +Income . +Gain +on Sale of Leaseholds +In July +2006, we entered into a purchase and sale agreement with an unaffiliated party +regarding the sale of our undeveloped leasehold located in the Grand Valley +Field, Garfield County, Colorado, as filed with the Securities and Exchange +Commission, or SEC, as Exhibit 10.3 to Form 10-Q for the period ended September +30, 2006. Total proceeds from the sale were $353.6 million, of which +we recognized a $328 million gain on sale of leasehold in the third quarter of +2006. +In +May 2007, we entered into a letter agreement amending the above +mentioned purchase and sale agreement, relieving us of our obligation, in its +entirety, to either drill 16 wells or pay liquidated damages of $1.6 million per +undrilled well. As a result, we recognized the remaining deferred +gain of $25.6 million in the second quarter of 2007. +In +December 2007, we sold to the same unaffiliated party a portion of our North +Dakota properties for approximately $34.7 million. The properties, +located in Dunn, Williams and McKenzie Counties, North Dakota, include interests +in five producing Bakken wells and approximately 72,000 net undeveloped +acres. We recorded a gain on sale of leaseholds of $7.7 million in +the fourth quarter of 2007. +Other +Costs and Expenses +Exploration +Expense +The +following table sets forth the major components of exploration +expense. +Year +Ended December 31, +2008 +2007 +2006 +(in +thousands) +Impairment +of proved oil and gas properties +$ +12,825 +$ +- +$ +1,510 +Amortization/impairment +of unproved properties +12,798 +3,291 +1,010 +Exploratory +dry holes +7,675 +4,187 +1,790 +Geological +and geophysical costs +2,121 +6,299 +2,234 +35,419 +13,777 +6,544 +Operating +and other +9,686 +9,774 +1,587 +Total +exploration expense +$ +45,105 +$ +23,551 +$ +8,131 +We +expanded exploratory drilling activities in 2005 and have generally believed +that the additional risk and costs associated with exploratory drilling is +justified by the potential to generate additional proved +properties. However, we plan to reduce exploratory drilling in 2009 +given the current economic conditions and focus primarily on development +activities in our proven fields. +We assess +our proved oil and gas properties for possible impairment by comparing net +capitalized costs to estimated undiscounted future net cash flows on a +field-by-field basis using estimated production based upon prices at which we +reasonably estimate the commodity to be sold. If net capitalized +costs exceed undiscounted future net cash flows, the measurement of impairment +is based on estimated fair value which would consider future discounted cash +flows. We assess our unproved oil and gas properties for possible +impairment by field based on our historical experience, current market data, +acquisition dates, average lease terms and the probability of being +drilled. +39 +Table of Contents +We +recognized impairment losses on proved oil and gas properties of $12.8 million +in 2008, consisting of $7.5 million related to our properties in the Fort Worth +Basin, $3 million in our Bakken Field in North Dakota and $2.3 million in our +Nesson Field, also in North Dakota. We also recognized +impairment losses of unproved properties of $12.9 million, consisting primarily +of $7.3 million related to our unproved properties in the Fort Worth Basin and +amortization of approximately $5.6 million related to all of our other areas of +operations. The $7.7 million of exploratory dry holes relates +primarily to two Michigan wells, one New York well and one Colorado +well. +In 2007, +exploration expense includes $2.7 million of liquidated damages associated with +the abandonment of an exploration agreement with an unaffiliated party and $1.1 +million related to the write-off of the carrying value of the related acreage, +$6.3 million in geological and geophysical costs related to seismic evaluation +of various exploratory prospects and increased payroll and payroll related costs +and other exploratory department costs. +In 2006, +exploration expense includes $1.8 million related to one exploratory dry hole, +$1.5 million related to an impairment charge on our Nesson Field in North Dakota +and $2.2 million in geological and geophysical costs related to the seismic +evaluation of our Northeast Colorado properties. +General +and Administrative Expense +General +and administrative expense has increased for the third consecutive +year. However, 2008 is considered pivotal because the rate of +increase is declining and we expect this trend to continue in +2009. It is this trend that we expect to continue in +2009. General and administrative expenses have been declining on a +per Mcfe basis, from $1.12 per Mcfe in 2006 to $1.11 per Mcfe in 2007 and $0.97 +per Mcfe in 2008. +The +increase in general and administrative expense in 2008 compared to 2007 was +primarily due to increased payroll and payroll related expenses, which includes +$4.7 million related to agreements with two former executive officers: $3.2 +million related to a separation agreement with our former president and $1.5 +million related to an agreement for the retirement of our former chief executive +officer. This increase was partially offset by a $2 million decrease +in audit fees and a decrease in various other general and administrative +expenses. +The +increase in general and administrative expense in 2007 compared to 2006 was +primarily due to increased costs related to increased payroll and payroll +related expenses, which includes stock-based compensation expense related to the +recruitment of professionals and key personnel in 2007. The increase +in management personnel is attributable to the growth we are experiencing, the +increase in the cost of recruiting and the higher compensation required to +obtain experienced oil and gas personnel. We also experienced higher +financial statement audit costs related to the late filing of our 2006 Form +10-K, higher compliance costs with the various provisions of the Sarbanes-Oxley +Act, increased accounting assistance from third party consulting services and +increased legal costs. +Depreciation, +Depletion and Amortization +DD&A expense +includes depreciation and amortization expense related of non-oil and natural +gas properties as well as oil and natural gas properties. DD&A +expense for non-oil and natural gas properties was $7.6 million, $4.3 million +and $2 million in 2008, 2007 and 2006, respectively. DD&A expense +related to oil and natural gas properties is directly related to reserves and +production volumes. DD&A expense is primarily based upon year-end +proved developed producing oil and gas reserves. These reserves are +priced at the price of oil and natural gas as of December 31 each +year. If prices increase, the corresponding volume of oil and gas +reserves will increase, resulting in decreases in the rate of DD&A per unit +of production. If prices decrease, as they did from 2007 to 2008, +volumes of oil and gas reserves will decrease resulting in increases in the rate +of DD&A per unit of production. See Note 18 , Supplemental Oil and Gas Information +– Unaudited , to our accompanying consolidated financial statements, for +the average December 31 oil and natural gas prices used to determine year-end +reserves and other reserve information. The cost to acquire acreage, +drill, complete and equip new wells have risen significantly over the past five +years along with oil and natural gas prices and is a major contributing factor +for the increased DD&A rate in the table below: +40 +Table of Contents +DD&A +rates for our oil and gas properties are shown in the table below. +Year +Ended December 31, +2008 +2007 +2006 +(per +Mcfe) +Appalachian +Basin (1) +$ +1.55 +$ +1.32 +$ +1.13 +Michigan +Basin +1.35 +1.28 +0.83 +Rocky +Mountain Region: +Wattenberg +Field +(2) +3.47 +2.99 +2.34 +Piceance +Basin (3) +2.04 +2.27 +1.83 +NECO +1.45 +1.45 +1.26 +Weighted +average +2.51 +2.37 +1.87 +______________ +(1) +The +increase in DD&A rate for the Appalachian Basin in 2008 was due to the +higher market price of a fourth quarter 2007 acquisition of 752 wells in +southwestern Pennsylvania and the new wells drilled in +2008. +(2) +Although +the Wattenberg Field development costs and DD&A rates are higher than +the other fields, the relative value of its oil production currently more +than offsets this cost difference. The Wattenberg Field has +produced volumes in excess of 85% of our total oil production in each of +the years in the three-year period ended December 31, +2008. +(3) +The +decrease in DD&A rates for the Piceance Basin in 2008 compared to 2007 +is the result of higher year-end 2008 oil and natural gas reserves, due +primarily to the improvements in drilling and completion technology and +expanded pipeline and compression +capacity. +Non-Operating +Income/Expense +Interest +Income . The decreases in our interest income in 2008 and 2007 +were the result of lower cash balances earning interest compared to +2006. In July 2006, we received $353.6 million in cash proceeds from +the sale of undeveloped leaseholds. These proceeds earned interest +income until reinvested in oil and gas properties in January 2007. +Interest +Expense . The increases in our interest expense were primarily +due to significantly higher average outstanding balances of our credit facility +and, in 2008, our 12% senior notes offset in part by lower average interest +rates in our bank credit facility. The average long-term debt in 2008 +was $275.9 million compared to $132.5 million in +2007. Interest expense is net of capitalized +interest. Interest costs capitalized in 2008, 2007 and 2006 were $2.6 +million, $3 million and $1.6 million, respectively. We have +historically utilized our daily cash balances to reduce our line of credit +borrowings, thereby lowering our interest costs. +Provision +for Income Taxes +Our 2008 +effective income tax rate was 35.2% in 2008 compared to 38.7% in 2007 and 38.6% +in 2006. This reduced rate reflects second and third quarter discrete +benefits of $1.4 million for each period, related principally to the +implementation of state tax strategies during each respective +quarter. The impact of these strategies also affected our rate used +to establish deferred taxes and resulted in a deferred tax benefit of $1 million +in 2008. +Our +effective tax rate, excluding the effect of discrete items, for 2008 was 37.3%, +which was virtually unchanged from 2007 and slightly less than the 2006 rate of +38.4%. In 2008, the rate decreased primarily due to a 0.5% reduction +in our effective state tax rate due to the benefit being realized from our +implemented state tax planning strategies and a 0.7% reduction primarily related +to reduced tax penalties. However, these 2008 rate decreases were +offset by our permanent tax deductions resulting in a proportionately smaller +effective rate benefit of 0.8% compared to 1.8% in 2007. In 2006, our +permanent tax deduction for percentage depletion resulted in a proportionately +smaller tax rate benefit of only 0.1%. +41 +Table of Contents +Liquidity +and Capital Resources +Cash flow +from operations and our bank credit facility are the primary sources of +liquidity for us to satisfy our operating expenses and fund our capital +expenditures. We had $180.5 million of available borrowing capacity +under our $375 million bank credit facility as of December 31, +2008. Cash provided by operating activities was $139.1 million for +the current year period compared to $60.3 million in the prior year +period. The $78.8 million increase in the current year period was +primarily due to higher natural gas and oil prices through mid-2008 and higher +volumes of oil and natural gas production and realized derivative gains +primarily in the fourth quarter of 2008. Changes in cash flow from +operations are largely due to the same factors that affect our net income, +excluding non-cash items which are primarily depreciation, depletion and +amortization and unrealized gains and losses on derivative +transactions. See the discussion under Results of +Operations . Cash flow used in investing activities increased +$55.6 million, or 21%, from $267.4 million for the year ended 2007 to $323 +million in 2008. Substantially all of our investing activity involved +drilling for oil and gas reserves during 2008. Cash flows provided +from financing activities increased $52.6 million, or 54%, from $97.5 million to +$150.1 million for the years ended December 31, 2007 and 2008, +respectively. This increase was primarily due to the increase in +proceeds from the issuance of our 12% senior notes of $200 million offset by net +repayments on our bank credit facility. +Changes +in market prices for oil and natural gas, our ability to increase production, +the impact of realized gains and losses on our oil and natural gas derivative +instruments and changes in costs are the principal determinants of the level of +our cash flow from operations. Oil and natural gas sales for the year +ended December 31, 2008, were approximately 85% higher than the prior year, +resulting from a 34% increase in average oil and natural gas prices and a 38% +increase in oil and natural gas production. While a decline in oil +and natural gas prices would affect the amount of cash from operations that +would be generated, we have oil and natural gas derivative positions in place, +as of the date of this filing, covering 52% of our expected oil production and +62% of our expected natural gas production in 2009, at average prices of $90.52 +per Bbl and $7.25 per Mcf, respectively. These contracts reduce the +impact of price changes for a substantial portion of our 2009 cash from +operations. +Our +primary use of funds is for capital expenditures. As a result of the +current unstable conditions in the commodity and financial markets, we have +significantly reduced our planned 2009 capital expenditures to a range of $120 +million to $140 million which represents an approximate 60% decrease from our +2008 capital expenditures. With this reduction, we estimate our 2009 +production will increase by approximately 15% over 2008 in part due to increased +production from wells drilled in the latter part of 2008. We believe, +based on the current commodity price environment, our cash flow from operations +will fund our reduced 2009 capital spending program allowing us to remain debt +neutral during 2009. We expect to manage capital expenditures within +our cash flow from operations in 2009 and for the foreseeable future until +commodity prices and capital markets are more favorable. In order to +continue to maintain or grow our production, we will need to commit greater +amounts of capital in 2010 and beyond. If capital is not available or +is constrained in the future, we will be limited to our cash flow from +operations and liquidity under our credit facility as the sources of funding for +our capital expenditures. Oil and gas produced from our existing +properties declines rapidly in the first two years of production. We +could not maintain our current level of oil and gas production and cash flow +from operations if capital markets and commodity prices remain in their current +depressed state for a prolonged period beyond 2009, which would have a material +negative impact on our operations in 2010 and beyond. +We +considered the possibility of a reduced available liquidity environment in +planning our 2009 drilling program and believe we will have adequate cash flow +from operations during the year to execute our planned capital expenditures +without drawing additional funds from our credit facility. Currently, +we operate approximately 95% of our properties, allowing us to control the pace +of substantially all of our planned capital +expenditures. Consequently, a substantial portion of our planned +capital expenditures for 2009 and beyond could be deferred if market conditions +worsen. +In +addition to deferring capital expenditures to reduce borrowings under our credit +facility, other sources of liquidity include the fair value of our oil and +natural gas derivative positions, excluding the derivative positions attributed +to our affiliated partnerships, of $117.8 million as well as our available cash +balance which was $51 million as of December 31, 2008. +We have +one significant future drilling commitment along with certain volume delivery +requirements that will require us to expend $60 million in development drilling +on our Wattenberg leases through 2011, provided that our counterparty in the +agreement expands two gas processing facilities and maintains certain wellhead +pressures by June 30, 2010. Our 2009 capital expenditure plan +includes approximately $50 million related to this +commitment. Failure to meet our drilling commitment would result in a +maximum payment to the counterparty of $15 million in 2012; failure to meet our +volume delivery commitments by December 31, 2012, would result in a maximum +payment to the counterparty of $10 million in 2013. Failure of the +counterparty to complete the required plant expansions results in a waiver of +our $60 million capital and volume delivery requirements. +42 +Table of Contents +We have +experienced no impediments in our ability to access borrowings under our current +bank credit facility. We continue to monitor market events and circumstances and +their potential impacts on each of the thirteen lenders that comprise our bank +credit facility. Our $375 million bank credit facility borrowing base +is subject to size redeterminations each April and October based upon a +quantification of our proved reserves at each December 31st +and June 30th, respectively. A commodity price deck reflective of the +current and future commodity pricing environment is utilized by our lenders to +quantify our reserve reports and determine the underlying borrowing +base. We will be subject to a borrowing base redetermination in April +2009. +We +increased our borrowing base in July 2008, and again in November 2008, to $300 +million and $375 million respectively. The increases were driven +primarily by increases in proved producing reserves from drilling +operations. While we have continued to add producing reserves since +our November 2008 redetermination, we believe the significant decrease in +commodity prices and turmoil in the credit markets could have a negative impact +on our borrowing base at our next redetermination in April 2009. Our +credit facility matures in November 2010, and is payable in full at that +time. We have begun discussions with our bank group with the intent +of renewing the credit facility prior to November 1, 2009. There is +no assurance all of the lenders in our credit facility will participate in the +renewal and there is no assurance that our borrowing base will not be reduced +from its current level as a result of the renewal or the loss of one or more +lenders in our credit facility. Further, costs of capital have +increased since we last amended our credit facility and we expect that interest +and commitment fees under a new facility will be higher than in our current +credit facility. See Note 6 , Long Term Debt , to the +accompanying consolidated financial statements. At December 31, 2008, +we had $180.5 million available for borrowing under our $375 million credit +facility. While we believe our borrowing base could be reduced as a +result of redeterminations, we believe that producing reserves added since our +last redetermination and our oil and natural gas derivative positions in place +could mitigate the risk of a significant decrease in our borrowing base in +2009. We also believe that while costs of capital have increased for +credit facilities like ours, the impact of an increase in interest and +commitment fees on our outstanding balance and commitments will not have a +material adverse effect on our liquidity in 2009. Our credit facility +matures in November 2010. If economic conditions deteriorate further +in 2009 and 2010, our ability to renew our credit facility and provide adequate +liquidity to continue our drilling programs could be negatively impacted in 2010 +and beyond. +We are +subject to quarterly financial debt covenants on our bank credit +facility. Our key credit facility debt covenants require that we +maintain: 1) total debt of less than 3.75 times earnings before interest, taxes, +depreciation, amortization and capital expenditures (“EBITDAX”) and 2) an +adjusted working capital ratio of at least 1.0 to 1.0. As of December +31, 2008, our total debt was 1.5 times EBITDAX and our adjusted working capital +ratio was 1.6 to +1.0. Our adjusted working capital ratio is calculated by reducing our +current assets and liabilities by any impact of recording the fair value of our +oil and gas derivative instruments and adding our available borrowings on our +bank credit facilities to our current assets. In addition, the impact +of any current portion of our debt is eliminated from the current +liabilities. Therefore, any change in our available borrowings under +our credit facility impacts our working capital ratio. +We +believe we have sufficient liquidity and capital resources to conduct our +business and remain compliant with our debt covenants throughout 2009 based upon +our 2009 cash flow projections, anticipated capital requirements, the +discretionary nature of our capital expenditures and available capacity under +our bank credit facility. While current conditions in the financial +markets are extremely difficult and illiquid, we have no current plans or +requirements to raise capital through these markets. However, we cannot predict +with any certainty the impact to our future business of any further disruption +or deterioration in the financial markets. We will continue to +closely monitor our liquidity and the credit markets and may choose to access +them opportunistically should conditions and capital market liquidity +improve. +We filed +a shelf registration statement on Form S-3 with the SEC on November 26, 2008. +The shelf provides for an aggregate of $500 million, through the sale of debt +securities, common stock or preferred stock, either separately or represented by +depository shares, warrants and purchase contracts, as well as units that may +include any of these securities or securities of other entities. The +shelf registration statement is intended to allow the Company to be proactive in +its ability to raise capital should the need arise, and to have the flexibility +to raise such funds in one or more offerings, subject to market +conditions. This shelf registration statement was declared effective +by the SEC on January 30, 2009. There are no immediate plans to raise +any funds and there is no assurance that we will be able to secure any such +funds should the need arise. +See Item +7A, Quantitative and +Qualitative Disclosure about Market Risk , for our discussion of credit +risk. +Contractual +Obligations and Contingent Commitments +The table +below sets forth our contractual obligations and contingent commitments as of +December 31, 2008: +Payments +due by period +Contractual +Obligations and Contingent Commitments (1) +Total +Less +than +1 +year +1-3 +years +3-5 +years +More +than +5 +years +(in +thousands) +Long-Term +Debt (2) +$ +394,867 +$ +- +$ +194,500 +$ +- +$ +200,367 +Interest on +long-term debt (2) +238,955 +33,398 +56,352 +73,080 +76,125 +Operating +leases +5,840 +2,687 +2,726 +383 +44 +Asset +retirement obligations +23,086 +50 +100 +100 +22,836 +Rig +commitments (3) +15,859 +12,091 +3,768 +- +- +Capital +expenditure commitments (4) +71,800 +- +70,000 +- +1,800 +Derivative +contracts (5) +10,486 +4,766 +(6,197 +) +11,917 +- +Partnership +derivative contracts (6) +13,944 +3,808 +10,136 +- +- +Production +tax liability +43,948 +18,226 +25,722 +- +- +Firm +transportation, sales and processing agreements (7) +217,495 +8,391 +37,490 +50,333 +121,281 +Other +liabilities (8) +8,380 +446 +1,240 +1,240 +5,454 +Total +$ +1,044,660 +$ +83,863 +$ +395,837 +$ +137,053 +$ +427,907 +43 +Table of Contents +__________ +(1) +Table +does not include deferred income tax obligations to taxing authorities of +$190.9 million and maximum annual repurchase obligations to investing +partners of $15.9 million as of December 31, 2008 due to the uncertainty +surrounding the ultimate settlement of amounts and timing of these +obligations. +(2) +Amounts +presented for long term debt consist of amounts related to our 12% senior +notes and our outstanding credit facility. The interest on long term debt +includes $222.3 million payable to the holders of our 12% senior notes and +$16.7 million related to our outstanding balance of $194.5 million on our +credit facility as of December 31, 2008, based on an imputed interest rate +of 4.65%. +(3) +Drilling rig commitments in +the above table reflect our maximum obligation and does not include future +adjustments to daily rates as provided for in the agreements as such +increases are not predictable and are only included in the above +obligation table upon notification to us by the contractor of an increase +in the rate . Further, our rig commitment +above includes $5.1 million related to a rig sublet to a third party and +remains our obligation should the third party default on terms of the +sublet agreement. +(4) +Primarily +represents our capital expenditure commitment related to certain drilling +and development agreements. See Note 8 , +Commitments and Contingencies, to our accompanying consolidated financial +statements. These amounts do not include advances for future +drilling contracts totaling $1.7 million at December 31, +2008. +(5) +Represents +our gross liability related to the fair value of derivative positions, +including the fair value of derivative contracts we entered into on behalf +of our affiliated partnerships as the managing general +partner. We have a related receivable from the partnerships of +$1.6 million as of December 31, +2008. +(6) +Represents +our affiliated partnerships’ share of the fair value of our gross +derivative assets at December 31, +2008. +(7) +Represents +our gross commitment, including amounts for volumes transported or +sold on behalf of our affiliated partnerships and other working interest +owners. We will recognize in our financial statements our +proportionate share based on our working and net revenue +interest. +(8) +Includes +funds held from revenue distribution to third party investors for plugging +liabilities related to wells we operate and deferred officer +compensation. +As +managing general partner of 33 partnerships ( see Item 1 . +Business – Drilling and +Development Conducted for Company Sponsored Partnerships) , we have +liability for any potential casualty losses in excess of the partnership assets +and insurance. We believe that the casualty insurance coverage +we and our subcontractors carry is adequate to meet this potential +liability. +For +information regarding our legal proceedings, see Note ­8 , Commitments and Contingencies – +Litigation, and Note 17 , Subsequent Events , to our +accompanying consolidated financial statements included in this +report. From time to time we are a party to various other legal +proceedings in the ordinary course of business. We are not currently +a party to any litigation that we believe would have a materially adverse affect +on our business, financial condition, results of operations, or +liquidity. +Critical +Accounting Policies and Estimates +We +have identified the following policies as critical to business operations and +the understanding of our results of operations. This is not a +comprehensive list of all of the accounting policies. In many cases, +the accounting treatment of a particular transaction is specifically dictated by +accounting principles generally accepted in the U.S., with no need for our +judgment in the application. There are also areas in which our +judgment in selecting any available alternative would not produce a materially +different result. However, certain of our accounting policies are +particularly important to the portrayal of our financial position and results of +operations and we may use significant judgment in the application; as a result, +they are subject to an inherent degree of uncertainty. In applying +those policies, we use our judgment to determine the appropriate assumptions to +be used in the determination of certain estimates. Those estimates +are based on historical experience, observation of trends in the industry, and +information available from other outside sources, as appropriate. For +a more detailed discussion on the application of these and other accounting +policies, see Note +1 , Summary of +Significant Accounting Policies , to our accompanying consolidated +financial statements. Our critical accounting policies and estimates +are as follows: +Revenue +Recognition +Oil and natural gas +sales . Sales of oil are recognized when persuasive evidence of +a sales arrangement exists, the oil is verified as produced and is delivered to +a purchaser, collection of revenue from the sale is reasonably assured and the +sales price is determinable. We are currently able to sell all the +oil that we can produce under existing sales contracts with petroleum refiners +and marketers. We do not refine any of our oil +production. Our crude oil production is sold to purchasers at or near +our wells under short-term purchase contracts at prices and in accordance with +arrangements that are customary in the oil industry. +Sales of +natural gas are recognized when natural gas has been delivered to a custody +transfer point, persuasive evidence of a sales arrangement exists, the rights +and responsibility of ownership pass to the purchaser upon delivery, collection +of revenue from the sale is reasonably assured and the sales price is fixed or +determinable. Natural gas is sold by us under contracts with terms +ranging from one month to three years. Virtually all of our contract +pricing provisions are tied to a market index, with certain adjustments based +on, among other factors, whether a well delivers to a gathering or transmission +line, quality of natural gas and prevailing supply and demand conditions, so +that the price of the natural gas fluctuates to remain competitive with other +available natural gas supplies. As a result, our revenues from the +sale of natural gas will suffer if market prices decline and benefit if they +increase. We believe that the pricing provisions of our natural gas +contracts are customary in the industry. +44 +Table of Contents +We +currently use the “net-back” method of accounting for transportation +arrangements of natural gas sales. We sell gas at the wellhead and +collect a price and recognize revenues based on the wellhead sales price since +transportation costs downstream of the wellhead are incurred by our customers +and reflected in the wellhead price. +Natural gas marketing +activities . Natural gas marketing is reported on the gross +accounting method, based on the nature of the agreements between RNG, our +suppliers and our customers. RNG, our marketing subsidiary, purchases +gas from PDC and other small producers and bundles the gas together to sell in +larger amounts to purchasers of natural gas for a price +advantage. RNG has latitude in establishing price and discretion in +supplier and purchaser selection. Natural gas marketing revenues and +expenses reflect the full cost and revenue of those transactions because RNG +takes title to the gas it purchases from the various producers and bears the +risks and rewards of that ownership. Both the realized and unrealized +gains and losses of the RNG commodity based derivative transactions for natural +gas marketing activities are included in gas sales from marketing activities or +cost of gas marketing activities, as applicable. +Oil and gas well drilling +operations . Our drilling segment recognizes revenue from +drilling contracts with sponsored drilling programs using the percentage of +completion method based upon the percentage of contract costs incurred to date +to the estimated total contract costs for each contract. We utilize +this method since reasonably dependable estimates of the total estimated costs +can be made and recognized revenues are subject to revisions as a contract +progresses, the term of which can range from three to twelve +months. We have offered our drilling services under two types of +contractual arrangements, cost-plus or footage-based service contracts, which +result in differing risk and reward relationships and, consequently, different +revenue reporting policies pursuant to Emerging Issues Task Force, or EITF, +Issue No. 99-19, Reporting +Revenue Gross as a Principal versus Net as an Agent . +The first +cost-plus drilling service arrangement was entered into in late 2005 with +drilling activity commencing in the first quarter of 2006. Due to the +fixed-fee-percentage nature of our revenues from these services, we have +determined that, in substance, we are acting as an agent, without risk of loss +during the performance of the drilling activities. Accordingly, our +services provided under the cost-plus drilling agreements are reported on a net +basis. We entered into our second and third cost-plus drilling +arrangements in September 2006 and August 2007 and commenced drilling +immediately. Footage-based contracts provide for the drilling, +completion and equipping of wells at footage rates and are generally completed +within nine to twelve months after the commencement of drilling. We +provide geological, engineering, and drilling supervision on the drilling and +completion process and use subcontractors to perform drilling and completion +services at a fixed footage-based rate and accordingly have the risk of loss in +performing services under these arrangements. Accordingly, we report +revenue under these agreements gross of related expenses. Anticipated +losses, if any, on uncompleted contracts are recorded at the time that the +estimated total costs exceed the estimated total contract revenue. At +December 31, 2007, we had recorded a loss contract reserve of $0.2 +million. There was no loss contract reserve as of December 31, +2008 . +Well operations and pipeline +income . Well operations and pipeline income are recognized +when persuasive evidence of an arrangement exists, services have been rendered, +collection of revenues is reasonably assured and the sales price is fixed or +determinable. We are paid a monthly operating fee for each well we +operate for outside owners including the limited partnerships we +sponsor. The fee covers monthly operating and accounting costs, +insurance and other recurring costs. We may also receive additional +compensation for special non-recurring activities, such as reworks and +recompletions. +Fair +Value of Financial Instruments +We +adopted the provisions of Statement of SFAS No. 157, Fair Value Measurements, +effective January 1, 2008. SFAS No. 157 defines fair value, +establishes a framework for measuring fair value and expands disclosures related +to fair value measurements. SFAS No. 157 applies broadly to financial and +nonfinancial assets and liabilities that are measured at fair value under other +authoritative accounting pronouncements, but does not expand the application of +fair value accounting to any new circumstances. In February 2008, the +Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“FSP”) +FAS No. 157-2, Effective Date of FASB Statement No. 157, which delays the +effective date of SFAS No. 157 by one year (to January 1, 2009) for nonfinancial +assets and liabilities, except those that are recognized or disclosed at fair +value in the financial statements on a recurring basis (at least +annually). Nonfinancial assets and liabilities for which we have not +applied the provisions of SFAS No. 157 include those initially measured at fair +value, including our asset retirement. +Derivative Financial +Instruments . +We use +derivative instruments to manage our commodity and financial market +risks. We currently do not use hedge accounting treatment for our +derivatives. Derivatives are reported on our accompanying +consolidated balance sheets at fair value on a gross asset and liability +basis. Changes in fair value of derivatives are recorded in oil and +gas price risk management, net, in our accompanying consolidated statements of +income. +SFAS No. +157 establishes a fair value hierarchy that requires an entity to maximize the +use of observable inputs and minimize the use of unobservable inputs when +measuring fair value. The valuation hierarchy is based upon the +transparency of inputs to the valuation of an asset or liability as of the +measurement date, giving the highest priority to quoted prices in active markets +(Level 1) and the lowest priority to unobservable data (Level 3). In +some cases, the inputs used to measure fair value might fall in different levels +of the fair value hierarchy. The lowest level input that is +significant to a fair value measurement in its entirety determines the +applicable level in the fair value hierarchy. Assessing the +significance of a particular input to the fair value measurement in its entirety +requires judgment, considering factors specific to the asset or +liability. The three levels of inputs that may be used to measure +fair value are defined as: +Level +1 – Quoted prices (unadjusted) in active markets for identical assets or +liabilities. Instruments included in Level 1 consist of our +commodity derivatives for New York Mercantile Exchange (“NYMEX”)-based +natural gas swaps. +Level +2 – Inputs other than quoted prices included within Level 1 that are +either directly or indirectly observable for the asset or liability, +including (i) quoted prices for similar assets or liabilities in active +markets, (ii) quoted prices for identical or similar assets or liabilities +in inactive markets, (iii) inputs other than quoted prices that are +observable for the asset or liability and (iv) inputs that are derived +from observable market data by correlation or other +means. +Level +3 – Unobservable inputs for the asset or liability, including situations +where there is little, if any, market activity for the asset or +liability. Instruments included in Level 3 consist of our +commodity derivatives for Colorado Interstate Gas (“CIG”) and Panhandle +Eastern Pipeline (“PEPL”)-based natural gas swaps, oil swaps, natural gas +basis protection swaps, oil and natural gas options, and physical sales +and purchases. +We +measure fair value of our derivatives based upon quoted market prices, where +available. Our valuation determination includes: (1) identification +of the inputs to the fair value methodology through the review of counterparty +statements and other supporting documentation, (2) determination of the validity +of the source of the inputs, (3) corroboration of the original source of inputs +through access to multiple quotes, if available, or other information and (4) +monitoring changes in valuation methods and assumptions. The methods +described above may produce a fair value calculation that may not be indicative +of future fair values. Our valuation determination also gives +consideration to our nonperformance risk on our own liabilities as well as the +credit standing of our counterparties. We primarily use two +investment grade financial institutions as our counterparties to our derivative +contracts. We have evaluated the credit risk of our derivative assets +from our counterparties using relevant credit market default rates, giving +consideration to amounts outstanding for each counterparty and the duration of +each outstanding derivative position. Based on our evaluation, we +have determined that the impact of the nonperformance of our counterparties on +the fair value of our derivative instruments is +insignificant. As of December 31, 2008, no valuation allowance +was recorded. Furthermore, while we believe these valuation +methods are appropriate and consistent with that used by other market +participants, the use of different methodologies, or assumptions, to determine +the fair value of certain financial instruments could result in a different +estimate of fair value. We estimated the gross net fair value of our +commodity based derivatives as of December 31, 2008, to be $153.5 +million. +Non-Derivative +Financial Assets and Liabilities. +The +carrying values of the financial instruments comprising cash and cash +equivalents, restricted cash, accounts receivable and accounts payable +approximate fair value due to the short-term maturities of these +instruments. +The +portion of our long-term debt related to our credit facility, approximates fair +value due to the variable nature of its related interest rate. We +estimate the fair value of the portion of our long-term debt related to our +senior notes to be approximately $127 million or approximately 62.5% of par +value as of December 31, 2008. We determined this valuation based +upon measurements of trading activity and quotes provided by brokers and traders +participating in the trading of the securities. +Oil +and Gas Properties +We +account for our oil and gas properties under the successful efforts method of +accounting. Costs of proved developed producing properties, +successful exploratory wells and development dry hole costs are capitalized and +depreciated or depleted by the unit-of-production method based on estimated +proved developed producing oil and natural gas reserves. Property +acquisition costs are depreciated or depleted on the unit-of-production method +based on estimated proved oil and gas reserves. +45 +Table of Contents +Our +estimates of proved reserves are based on quantities of oil and natural gas that +engineering and geological analysis demonstrates, with reasonable certainty, to +be recoverable from established reservoirs in the future under current operating +and economic conditions. Annually, we engage independent petroleum +engineers to prepare a reserve and economic evaluation of all our properties on +a well-by-well basis as of December 31. Additionally, we adjust our +oil and gas reserves for major acquisitions, new drilling and divestitures +during the year as needed. The process of estimating and evaluating +oil and natural gas reserves is complex, requiring significant decisions in the +evaluation of available geological, geophysical, engineering and economic +data. The data for a given property may also change substantially +over time as a result of numerous factors, including additional development +activity, evolving production history and a continual reassessment of the +viability of production under changing economic conditions. As a +result, revisions in existing reserve estimates occur from time to +time. Although every reasonable effort is made to ensure that reserve +estimates reported represent our most accurate assessments possible, the +subjective decisions and variances in available data for various properties +increase the likelihood of significant changes in these estimates over +time. Because estimates of reserves significantly affect our DD&A +expense, a change in our estimated reserves could have an effect on our net +income. +Exploration +costs, including geological and geophysical expenses and delay rentals, are +charged to expense as incurred. Exploratory well drilling costs, +including the cost of stratigraphic test wells, are initially capitalized but +charged to expense if the well is determined to be nonproductive. The +status of each in-progress well is reviewed quarterly to determine the proper +accounting treatment under the successful efforts method of +accounting. Exploratory well costs continue to be capitalized as long +as the well has found a sufficient quantity of reserves to justify our +completion as a producing well and we are making sufficient progress assessing +our reserves and economic and operating viability. If an in-progress +exploratory well is found to be unsuccessful (referred to as a dry hole) prior +to the issuance of the financial statements, the costs incurred prior to the end +of the reporting period are expensed to exploration costs. If we are +unable to make a final determination about the productive status of a well prior +to issuance of the financial statements, the well is classified as “suspended +well costs” until we have had sufficient time to conduct additional completion +or testing operations to evaluate the pertinent geological and engineering data +obtained. At the time when we are able to make a final determination +of a well’s productive status, the well is removed from the suspended well +status and the proper accounting treatment is recorded. At December +31, 2008 and 2007, suspended well costs included in oil and gas properties on +our accompanying consolidated financial statements was $1.2 million and $2.3 +million, respectively. +The +acquisition costs of unproved properties are capitalized when incurred, until +such properties are transferred to proved properties or charged to expense when +expired, impaired or amortized. Unproved oil and gas properties with +individually significant acquisition costs are periodically assessed, and any +impairment in value is charged to exploration expense. The amount of +impairment recognized on unproved properties which are not individually +significant is determined by amortizing the costs of such properties within +appropriate fields based on our historical experience, acquisition dates and +average lease terms. The valuation of unproved properties is +subjective and requires us to make estimates and assumptions which, with the +passage of time, may prove to be materially different from actual realizable +values. +In +accordance with SFAS No. 144, Accounting for the Impairment or +Disposal of Long-Lived Assets , we assess our oil and gas properties for +possible impairment by comparing net capitalized costs to estimated undiscounted +future net cash flows on a field-by-field basis using estimated production based +upon prices at which we reasonably estimate the commodity to be +sold. The estimates of future prices may differ from current market +prices of oil and natural gas. Any downward revisions in estimates to +our reserve quantities, expectations of falling commodity prices or rising +operating costs could result in a reduction in undiscounted future net cash +flows and an impairment of our oil and gas properties. Although our +cash flow estimates are based on the relevant information available at the time +the estimates are made, estimates of future cash flows are, by nature, highly +uncertain and may vary significantly from actual results. +Deferred +Income Tax Asset Valuation Allowance +Deferred +income tax assets are recognized for deductible temporary differences, net +operating loss carry-forwards, and credit carry-forwards if it is more likely +than not that the tax benefits will be realized. To the extent a +deferred tax asset is not expected to be realized under the preceding criteria, +a valuation allowance is established. The factors which we consider +in assessing whether we will realize the value of deferred income tax assets +involve judgments and estimates of both amount and timing, which could differ +from actual results, achieved in future periods. +The +judgments used in applying the above policies are based on our evaluation of the +relevant facts and circumstances as of the date of the financial +statements. Actual results may differ from those +estimates. +Accounting +for Acquisitions Using Purchase Accounting +We +account for acquisitions utilizing the purchase method as prescribed by SFAS No. +141, Business +Combinations . Pursuant to purchase method accounting, the +acquiring company must allocate the cost of the acquisition to assets acquired +and liabilities assumed based on fair values as of the acquisition +date. The purchase price allocations are based on appraisals, +discounted cash flows, quoted market prices and estimates by +management. In addition, when appropriate, we review comparable +purchases and sales of oil and gas properties within the same regions, and use +that data as a basis for fair market value; for example, the amount a willing +buyer and seller would enter into an exchange for such +properties. +46 +Table of Contents +In +estimating the fair values of assets acquired and liabilities assumed we made +various assumptions. The most significant assumptions relate to the +estimated fair values assigned to proved developed producing, proved developed +non-producing, proved undeveloped and unproved oil and gas +properties. To estimate the fair values of these properties, we +prepared estimates of oil and gas reserves. We estimated future +prices to apply to the estimated reserve quantities acquired, and estimated +future operating and development costs, to arrive at estimates of future net +revenues. For estimated proved reserves, the future net revenues were +discounted using a market-based weighted average cost of capital rate determined +appropriate at the time of the acquisition. The market-based weighted +average cost of capital rate was subjected to additional project-specific +risking factors. To compensate for the inherent risk of estimating +and valuing unproved properties, the discounted future net revenues of probable +and possible reserves were reduced by additional risk-weighting +factors. +Deferred +taxes must be recorded for any differences between the assigned values and tax +basis of assets and liabilities. Estimated deferred taxes are based +on available information concerning the tax basis of assets acquired and +liabilities assumed and loss carryforwards at the acquisition date, although +such estimates may change in the future as additional information becomes +known. +Recent +Accounting Standards +See Note 1 , Summary of Significant Accounting +Policies - Recent Accounting Standards , to our accompanying consolidated +financial statements. +ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT +MARKET RISK. +Market-Sensitive +Instruments and Risk Management +We are +exposed to market risks associated with interest rates, commodity prices and +credit exposure. Management has established risk management processes +to monitor and manage these market risks. +Interest +Rate Risk +Changes +in interest rates affect the amount of interest we earn on our cash, cash +equivalents and restricted cash and the interest we pay on borrowings under our +bank credit facility. Our 12% senior notes are fixed rate and, +therefore, do not expose us to the cash flow loss due to changes in market +interest rate. However, changes in interest rates do affect the fair +value of our senior notes. +Our +interest-bearing cash and cash equivalents include our money market accounts, +short-term certificates of deposit and checking and savings accounts with +various banks. The amount of our interest-bearing cash and cash +equivalents as of December 31, 2008, was $78.8 million with an average annual +interest rate of 1.8%. +Based on +a sensitivity analysis of the credit facility borrowings as of December 31, +2008, it was estimated that if market interest rates were to average 1% higher +(lower) in 2009 than in 2008, our interest expense, net of tax, would increase +(decrease) by approximately $1.3 million. +Commodity Price +Risk +See Part +II, Item 7, Management’s +Discussion and Analysis of Financial Condition and Results of Operation, +Critical Accounting Policies and Estimates-Accounting for Derivatives Contracts +at Fair Value , for further discussion of the accounting for derivative +contracts. +We are +exposed to the effect of market fluctuations in the prices of oil and natural +gas as they relate to our oil and natural gas sales and marketing +activities. Price risk represents the potential risk of loss from +adverse changes in the market price of oil and natural gas +commodities. We employ established policies and procedures to manage +the risks associated with these market fluctuations using commodity +derivatives. Our policy prohibits the use of oil and natural gas +derivative instruments for speculative purposes. +Validation +of a contract’s fair value is performed internally and while we use common +industry practices to develop our valuation techniques, changes in our pricing +methodologies or the underlying assumptions could result in significantly +different fair values. While we believe these valuation methods are +appropriate and consistent with those used by other market participants, the use +of different methodologies, or assumptions, to determine the fair value of +certain financial instruments could result in a different estimate of fair +value. +Economic Hedging +Strategies. Our results of operations and operating cash flows +are affected by changes in market prices for oil and natural gas. To +mitigate a portion of the exposure to adverse market changes, we have entered +into various derivative contracts. As of December 31, 2008, our oil +and natural gas derivative instruments consisted of (i) NYMEX-based natural gas +contracts for Appalachian and Michigan production, (ii) PEPL-based contracts for +NECO production, (iii) CIG-based contracts for other Colorado production and +(iv) NYMEX-based crude oil contracts for our Colorado oil +production. +47 +Table of Contents +· +For +swap instruments, we receive a fixed price for the derivative contract and +pay a floating market price to the counterparty. The +fixed-price payment and the floating-price payment are netted, resulting +in a net amount due to or from the +counterparty. +· +Basis +protection swaps are arrangements that guarantee a price differential for +natural gas from a specified delivery point. For CIG basis +protection swaps, which have negative differentials to NYMEX, we receive a +payment from the counterparty if the price differential is greater than +the stated terms of the contract and pay the counterparty if the price +differential is less than the stated terms of the +contract. +· +Collars +contain a fixed floor price (put) and ceiling price (call). If +the market price exceeds the fixed call strike price, we receive the +market price from the purchaser and pay the difference between the call +strike price and market price to the counterparty. If the +market price falls below the fixed put strike price, we receive the market +price from the purchaser and receive the difference between the put strike +price and market price from the counterparty. If the market +price is between the call and the put strike price, no payments are due +from either party. +With +regard to our natural gas marketing activities, we enter into fixed-price +physical purchase and sale agreements that are derivative +contracts. In order to offset these fixed-price physical derivatives, +we enter into financial derivative instruments that have the effect of locking +in the prices we will receive or pay for the same volumes and period, offsetting +the physical derivative. While these derivatives are structured to +reduce our exposure to changes in price associated with the derivative +commodity, they also limit the benefit we might otherwise have received from +price changes in the physical market. We believe our derivative +instruments continue to be effective in achieving the risk management objectives +for which they were intended. +The +following table presents monthly average NYMEX and CIG closing prices for oil +and natural gas in 2008 and 2007, as well as average sales prices we realized +for the respective commodity. +Year +Ended December 31, +2008 +2007 +Average +Index Closing Price +Natural +Gas (per MMbtu) +CIG +$ +6.22 +$ +3.97 +NYMEX +9.04 +6.89 +Oil +(per Barrel) +NYMEX +104.42 +69.79 +Average +Sales Price +Natural +Gas +6.98 +5.33 +Oil +89.77 +60.65 +Based on +a sensitivity analysis as of December 31, 2008, it was estimated that a 10% +increase in oil and natural gas prices, inclusive of basis, over the entire +period for which we have derivatives currently in place would have resulted in +an increase in fair value of $13.7 million and a 10% decrease in oil and natural +gas prices would have resulted in an increase in fair value of $49.4 +million. +See Item +7, Management’s Discussion and +Analysis of Financial Condition and Results of Operations, Results of +Operations, Oil and Gas Price Risk Management, Net and Natural Gas Marketing +Activities , for a detailed discussion of the our open derivative +positions related to our oil and gas sales activities and our natural gas +marketing activities. See Note 3 , Derivative Financial +Instruments , to our accompanying consolidated financial statements +included in this report for a summary of our open derivative positions as of +December 31, 2008. +Credit +Risk +Credit +risk represents the loss that we would incur if a counterparty fails to perform +under its contractual obligations. We attempt to reduce credit risk +by diversifying our counterparty exposure and entering into transactions with +high-quality counterparties. When exposed to credit risk, we analyze +the counterparties’ financial condition prior to entering into an agreement, +establish credit limits and monitor the appropriateness of those limits on an +ongoing basis. We have had no counterparty default +losses. +48 +Table of Contents +Our +receivables are from a diverse group of companies, including major energy +companies, both upstream and mid-stream, financial institutions and end-users in +various industries related to our gas marketing group. We monitor +their creditworthiness through credit reports and rating agency +reports. +Our +commodity-based derivative contracts expose us to the credit risk of +nonperformance by the counterparty to the contracts. These contracts +consist of fixed price swaps, basis swaps and collars. We primarily +use two investment grade financial institutions as our counterparties to our +derivative contracts who are also major lenders in our credit facility +arrangement. We have evaluated the credit risk of our derivative +assets from our counterparties using relevant credit market default rates, +giving consideration to amounts outstanding for each counterparty and the +duration of each outstanding derivative position. Based on our +evaluation, we have determined that the impact of the nonperformance of our +counterparties on the fair value of our derivative instruments is +insignificant. As of December 31, 2008, no valuation allowance +was recorded. +The +recent disruption in the credit market has had a significant adverse impact on a +number of financial institutions. We monitor the creditworthiness of +the financial institutions with which we transact, giving consideration to the +reports of credit agencies and their related ratings. While we +believe that our monitoring procedures are sufficient and customary, no amount +of analysis can guarantee performance in these uncertain times. +Disclosure +of Limitations +Because +the information above included only those exposures that exist at December 31, +2008, it does not consider those exposures or positions which could arise after +that date. As a result, our ultimate realized gain or loss with +respect to interest rate and commodity price fluctuations will depend on the +exposures that arise during the period, our hedging strategies at the time, and +interest rates and commodity prices at the time. +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY +DATA +The +response to this Item is set forth herein in a separate section of this Report, +beginning on Page F-1. +Index to financial +statements. +ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON +ACCOUNTING AND FINANCIAL DISCLOSURE +As +reported on Form 8-K filed with the SEC on May 31, 2007, and incorporated herein +by reference, the Audit Committee of our Board of Directors recommended, and the +Board of Directors ratified, the dismissal of KPMG LLP as our principal +accountants on May 24, 2007. +ITEM 9A. CONTROLS AND PROCEDURES +Evaluation +of Disclosure Controls and Procedures +As of +December 31, 2008, we carried out an evaluation, under the supervision and with +the participation of our management, including our Chief Executive Officer and +Chief Financial Officer, of the effectiveness of the design and operation of our +disclosure controls and procedures pursuant to Securities Exchange Act Rule +13a-15. Based upon that evaluation, our Chief Executive Officer and +Chief Financial Officer concluded that our disclosure controls and procedures +were effective as of December 31, 2008, to ensure that the information required +to be disclosed by the Company in the reports that we file or submit under the +Exchange Act is recorded, processed, summarized and reported, within the time +periods specified in the SEC rules and forms, and that the information is +accumulated and communicated to our management, including our Chief Executive +Officer and Chief Financial Officer, as appropriate to allow timely decisions +regarding required disclosure. +Changes +in Internal Control over Financial Reporting +We made +no changes in our internal control over financial reporting (as such term is +defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934) +during the quarter ended December 31, 2008, that have materially affected or are +reasonably likely to materially affect our internal control over financial +reporting. +See Remediation of Material Weaknesses +in Internal Control below for a discussion of changes in our internal +control over financial reporting that occurred throughout 2008. +49 +Table of Contents +Remediation +of Material Weaknesses in Internal Control +We, with +oversight from the Audit Committee of our Board of Directors, have been +addressing the material weaknesses disclosed in our 2007 Form 10-K and Item 4 of +our subsequently filed Form 10-Q for each of the quarterly periods in the +nine-month period ended September 30, 2008. We have concluded, based +on our assessment, that, through the implementation of the changes in internal +controls over financial reporting described below, we have remediated these +previously reported material weaknesses as of December 31, +2008. Management’s annual report on internal control over financial +reporting and the audit report on our internal control over financial reporting +of our independent registered public accounting firm are included in response to +Item 8 of this report on pages F-2 and F-3 included +herein. +The +remediation initiatives that were undertaken during 2008 include: +· +In +the first quarter of 2008, we implemented the general ledger, accounts +receivable, and joint interest billing modules as part of a new broader +financial reporting system. We have taken the necessary steps +to monitor and maintain appropriate internal controls during this period +of change. These steps included providing training related to +business process changes and the financial reporting system software to +individuals using the financial reporting system to carry out their job +responsibilities as well as those who rely on the financial +information. The implementation of the financial reporting +system strengthened the overall internal controls due to enhanced +automation and integration of related processes. The design and +documentation of internal control process and procedures relating to the +new system has been modified to supplement and complement existing +internal controls over financial +reporting. +· +In +the third quarter of 2008, we implemented controls over key financial +statement spreadsheets that support all significant balance sheet and +income statement accounts. Specifically, we enhanced the +spreadsheet policy to provide additional clarification and guidance with +regard to risk assessment and enforced controls over: 1) the security and +integrity of the data used in the various spreadsheets, 2) access to the +spreadsheets, 3) changes to spreadsheet functionality and the related +approval process and documentation and 4) increased managements review of +the spreadsheets. +· +In +the third quarter of 2008, key personnel attended an accredited derivative +training course and a desktop procedure was implemented to ensure the +completeness and accuracy over derivative activities, which supplemented +the key controls that previously existed in the +process. +ITEM 9B. OTHER INFORMATION +None. +PART +III +ITEM 10. DIRECTORS , EXECUTIVE OFFICERS AND CORPORATE +GOVERNANCE +The +information called for by Item 10 is incorporated by reference from information +under the captions entitled Corporate Governance , Section 16(a) Beneficial Ownership +Reporting Compliance , Election of Directors and +Executive Compensation +and other relevant portions of our definitive proxy statement to be filed +pursuant to Regulation 14A no later than 120 days after the close of our fiscal +year. +ITEM 11. EXECUTIVE COMPENSATION +The information called for by Item 11 +is incorporated by reference from information under the caption entitled Executive Compensation and +other relevant portions of our definitive proxy statement to be filed pursuant +to Regulation 14A no later than 120 days after the close of our fiscal +year. +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS +AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +The +information called for by Item 12 is incorporated by reference from information +under the caption entitled Security Ownership of Certain +Beneficial Owners and Management and Related Stockholder Matters and +other relevant portions of our definitive proxy statement to be filed pursuant +to Regulation 14A no later than 120 days after the close of our fiscal +year. +50 +Table of Contents +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +AND DIRECTOR INDEPENDENCE +The +information called for by Item 13 is incorporated by reference from information +under the captions entitled Certain Relationships and Related +Transactions and +Director Independence in our definitive proxy statement to be +filed pursuant to Regulation 14A no later than 120 days after the close of our +fiscal year. +ITEM 14. PRINCIPAL ACCOUNTANT FEES AND +SERVICES +The +information called for by Item 14 is incorporated by reference from information +under caption entitled Principal Accountant Fees and +Services and other relevant portions of our definitive proxy +statement to be filed pursuant to Regulation 14A no later than 120 days after +the close of our fiscal year. +PART +IV +ITEM 15. EXHIBITS , FINANCIAL STATEMENT +SCHEDULES +(a) +(1) +Financial +Statements: +See +Index to Financial Statements and +Schedules on page F-1. +(2) +Financial +Statement Schedules: +See +Index to Financial Statements and +Schedules on page F-1. +Schedules +and Financial Statements Omitted +All +other financial statement schedules are omitted because they are not +required, inapplicable, or the information is included in the Financial +Statements or Notes thereto. +(3) +Exhibits: +See +Exhibits Index on page +56. +51 +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. +PETROLEUM +DEVELOPMENT CORPORATION +By +/s/ Richard W. McCullough +Richard +W. McCullough, +Chairman, +Chief Executive Officer, and President +By +/s/ Gysle R. Shellum +Gysle +R. Shellum, +Chief +Financial Officer +February +26, +2009 +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/ Richard W. McCullough +Richard +W. McCullough +Chairman, +Chief Executive Officer, and President (principal +executive officer) +February +26, 2009 +/s/ Gysle R. Shellum +Gysle +R. Shellum +Chief +Financial Officer (principal +financial officer) +February +26, 2009 +/s/ Darwin L. Stump +Darwin +L. Stump +Chief +Accounting Officer (principal +accounting officer) +February +26, 2009 +/s/ Daniel W. Amidon +Daniel +W. Amidon +General +Counsel, Corporate Secretary +February +26, 2009 +/s/ Steven R. Williams +Steven +R. Williams +Director +February +26, 2009 +/s/ Jeffrey C. Swoveland +Jeffrey +C. Swoveland +Director +February +26, 2009 +/s/ Vincent F. D'Annunzio +Vincent +F. D'Annunzio +Director +February +26, 2009 +/s/ Kimberly Luff Wakim +Kimberly +Luff Wakim +Director +February +26, 2009 +/s/ David C. Parke +David +C. Parke +Director +February +26, 2009 +/s/ Anthony J. +Crisafio +Anthony +J. Crisafio +Director +February +26, +2009 +/s/ Joseph E. +Casabona +Joseph +E. Casabona +Director +February +26, 2009 +/s/ Larry F. Mazza +Larry +F. Mazza +Director +February +26, +2009 +52 +Table of Contents +GLOSSARY OF OIL AND NATURAL GAS TERMS +The +following are abbreviations and definitions of terms commonly used in the oil +and gas industry and this Form 10-K. +Bbl - One barrel or 42 U.S. +gallons of liquid volume. +Bcf - One billion cubic +feet. +Bcfe - One billion cubic feet +of natural gas equivalent. +CIG - Colorado Interstate +Gas. +Completion - The installation +of permanent equipment for the production of oil or gas. +DD&A - Refers to depreciation, +depletion and amortization of our property and equipment. +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 hydrocarbons in sufficient quantities to justify +completion as an oil or gas well. +Exploratory well - A well +drilled to find and produce oil or natural gas reserves not classified as +proved, to find a new productive reservoir in a field previously found to be +productive of oil or natural gas in another reservoir or to extend a known +reservoir. +Extensions and discoveries - +As to any period, the increases to proved reserves from all sources other than +the acquisition of proved properties or revisions of previous +estimates. +Gross acres or wells - Refers +to the total acres or wells in which we have a working interest. +Horizontal drilling - A +drilling technique that permits the operator to contact and intersect a larger +portion of the producing horizon than conventional vertical drilling techniques +and may, depending on the horizon, result in increased production rates and +greater ultimate recoveries of hydrocarbons. +MBbls - One thousand +barrels. +Mcf - One thousand cubic +feet. +Mcfe - One thousand cubic feet +of natural gas equivalent, based on a ratio of 6 Mcf for each barrel of oil, +which reflects the relative energy content. +MMbtu - One million British +thermal units. One British thermal unit is the heat required to raise +the temperature of a one-pound mass of water from 58.5 to 59.5 degrees +Fahrenheit. +MMcf - One million cubic +feet. +MMcfe - One million cubic feet of +natural gas equivalent. +Net acres or wells - Refers to +gross acres or wells multiplied, in each case, by the percentage working +interest we own. +Net production - Oil and gas +production that we own, less royalties and production due others. +NYMEX - New York Mercantile +Exchange. +Oil - Crude oil or +condensate. +Operator - The individual or +company responsible for the exploration, development and/or production of an oil +or gas well or lease. +53 +Table of Contents +PEPL - Panhandle Eastern +Pipeline. +Present value of proved +reserves - The present value of estimated future revenues, discounted at +10% annually, to be generated from the production of proved reserves determined +in accordance with Securities and Exchange Commission guidelines, net of +estimated production and future development costs, using prices and costs as of +the date of estimation without future escalation, without giving effect to (i) +estimated future abandonment costs, net of the estimated salvage value of +related equipment, (ii) non-property related expenses such as general and +administrative expenses, debt service and future income tax expense, or (iii) +depreciation, depletion and amortization. +Proved developed non-producing +reserves - Reserves that consist of (i) proved reserves from wells which +have been completed and tested but are not producing due to lack of market or +minor completion problems which are expected to be corrected and (ii) proved +reserves currently behind the pipe in existing wells and which are expected to +be productive due to both the well log characteristics and analogous production +in the immediate vicinity of the wells. +Proved developed producing +reserves - +Proved reserves that can be expected to be recovered from currently +producing zones under the continuation of present operating +methods. +Proved developed reserves - The combination of proved +developed producing and proved developed non-producing reserves. +Proved reserves - 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, i.e., prices and costs as of the date the estimate is +made. Prices include consideration of changes in existing prices +provided only by contractual arrangements, but not on escalations based upon +future conditions. +Proved undeveloped reserves, +or PUD - Proved +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 - A recompletion +occurs when we reenter a well to complete (i.e., perforate) a new formation +different from that in which a well has previously been completed. +Refrac, or refracture – A +refrac is when we stimulate the present producing zone of a well to increase +production, using hydraulic, acid, gravel, etc. fracture +techniques. +Reserve replacement - +Calculated by dividing the sum of reserve additions from all sources (revisions, +extensions, discoveries and other additions and acquisitions) by the actual +production for the corresponding period. The values used for reserve +additions are derived directly from the proved reserves table located in Note 18 , Supplemental Oil and Gas +information , to our consolidated financial statements included in this +report. We use the reserve replacement ratio as an indicator of our +ability to replenish annual production volumes and grow our reserves, thereby +providing some information on the sources of future production. It +should be noted that the reserve replacement ratio is a statistical indicator +that has limitations. As an annual measure, the ratio is limited +because it typically varies widely based on the extent and timing of new +discoveries and property acquisitions. Its predictive and comparative +value is also limited for the same reasons. In addition, since the +ratio does not imbed the cost or timing of future production of new reserves, it +cannot be used as a measure of value creation. +Royalty - An interest in an +oil and gas lease that gives the owner of the interest the right to receive a +portion of the production from the leased acreage (or of the proceeds of the +sale thereof), but generally does not require the owner to pay any portion of +the costs of drilling or operating the wells on the leased +acreage. Royalties may be either landowner’s royalties, which are +reserved by the owner of the leased acreage at the time the lease is granted, or +overriding royalties, which are usually reserved by an owner of the leasehold in +connection with a transfer to a subsequent owner. +Standardized measure of discounted +future net cash flows - Present value of proved reserves, as adjusted to +give effect to (i) estimated future abandonment costs, net of the estimated +salvage value of related equipment, and (ii) estimated future income +taxes. +Undeveloped acreage - Leased +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 proved reserves. +Working interest - An interest +in an oil and gas lease that gives the owner of the interest the right to drill +for and produce oil and gas on the leased acreage and requires the owner to pay +a share of the costs of drilling and production operations. The share +of production to which a working interest is entitled will be smaller than the +share of costs that the working interest owner is required to bear to the extent +of any royalty burden. +Workover - Operations on a +producing well to restore or increase production. +54 +Table of Contents +Exhibits +Index +Incorporated +by Reference +Exhibit +Number +Exhibit +Description +Form +SEC +File Number +Exhibit +Filing +Date +Filed +Herewith +3.1 +Second +Amended and Restated Certificate of Incorporation of Petroleum Development +Corporation. +8-K +000-07246 +3.1 +07/23/2008 +3.2 +Bylaws +of Petroleum Development Corporation, amended and restated, effective +October 11, 2007. +8-K +000-07246 +3.2 +10/17/2007 +4.1 +Rights +Agreement by and between Petroleum Development Corporation and Transfer +Online, Inc., as Rights Agent, dated as of September 11, 2007, including +the forms of Rights Certificates and Summary of Stockholder Rights Plan +attached thereto as Exhibits A and B. +8-K +000-07246 +4.1 +09/14/2007 +4.2 +Indenture +dated as of February 8, 2008, by and among Petroleum Development +Corporation and The Bank of New York. +8-K +000-07246 +4.1 +02/12/2008 +4.3 +First +Supplemental Indenture dated as of February 8, 2008, by and among +Petroleum Development Corporation and the Bank of New +York. +8-K +000-07246 +4.2 +02/12/2008 +4.4 +Form +of 12% Senior Note due 2018. +8-K +000-07246 +4.3 +02/12/2008 +10.1 +Purchase +Agreement dated as of February 1, 2008, by and among Petroleum Development +Corporation and the Initial Purchasers of 12% senior notes due 2018 named +therein. +8-K +000-07246 +10.1 +02/07/2008 +10.2 +Registration +Rights Agreement dated as of February 8, 2008, by and among Petroleum +Development Corporation and the Initial Purchasers of 12% senior notes due +2018 named therein. +8-K +000-07246 +10.1 +02/12/2008 +10.3 +Amended +and Restated Credit Agreement dated as of November 4, 2005, Petroleum +Development Corporation, as borrower and JPMorgan Chase Bank, N.A and BNP +Paribas, as lenders. +8-K +000-07246 +10.1 +11/04/2005 +10.4 +First +Amendment to Amended and Restated Credit Agreement, dated as of August 9, +2007, by an among Petroleum Development Corporation, certain of its +subsidiaries, JPMorgan Chase Bank, N.A., BNP Paribas and Wachovia Bank, +N.A. +8-K +000-07246 +10.1 +08/15/2007 +10.5 +Second +Amendment to Amended and Restated Credit Agreement, dated as of October +16, 2007, by and among Petroleum Development Corporation, certain of its +subsidiaries, JPMorgan Chase Bank, N.A., BNP Paribas, Wachovia Bank, N.A., +Guaranty Bank, FSB, Bank of Oklahoma and Morgan Stanley +Bank. +8-K +000-07246 +10.1 +10/22/2007 +10.6 +Third +Amendment to Amended and Restated Credit Agreement dated as of July 15, +2008, by and among Petroleum Development Corporation, +certain of its subsidiaries, JP Morgan Chase Bank, N.A., BNP Paribas and +various other banks. +8-K +000-07246 +10.1 +07/21/2008 +10.7 +Fourth +Amendment to Amended and Restated Credit Agreement dated as of July 18, +2008, by and among the Company, certain of its subsidiaries, JP Morgan +Chase Bank, N.A., BNP Paribas and various other banks. +8-K +000-07246 +10.2 +07/21/2008 +10.8 +Fifth +Amendment to Amended and Restated Credit Agreement dated as of November +12, 2008, by and among the Company, certain of its subsidiaries, JP Morgan +Chase Bank, N.A., various other banks. +8-K +000-07246 +10.1 +11/19/2008 +55 +Table of Contents +Incorporated +by Reference +Exhibit +Number +Exhibit +Description +Form +SEC +File Number +Exhibit +Filing +Date +Filed +Herewith +10.9* +Employment +Agreement with Richard W. McCullough, Chief Executive Officer, dated as of +December 31, 2008. +X +10.10* +Employment +Agreement with Eric R. Stearns, Executive Vice President, dated as of +December 31, 2008. +X +10.11* +Employment +Agreement with Gysle R. Shellum, Chief Financial Officer, dated as of +December 31, 2008. +X +10.12* +Employment +Agreement with Barton R. Brookman, Jr., Senior Vice President of +Exploration and Production, dated as of December 31, 2008. +X +10.13* +Employment +Agreement with Daniel W. Amidon, General Counsel and Corporate Secretary, +dated as of December 31, 2008. +X +10.14* +Employment +Agreement with Darwin L. Stump, Chief Accounting Officer, dated as of +December 31, 2008. +X +10.15* +2008 +Short-Term Incentive Compensation Terms for Executive +Officers. +8-K +000-07246 +03/28/2008 +10.16* +2008 +Long-Term Incentive Program (as amended for 2008) for Executive +Officers. +8-K +000-07246 +10.1 +03/13/2008 +10.17* +Non-Employee +Director Compensation for the 2008-2009 Term. +8-K +000-07246 +03/13/2008 +10.18* +2008 +Base Salary and Short-Term Incentive Cash Bonus Program for Executive +Officers. +8-K +000-07246 +02/22/2008 +10.19* +2007 +Long-Term Incentive Program for Executive Officers. +8-K +000-07246 +10.1 +04/13/2007 +10.20* +2006 +Long-Term Equity Compensation Grants to Executive +Officers. +8-K +000-07246 +04/10/2007 +10.21* +Agreement +with Steven R. Williams, Director. +10-Q +000-07246 +10.3 +11/06/2008 +10.22* +Separation +Agreement with Thomas E. Riley, former President. +X +10.23* +Indemnification +Agreement with Directors and Officers. +10-Q +000-07246 +10.1 +08/09/2007 +10.24* +The +Petroleum Development Corporation 401(k) & Profit Sharing +Plan. +S-8 +333-137836 +4.1 +10/05/2006 +10.25* +2005 +Non-Employee Director Restricted Stock Plan amended and restated as of +March 8, 2008. +10-Q +000-07246 +10.6 +11/06/2008 +10.26* +2004 +Long-Term Equity Compensation Plan amended and restated as of March 8, +2008. +X +10.27* +Non-Employee +Director Deferred Compensation Plan. +S-8 +333-118222 +99.1 +08/13/2004 +10.28* +1999 +Incentive Stock Option and Non-Qualified Stock Plan. +S-8 +333-111825 +99.1 +01/09/2004 +14.1 +Code +of Business Conduct and Ethics. +X +21.1 +Subsidiaries. +X +23.1 +Consent +of PricewaterhouseCoopers LLP. +X +23.2 +Consent +of KPMG LLP. +X +23.3 +Consent +of Wright & Company, Inc., Petroleum Consultants. +X +23.4 +Consent +of Ryder Scott Company, L.P., Petroleum Consultants. +X +56 +Table of Contents +Incorporated +by Reference +Exhibit +Number +Exhibit +Description +Form +SEC +File Number +Exhibit +Filing +Date +Filed +Herewith +31.1 +Certification +by Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the +Exchange Act Rules, as adopted pursuant to Section 302 of the +Sarbanes-Oxley Act of 2002. +X +31.2 +Certification +by Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the +Exchange Act Rules, as adopted pursuant to Section 302 of the +Sarbanes-Oxley Act of 2002. +X +32.1 +Certifications +by Chief Executive Officer and Chief Financial Officer pursuant to Title +18 U.S.C. Section 1350, as adopted pursuant to Section 906 of +Sarbanes-Oxley Act of 2002. +X +____________ +*Management +contract or compensatory plan or arrangement. +57 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +Index +to Consolidated Financial Statements and Financial Statement +Schedule +Management's Report on Internal Control Over +Financial Reporting +F-2 +Financial +Statements: +Reports of Independent Registered Public +Accounting Firms +F-3 +Consolidated Balance Sheets - December 31, 2008 +and 2007 +F-5 +Consolidated Statements of Operations - Years +Ended December 31, 2008, 2007 and 2006 +F-6 +Consolidated Statements of Cash Flows - Years +Ended December 31, 2008, 2007 and 2006 +F-7 +Consolidated Statements of Shareholders' Equity - +Years Ended December 31, 2008, 2007 and 2006 +F-8 +Notes to Consolidated Financial +Statements +F-9 +Financial +Statement Schedule: +Schedule II – Valuation and Qualifying Accounts +and Reserves +F-48 +F-1 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +Management's Report on +Internal Control Over Financial Reporting +Management +is responsible for establishing and maintaining adequate internal control over +financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) of +the Exchange Act. 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. 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 policies +or procedures may deteriorate. +Management +has assessed the effectiveness of the Company’s internal control over financial +reporting as of December 31, 2008, based upon the criteria established in +“Internal Control – Integrated Framework” issued by the Committee of Sponsoring +Organizations of the Treadway Commission (“COSO”). Based on this +evaluation, management concluded that the Company maintained effective internal +control over financial reporting as of December 31, 2008. +The +effectiveness of Petroleum Development Corporation's internal control over +financial reporting as of December 31, 2008, has been audited by +PricewaterhouseCoopers LLP, an independent registered public accounting firm, as +stated in their report which appears herein. +PETROLEUM +DEVELOPMENT CORPORATION +/s/ +Richard W. McCullough +Richard +W. McCullough +Chairman +and Chief Executive Officer +/s/ +Gysle R. Shellum +Gysle +R. Shellum +Chief +Financial Officer +F-2 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +Report of +Independent Registered Public Accounting Firm +To the Board of +Directors and Shareholders +of Petroleum +Development Corporation +In our opinion, +the accompanying consolidated balance sheets and the related consolidated +statements of operations, shareholders' equity, and cash flows present fairly, +in all material respects, the financial position of Petroleum Development +Corporation and its subsidiaries at December 31, 2008 and 2007, and +the results of their operations and their cash flows for the years then ended in +conformity with accounting principles generally accepted in the United States of +America. In addition, in our opinion, the 2008 and 2007 information +in the financial statement schedule listed in the accompanying +index presents fairly, in all material respects, the information set forth +therein when read in conjunction with the related consolidated financial +statements. Also in our opinion, the Company maintained, in all +material respects, effective internal control over financial reporting as of +December 31, 2008, based on criteria established in Internal Control - +Integrated Framework issued by the Committee of Sponsoring Organizations of the +Treadway Commission (COSO). The Company's management is responsible +for these financial statements and financial statement schedule, 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 opinions on these +financial statements, on the 2008 and 2007 information in the financial +statement schedule, and on the Company's internal control over financial +reporting based on our integrated 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 +audits to obtain reasonable assurance about whether the financial statements are +free of material misstatement and whether effective internal control over +financial reporting was maintained in all material respects. Our +audits of the financial statements included examining, on a test basis, evidence +supporting the amounts and disclosures in the financial statements, assessing +the accounting principles used and significant estimates made by management, and +evaluating the overall financial statement presentation. Our audit of +internal control over financial reporting included obtaining an understanding of +internal control over financial reporting, assessing the risk that a material +weakness exists, and testing and evaluating the design and operating +effectiveness of internal control based on the assessed risk. Our +audits also included performing such other procedures as we considered necessary +in the circumstances. We believe that our audits provide a reasonable basis for +our opinion. +As discussed in +Note 5 to the consolidated financial statements, the Company changed the +manner in which it accounts for uncertain tax positions in 2007. +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 +(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 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. +/s/ +PricewaterhouseCoopers LLP +Pittsburgh, +Pennsylvania +February 26, +2009 +F-3 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +Report +of Independent Registered Public Accounting Firm +The Board +of Directors and Stockholders +Petroleum +Development Corporation: +We have +audited the accompanying consolidated statements of operations, shareholders’ +equity, and cash flows of Petroleum Development Corporation and subsidiaries for +the year ended December 31, 2006. In connection with our audit +of these consolidated financial statements, we also have audited the related +financial statement schedule. These consolidated financial statements +and financial statement schedule are the responsibility of the Company’s +management. Our responsibility is to express an opinion on these +consolidated 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 consolidated financial statements referred to above present fairly, +in all material respects, the results of operations and the cash flows of +Petroleum Development Corporation and subsidiaries for the year ended +December 31, 2006, in conformity with U.S. generally accepted accounting +principles. Also in our opinion, the related financial statement +schedule, when considered in relation to the basic consolidated financial +statements taken as a whole, presents fairly, in all material respects, the +information set forth therein. +As +discussed in Note 1 to the consolidated financial statements, the Company +adopted the provisions of Statement of Financial Accounting Standards No. +123(R), (“Share-Based Payment”), in 2006. +As +discussed in Note 1 to the consolidated financial statements, the Company +changed its method of quantifying errors based on SEC Staff Accounting Bulletin +No. 108 (“Considering the Effects of Prior Year Misstatements when Quantifying +Misstatements in Current Year Financial Statements”) in 2006. +KPMG +LLP +Pittsburgh, +Pennsylvania +May 22, +2007 +F-4 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +Consolidated +Balance Sheets +(in +thousands, except share and per share data) +December +31, +2008 +2007 +Assets +Current +assets: +Cash +and cash equivalents +$ +50,950 +$ +84,751 +Restricted +cash - current +19,030 +14,773 +Accounts +receivable, net +69,688 +60,024 +Accounts +receivable - affiliates +16,742 +11,537 +Fair +value of derivatives - current +116,881 +4,817 +Prepaid +expenses and other current assets +19,146 +15,891 +Total +current assets +292,437 +191,793 +Properties +and equipment, net +1,033,078 +845,864 +Other +assets +77,189 +12,822 +Total +Assets +$ +1,402,704 +$ +1,050,479 +Liabilities +and Shareholders' Equity +Current +liabilities: +Accounts +payable +$ +90,532 +$ +88,502 +Accounts +payable - affiliates +40,540 +3,828 +Production +tax liability +18,226 +21,330 +Federal +and state income taxes payable +1,591 +901 +Fair +value of derivatives +4,766 +6,291 +Advances +for future drilling contracts +1,675 +68,417 +Funds +held for distribution +50,361 +39,823 +Net +deferred income taxes - current +28,355 +- +Other +accrued expenses +25,125 +12,913 +Total +current liabilities +261,171 +242,005 +Long-term +debt +394,867 +235,000 +Net +deferred income taxes - non current +162,593 +136,490 +Other +liabilities +71,798 +40,699 +Total +liabilities +890,429 +654,194 +Commitments +and contingent liabilities +Minority +interest in consolidated limited liability company +694 +759 +Shareholders' +equity: +Preferred +shares, par value $.01 per share; authorized 50,000,000 shares; +issued: none +- +- +Common +shares, par value $.01 per share; authorized 100,000,000 shares; +issued: 14,871,870 in 2008 and 14,907,679 in +2007 +149 +149 +Additional +paid-in capital +5,818 +2,559 +Retained +earnings +505,906 +393,044 +Treasury +shares, at cost: 7,066 shares in 2008 and 5,894 in 2007 +(292 +) +(226 +) +Total +shareholders' equity +511,581 +395,526 +Total +Liabilities and Shareholders' Equity +$ +1,402,704 +$ +1,050,479 +See accompanying Notes to +Consolidated Financial Statements . +F-5 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +Consolidated +Statements of Operations +(in +thousands, except per share data) +Year +Ended December 31, +2008 +2007 +2006 +Revenues: +Oil +and gas sales +$ +321,877 +$ +175,187 +$ +115,189 +Sales +from natural gas marketing activities +140,263 +103,624 +131,325 +Oil +and gas well drilling +7,615 +12,154 +17,917 +Well +operations and pipeline income +11,474 +9,342 +10,704 +Oil +and gas price risk management gain, net +127,838 +2,756 +9,147 +Other +293 +2,172 +2,221 +Total +revenues +609,360 +305,235 +286,503 +Costs +and expenses: +Oil +and gas production and well operations cost +78,209 +49,264 +29,021 +Cost +of natural gas marketing activities +139,234 +100,584 +130,150 +Cost +of oil and gas well drilling +2,213 +2,508 +12,617 +Exploration +expense +45,105 +23,551 +8,131 +General +and administrative expense +37,715 +30,968 +19,047 +Depreciation, +depletion, and amortization +104,575 +70,844 +33,735 +Total +costs and expenses +407,051 +277,719 +232,701 +Gain +on sale of leaseholds +- +33,291 +328,000 +Income +from operations +202,309 +60,807 +381,802 +Interest +income +591 +2,662 +8,050 +Interest +expense +(28,132 +) +(9,279 +) +(2,443 +) +Income +before income taxes +174,768 +54,190 +387,409 +Provision +for income taxes +61,459 +20,981 +149,637 +Net +income +$ +113,309 +$ +33,209 +$ +237,772 +Earnings +per common share: +Basic +$ +7.69 +$ +2.25 +$ +15.18 +Diluted +$ +7.63 +$ +2.24 +$ +15.11 +Weighted +average common and common equivalent shares outstanding: +Basic +14,736 +14,744 +15,660 +Diluted +14,848 +14,841 +15,741 +See accompanying Notes to +Consolidated Financial Statements . +F-6 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +Consolidated +Statements of Shareholders' Equity +(in +thousands, except share and per share data) +Year +Ended December 31, +2008 +2007 +2006 +Common +stock, par value $.01 per share - shares issued: +Shares +at beginning of year +14,907,679 +14,834,871 +16,281,923 +Adjust +prior conversion of predecessor shares +100 +- +59,546 +Exercise +of stock options +25,699 +38,000 +8,000 +Issuance +of stock awards, net of forfeitures +21,863 +46,828 +112,902 +Retirement +of treasury shares +(83,471 +) +(12,020 +) +(1,627,500 +) +Shares +at end of year +14,871,870 +14,907,679 +14,834,871 +Treasury +stock: +Shares +at beginning of year +(5,894 +) +(4,706 +) +- +Purchase +of treasury shares +(83,471 +) +(12,020 +) +(1,627,500 +) +Retirement +of treasury shares +83,471 +12,020 +1,627,500 +Non-employee +directors' deferred compensation plan +(1,172 +) +(1,188 +) +(4,706 +) +Shares +at end of year +(7,066 +) +(5,894 +) +(4,706 +) +Common +shares outstanding +14,864,804 +14,901,785 +14,830,165 +Common +stock, $.01 par: +Balance +at beginning of year +$ +149 +$ +148 +$ +163 +Exercise +of stock options +- +- +- +Issuance +of stock awards, net of forfeitures +- +1 +1 +Retirement +of treasury shares +- +- +(16 +) +Balance +at end of year +149 +149 +148 +Additional +paid-in capital: +Balance +at beginning of year +2,559 +64 +30,423 +Reclassification +of unearned compensation pursuant to the adoption of SFAS No. +123(R) +- +- +(825 +) +Exercise +of stock options +627 +183 +31 +Issuance +of stock awards, net of forfeitures +- +(1 +) +(1 +) +Stock +based compensation expense +6,702 +2,286 +1,516 +Retirement +of treasury shares +(5,101 +) +(646 +) +(31,150 +) +Excess +tax benefit of stock based compensation +1,031 +673 +70 +Balance +at end of year +5,818 +2,559 +64 +Retained +earnings: +Balance +at beginning of year +393,044 +360,102 +158,504 +Cumulative +effect adjustment for the adoption of SAB 108, net of tax +- +- +(1,021 +) +FIN +48 adoption +- +(267 +) +- +Retirement +of treasury shares +(447 +) +- +(35,153 +) +Net +income +113,309 +33,209 +237,772 +Balance +at end of year +505,906 +393,044 +360,102 +Unamortized +stock award +Balance +at beginning of year +- +- +(825 +) +Reclassification +of unearned compensation pursuant to the adoption of SFAS No. +123(R) +- +- +825 +Balance +at end of year +- +- +- +Treasury +stock, at cost: +Balance +at beginning of year +(226 +) +(170 +) +- +Purchase +of treasury shares +(5,549 +) +(646 +) +(66,319 +) +Retirement +of treasury shares +5,549 +646 +66,319 +Non-employee +directors' deferred compensation plan +(66 +) +(56 +) +(170 +) +Balance +at end of year +(292 +) +(226 +) +(170 +) +Total +shareholders' equity +$ +511,581 +$ +395,526 +$ +360,144 +See accompanying Notes to +Consolidated Financial Statements . +F-7 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +Consolidated +Statements of Cash Flows +(in +thousands) +Year +Ended December 31, +2008 +2007 +2006 +Cash +flows from operating activities: +Net +income +$ +113,309 +$ +33,209 +$ +237,772 +Adjustments +to net income to reconcile to net cash provided by operating +activities: +Deferred +income taxes +59,079 +12,201 +86,431 +Depreciation, +depletion and amortization +104,575 +70,844 +33,735 +Allowance +for doubtful accounts +180 +50 +7 +Amortization +of debt issuance costs +1,344 +394 +- +Impairment +of oil and gas properties +22,091 +1,485 +1,519 +Accretion +of asset retirement obligation +1,230 +999 +515 +Exploratory +dry hole costs +6,504 +1,775 +1,790 +Loss +(gain) from sale of leaseholds/assets +19 +(33,322 +) +(327,991 +) +Expired +and abandoned leases +3,633 +1,786 +2,169 +Stock +based compensation +6,702 +2,286 +1,516 +Unrealized +(gains) losses on derivative transactions +(117,536 +) +4,642 +(7,620 +) +Excess +tax benefits from stock-based compensation +(1,031 +) +(673 +) +(70 +) +Changes +in current assets and liabilities: +(Increase) +decrease in restricted cash +(4,257 +) +(14,254 +) +982 +Increase +in accounts receivable +(9,844 +) +(16,506 +) +(9,942 +) +Increase +in accounts receivable - affiliates +(7,631 +) +(2,302 +) +(194 +) +(Increase) +decrease in inventories +(2,062 +) +1,285 +1,987 +(Increase) +decrease in other current assets +(5,793 +) +4,839 +(2,106 +) +Increase +(decrease) in production tax liability +9,857 +10,802 +(261 +) +Increase +(decrease) in accounts payable and accrued expenses +2,790 +(10,869 +) +13,010 +Increase +(decrease) in accounts payable - affiliates +10,282 +(3,099 +) +6,116 +(Decrease) +increase in advances for future drilling contracts +(66,742 +) +13,645 +4,773 +Increase +(decrease) in federal and state income taxes payable +1,721 +(27,124 +) +19,950 +Increase +in funds held for future distribution +10,538 +7,488 +(575 +) +Other +143 +723 +3,877 +Net +cash provided by operating activities +139,101 +60,304 +67,390 +Cash +flows from investing activities: +Capital +expenditures +(323,153 +) +(238,988 +) +(146,945 +) +Acquisition +of oil and gas properties, net of cash acquired +- +(255,661 +) +(18,512 +) +Investment +in drilling partnerships +- +- +(7,151 +) +(Increase) +decrease in restricted/designated cash +(874 +) +191,156 +(192,416 +) +Proceeds +from sale of leases to partnerships +448 +1,371 +1,798 +Proceeds +from sale of leaseholds/assets +538 +34,701 +353,600 +Net +cash used in investing activities +(323,041 +) +(267,421 +) +(9,626 +) +Cash +flows from financing activities: +Proceeds +from credit facility +419,000 +352,000 +302,000 +Proceeds +from senior notes +200,101 +- +- +Proceeds +from short-term debt +- +- +20,000 +Payment +of credit facility +(459,500 +) +(254,000 +) +(209,000 +) +Payment +of debt issuance costs +(5,571 +) +(1,468 +) +(160 +) +Proceeds +from exercise of stock options +627 +183 +31 +Excess +tax benefits from stock-based compensation +1,031 +673 +70 +Minority +interest investment +- +800 +- +Purchase +of treasury stock +(5,549 +) +(646 +) +(66,489 +) +Net +cash provided by financing activities +150,139 +97,542 +46,452 +Net +(decrease) increase in cash and cash equivalents +(33,801 +) +(109,575 +) +104,216 +Cash +and cash equivalents, beginning of year +84,751 +194,326 +90,110 +Cash +and cash equivalents, end of year +$ +50,950 +$ +84,751 +$ +194,326 +Supplemental +cash flow information: +Cash +payments for: +Interest, +net of capitalized interest +$ +19,200 +$ +9,535 +$ +1,376 +Income +taxes, net of refunds +(530 +) +43,785 +46,735 +Non-cash +investing activities: +Change +in deferred tax liability resulting from reallocation of acquisition +purchase price +- +4,188 +- +Change +in accounts payable - affiliates related to acquisition of +partnerships +- +668 +- +Change +in accounts payable related to purchases of properties and +equipment +8,197 +32,820 +1,800 +Change +in accounts payable - affiliates related to investment in drilling +partnership +- +18,712 +(7,151 +) +Change +in asset retirement obligation, with a corresponding increase to oil and +gas properties, net of disposals +1,153 +7,850 +3,164 +See +accompanying Notes to Consolidated Financial Statements . +F-8 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS +NOTE +1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +General +Petroleum +Development Corporation (“PDC,” “we,” “us” or “the Company”) is an independent +energy company engaged primarily in the drilling and development, production and +marketing of natural gas and oil. Since we began oil and gas +operations in 1969, we have grown primarily through drilling and development +activities, the acquisition of producing natural gas and oil wells and the +expansion of our natural gas marketing activities. As of December 31, +2008, we operate approximately 4,712 wells located in the Appalachian Basin, +Michigan Basin, and the Rocky Mountain Region. Our oil and natural +gas wells are located in West Virginia, Tennessee, Pennsylvania, Michigan, North +Dakota, Colorado, Kansas, Texas and Wyoming. We separate our +operations into four business segments: oil and gas sales, natural gas marketing +activities, well operations and pipeline income and oil and gas well drilling +operations. See Note 16 , Business +Segments . +Principles of +Consolidation +The +consolidated financial statements of PDC include the accounts of our +wholly-owned subsidiaries and WWWV, LLC, an entity in which we have a +controlling financial interest. All material intercompany accounts +and transactions have been eliminated in consolidation. We account +for our investment in interests in oil and gas limited partnerships under the +proportionate consolidation method. Under this method, our +consolidated financial statements include our investments in the partnerships +recorded by our working interest in each well thereby accumulating our pro rata +share of assets, liabilities and revenues and expenses respectively of the +limited partnerships in which we participate. Our proportionate share +of all significant transactions between us and the limited partnerships is +eliminated. +Use +of Estimates +The +preparation of our consolidated financial statements in accordance with +generally accepted accounting principles in the United States of America +(“U.S.”) requires us to make estimates and assumptions that affect the amounts +reported in our consolidated financial statements and accompanying +notes. Actual results could differ from those +estimates. Estimates which are particularly significant to our +consolidated financial statements include estimates of oil and gas reserves, +future cash flows from oil and gas properties, valuation of derivative +instruments and valuation of deferred income tax assets. +Cash +Equivalents +For +purposes of the statement of cash flows, we consider all highly liquid debt +instruments with original maturities of three months or less to be cash +equivalents. +Restricted Cash +Included +in our restricted cash – current as of December 31, 2007, along with interest +earned of $0.4 million, is an escrow account funded in June 2007 in the amount +of $14.1 million, representing amounts due to the limited partners of our +sponsored drilling partnerships as a result of our over withholding estimated +production taxes in years prior to 2007. In October 2008, as part of +a pre-filing agreement, we paid the Internal Revenue Service on behalf of the +limited partners an estimated tax payment of $4.2 million. As of +December 31, 2008, we had reflected in restricted cash - current $10.6 million, +including additional interest of $0.3 million earned in 2008. +Pursuant +to a preliminary court approved litigation settlement agreement reached in +October 2008, we funded an escrow account in November 2008 in the amount of $8.2 +million, of which $5.8 million represented the Company’s share of the settlement +and the remainder being that of the affiliated partnerships for which the +Company serves as the managing general partner. As of December 31, +2008, restricted cash – current includes $8.2 million related to this escrow +account. Further, our balance sheet includes a related accounts +receivable from our affiliated partnerships of $2.4 million. +We are +required by a counterparty to maintain a margin deposit for outstanding +derivative contracts. As of December 31, 2007, cash in the amount of +$0.3 million was on deposit and reflected in our consolidated balance sheets as +restricted cash - current. As of December 31, 2008, the margin +deposit requirement was insignificant. +F-9 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +We are +required by various government agencies or joint venture agreements to maintain +a bond or cash account for the plugging and abandonment of wells. As +of December 31, 2008 and 2007, we had bonds in the form of certificates of +deposit for plugging and abandonment of wells totaling $2.2 million and $1.3 +million, respectively, which are reflected in other assets. +Accounts +Receivable +Our +accounts receivable are primarily from purchasers of oil and natural gas and +third parties and affiliated partnerships for well pipeline operating +services. Inherent to our industry is the concentration of oil and +natural gas sales to a few customers. This industry concentration has +the potential to impact our overall exposure to credit risk, either positively +or negatively, in that our customers may be similarly affected by changes in +economic, industry or other conditions. +We +provide an allowance for doubtful accounts equal to the estimated uncollectible +amounts. In making our estimate, we consider our historical +write-offs, relationships and overall creditworthiness of our customers, +additional consideration is given to well production data for receivables +related to well operations. It is reasonably possible that our +estimate of uncollectible amounts will change periodically. Accounts +receivable are presented on our consolidated balance sheets net of allowance for +doubtful accounts of $0.5 million and $0.4 million at December 31, 2008 and +2007, respectively. +Inventories +Materials, +supplies and commodity inventories are stated at the lower of average cost or +market and removed at carrying value. Inventory of $4.3 million and +$2.2 million as of December 31, 2008 and 2007, respectively, is included in +prepaid expenses and other current assets on our consolidated balance +sheets. +Derivative +Financial Instruments +We +account for derivative financial instruments in accordance with Statement of +Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative +Instruments and Certain Hedging Activities , as amended. +During +2008, 2007 and 2006, none of our derivative instruments qualified for use of +hedge accounting under the terms of SFAS No. 133. Accordingly, we +recognize all derivative instruments as either assets or liabilities on our +consolidated balance sheets at fair value, and changes in the derivatives' fair +values are recorded on a net basis in our consolidated statements of +operations. Changes in the fair value of derivative instruments +related to our oil and gas sales activities are recorded in oil and gas price +risk management, net and changes in fair value of derivatives related to our +natural gas marketing activities are recorded in sales from and cost of natural +gas marketing activities. +We record +on our consolidated balance sheets the fair value of derivative instruments +entered into by us and allocated to our affiliated partnerships, recording an +offsetting receivable from or payable to those partnerships. +See Note 2 , Fair Value of Financial +Instruments , and Note 3 , Derivative Financial +Instruments , for a discussion of our derivative fair value measurements +and a summary fair value table of our open positions as of December 31, 2008 and +2007, respectively. +Properties +and Equipment +Oil +and Gas Properties. +We +account for our oil and gas properties under the successful efforts method of +accounting. Costs of proved developed producing properties, +successful exploratory wells and development dry hole costs are capitalized and +depreciated or depleted by the unit-of-production method based on estimated +proved developed producing oil and natural gas reserves. Property +acquisition costs are depreciated or depleted on the unit-of-production method +based on estimated proved oil and gas reserves. +F-10 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Our +estimates of proved reserves are based on quantities of oil and natural gas that +engineering and geological analysis demonstrates, with reasonable certainty, to +be recoverable from established reservoirs in the future under current operating +and economic conditions. Annually, we engage independent petroleum +engineers to prepare a reserve and economic evaluation of all our properties on +a well-by-well basis as of December 31. Additionally, we adjust our +oil and gas reserves for major acquisitions, new drilling and divestitures +during the year as needed. The process of estimating and evaluating +oil and natural gas reserves is complex, requiring significant decisions in the +evaluation of available geological, geophysical, engineering and economic +data. The data for a given property may also change substantially +over time as a result of numerous factors, including additional development +activity, evolving production history and a continual reassessment of the +viability of production under changing economic conditions. As a +result, revisions in existing reserve estimates occur from time to +time. Although every reasonable effort is made to ensure that reserve +estimates reported represent our most accurate assessments possible, the +subjective decisions and variances in available data for various properties +increase the likelihood of significant changes in these +estimates. Because estimates of reserves significantly affect our +depreciation, depletion and amortization (“DD&A”) expense, a change in our +estimated reserves could have an effect on our net income. +Exploration +costs, including geological and geophysical expenses and delay rentals, are +charged to expense as incurred. Exploratory well drilling costs, +including the cost of stratigraphic test wells, are initially capitalized but +charged to expense if the well is determined to be nonproductive. The +status of each in-progress well is reviewed quarterly to determine the proper +accounting treatment under the successful efforts method of +accounting. Exploratory well costs continue to be capitalized as long +as the well has found a sufficient quantity of reserves to justify our +completion as a producing well and we are making sufficient progress assessing +our reserves and economic and operating viability. If an in-progress +exploratory well is found to be unsuccessful (referred to as a dry hole) prior +to the issuance of the financial statements, the costs incurred prior to the end +of the reporting period are expensed to exploration costs. If we are +unable to make a final determination about the productive status of a well prior +to issuance of the financial statements, the costs associated with the well are +classified as “suspended well costs” until we have had sufficient time to +conduct additional completion or testing operations to evaluate the pertinent +geological and engineering data obtained. At the time when we are +able to make a final determination of a well’s productive status, the same well +is removed from the suspended well status and the proper accounting treatment is +recorded. At December 31, 2008, suspended well costs included in oil +and gas properties on our consolidated balance sheet were $1.2 +million. See Note 4 , Properties and +Equipment . +The +acquisition costs of unproved properties are capitalized when incurred, until +such properties are transferred to proved properties or charged to expense when +expired, impaired or amortized. Unproved oil and gas properties with +individually significant acquisition costs are periodically assessed, and any +impairment in value is charged to exploratory expense. The amount of +impairment recognized on unproved properties which are not individually +significant is determined by amortizing the costs of such properties within +appropriate fields based on our historical experience, acquisition dates and +average lease terms. Impairment costs are recorded in the statements +of operations as a component of exploration expense and were as follows for each +of the periods indicated: +2008 +2007 +2006 +(in +thousands) +Individually +significant unproved properties (1) +$ +9,165 +$ +1,484 +$ +473 +Insignificant +unproved properties +3,633 +1,786 +157 +Total +$ +12,798 +$ +3,270 +$ +630 +__________ +(1) +2007 +includes liquidated damages of $1.1 million related to the abandonment of +an exploration agreement with an unaffiliated +party. +The +valuation of unproved properties is subjective and requires us to make estimates +and assumptions which, with the passage of time, may prove to be materially +different from actual realizable values. +F-11 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +In +accordance with SFAS No. 144, Accounting for the Impairment or +Disposal of Long-Lived Assets , we assess our oil and gas properties for +possible impairment quarterly by comparing net capitalized costs to estimated +undiscounted future net cash flows on a field-by-field basis using estimated +production based upon prices at which we reasonably estimate the commodity to be +sold. The estimates of future prices may differ from current market +prices of oil and natural gas. Any downward revisions in estimates to +our reserve quantities, expectations of falling commodity prices or rising +operating costs could result in a reduction in undiscounted future net cash +flows and an impairment of our oil and gas properties. If net +capitalized costs exceed undiscounted future net cash flows, the measurement of +impairment is based on estimated fair value which would consider future +discounted cash flows. We recognized impairment losses on proved oil +and gas properties of $12.8 million in 2008, consisting of $7.5 million related +to our properties in the Fort Worth Basin, $3 million in our Bakken Field in +North Dakota and $2.3 million in our Nesson Field also in North +Dakota. In 2006, we recorded an impairment loss of $1.5 million in +our Nesson Field. Impairment charges related to our oil and gas +properties are included in our statements of operations as a component of +exploration expense. No impairments related to proved oil and natural gas +properties were recorded in 2007. +Upon sale +or retirement of significant portions of or complete fields of depreciable or +depletable property, the net book value thereof, less proceeds or salvage value, +is credited or charged to income. Upon sale of individual wells, the +proceeds are credited to property costs. +Other +Property and Equipment. +The +following table sets forth the estimated useful lives of our other property and +equipment. +Pipelines +and related facilities +10 +- 17 years +Transportation +and other equipment +3 - +20 years +Buildings +30 +- 40 years +Pipelines, Transportation Equipment +and Other Equipment . Pipelines, transportation equipment and +other equipment are carried at cost. Depreciation is provided +principally on the straight-line method over the assets estimated useful +lives. In accordance with SFAS No. 144 , Accounting for the Impairment or +Disposal of Long-Lived Assets , long-lived assets, such as property, plant +and equipment, are reviewed for impairment whenever events or changes in +circumstances indicate that the carrying amount of an asset may not be +recoverable. Recoverability of assets to be held and used is measured +by a comparison of the carrying amount of an asset to estimated undiscounted +future cash flows expected to be generated by the asset. If the +carrying amount of an asset exceeds our estimated future cash flows, an +impairment charge is recognized in the amount by which the carrying amount of +the asset exceeds the fair value of the asset. No impairments were +recorded in 2008, 2007or 2006. +Buildings. Buildings +are carried at cost and depreciated on the straight-line method over their +estimated useful lives. +Maintenance +and repairs on other property and equipment are charged to expense as +incurred. Major renewals and improvements are +capitalized. Upon the sale or other disposition of assets, the cost +and related accumulated depreciation, depletion and amortization are removed +from the accounts, the proceeds are applied thereto and any resulting gain or +loss is reflected in income. +Total +depreciation expense related to other property and equipment was $7.6 million, +$4.3 million and $2 million in 2008, 2007 and 2006, respectively. +Capitalized +Interest +Interest +costs are capitalized as part of the historical cost of acquiring +assets. Oil and gas investments in unproved properties and major +development projects, on which DD&A expense is not currently recorded and on +which exploration or development activities are in progress, qualify for +capitalization of interest. Major construction projects also qualify +for interest capitalization until the asset is ready for +service. Capitalized interest is calculated by multiplying our +weighted-average interest rate on our debt outstanding by the qualifying +costs. Interest capitalized may not exceed gross interest expense for +the period. As the qualifying asset is moved to the DD&A pool, +the related capitalized interest is also transferred and is amortized over the +useful life of the asset. Interest costs of $2.6 million, $3 million +and $1.6 million were capitalized in 2008, 2007 and 2006, +respectively. +F-12 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Production +Tax Liability +Production +tax liability represents estimated taxes, primarily severance and property, to +be paid to the states and counties in which we produce oil and +gas. Our share of these taxes is expensed to oil and gas production +and well operations cost. +Advances +for Future Drilling Contracts +Advances +for future drilling contracts represent funds received from our sponsored +drilling partnerships for drilling activities which have not been completed, a +portion of which will be recognized as revenue in accordance with our revenue +recognition policies. The amount advanced and outstanding as of +December 31, 2008, are primarily related to the drilling partnership sponsored +in August 2007 and represents the remaining costs to finish the wells, primarily +reclamation. No partnership was sponsored in 2008. +Income +Taxes +We +account for income taxes under the asset and liability method. We +recognize deferred tax assets and liabilities for the future tax consequences +attributable to differences between the financial statement carrying amounts of +existing assets and liabilities and their respective tax +bases. Deferred tax assets and liabilities are measured using enacted +tax rates expected to apply to taxable income in the years in which those +temporary differences are expected to be recovered or settled. The +effect on deferred tax assets and liabilities of a change in tax rates is +recognized in income in the period that includes the enactment +date. If we determine that it is more likely than not that some +portion or all of the deferred tax assets will not be realized, we record a +valuation allowance thereby reducing the deferred tax assets to what we consider +realizable. No valuation allowance was recorded at December 31, 2008 +or 2007. +Asset +Retirement Obligations +We +account for asset retirement obligations by recording the fair value of our +plugging and abandonment obligations when incurred, which is at the time the +well is completely drilled. Upon initial recognition of an asset +retirement obligation, we increase the carrying amount of the long-lived asset +by the same amount as the liability. Over time, the liabilities are +accreted for the change in their present value, through charges to oil and gas +production and well operations costs. The initial capitalized costs +are depleted over the useful lives of the related assets, through charges to +depreciation, depletion and amortization. If the fair value of the +estimated asset retirement obligation changes, an adjustment is recorded to both +the asset retirement obligation and the asset retirement +cost. Revisions in estimated liabilities can result from revisions of +estimated inflation rates, escalating retirement costs and changes in the +estimated timing of settling asset retirement obligations. See Note 7 , Asset Retirement Obligations , +for a reconciliation of asset retirement obligation activity. +Minority +Interest in Consolidated Limited Liability Company +In May +2007, we contributed $0.8 million for a 50% interest in WWWV, LLC (“LLC”), a +limited liability company for which we serve as the managing +member. One-sixth of the entity is owned by a member of our Board of +Directors, who paid the same unit price for his interest as was paid by us and +unrelated third parties for such interests in the LLC. The LLC's only +asset is an aircraft and the LLC was formed for the purpose of owning and +operating the aircraft. +The +minority interest portion of pre-tax expense incurred by and belonging to the +minority interest holders of the consolidated limited liability company is not +material and is included in our consolidated statement of operations as an +offset to DD&A expense. +Retirement +of Treasury Shares +We +have historically retired all treasury share purchases, with the exception of +shares purchased in accordance with our non-employee deferred compensation plan +for non-employee directors, see Note 9 , Common Stock . As +treasury shares are retired, we charge any excess of cost over the par value +entirely to additional paid-in-capital, to the extent we have amounts in +paid-in-capital, with any remaining excess cost being charged to retained +earnings. +Revenue +Recognition +Oil and natural gas +sales . Sales of oil are recognized when persuasive evidence of +a sales arrangement exists, the oil is verified as produced and is delivered to +a purchaser, collection of revenue from the sale is reasonably assured and the +sales price is determinable. We are currently able to sell all the +oil that we can produce under existing sales contracts with petroleum refiners +and marketers. We do not refine any of our oil +production. Our crude oil production is sold to purchasers at or near +our wells under short-term purchase contracts at prices and in accordance with +arrangements that are customary in the oil industry. +F-13 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Sales of +natural gas are recognized when natural gas has been delivered to a custody +transfer point, persuasive evidence of a sales arrangement exists, the rights +and responsibility of ownership pass to the purchaser upon delivery, collection +of revenue from the sale is reasonably assured and the sales price is fixed or +determinable. Natural gas is sold by us under contracts with terms +ranging from one month to three years. Virtually all of our contract +pricing provisions are tied to a market index, with certain adjustments based +on, among other factors, whether a well delivers to a gathering or transmission +line, quality of natural gas and prevailing supply and demand conditions, so +that the price of the natural gas fluctuates to remain competitive with other +available natural gas supplies. As a result, our revenues from the +sale of natural gas will suffer if market prices decline and benefit if they +increase. We believe that the pricing provisions of our natural gas +contracts are customary in the industry. +We +currently use the “net-back” method of accounting for transportation +arrangements of our natural gas sales. We sell gas at the wellhead +and collect a price and recognize revenues based on the wellhead sales price +since transportation costs downstream of the wellhead are incurred by the +customers and reflected in the wellhead price. +Natural gas marketing +activities . Natural gas marketing is reported on the gross +accounting method, based on the nature of the agreements between RNG, our +suppliers and our customers. RNG, our marketing subsidiary, purchases +gas from many small producers and bundles the gas together to sell in larger +amounts to purchasers of natural gas for a price advantage. RNG has +latitude in establishing price and discretion in supplier and purchaser +selection. Natural gas marketing revenues and expenses reflect the +full cost and revenue of those transactions because RNG takes title to the gas +it purchases from the various producers and bears the risks and rewards of that +ownership. Both the realized and unrealized gains and losses of the +RNG commodity based derivative transactions for natural gas marketing activities +are included in gas sales from marketing activities or cost of gas marketing +activities, as applicable. +Oil and gas well +drilling . Our drilling segment recognizes revenue from +drilling contracts with sponsored drilling programs using the percentage of +completion method based upon the percentage of contract costs incurred to date +to the estimated total contract costs for each contract. We utilize +this method since reasonably dependable estimates of the total estimated costs +can be made and recognized revenues are subject to revisions as a contract +progresses, the term of which can range from three to twelve +months. We have offered our drilling services under two types of +contractual arrangements, cost-plus or footage-based service contracts, which +result in differing risk and reward relationships, and consequently, different +revenue reporting policies pursuant to Emerging Issues Task Force (“EITF”) Issue +No. 99-19, Reporting Revenue +Gross as a Principal versus Net as an Agent . +The first +cost-plus drilling service arrangement was entered into in late 2005 with +drilling activity commencing in the first quarter of 2006. Due to the +fixed-fee-percentage nature of our revenues from these services, we have +determined that, in substance, we are acting as an agent, without risk of loss +during the performance of the drilling activities. Accordingly, our +services provided under the cost-plus drilling agreements are reported on a net +basis. We entered into our second and third cost-plus drilling +arrangements in September 2006 and August 2007 and commenced drilling +immediately. +Footage-based +contracts provide for the drilling, completion and equipping of wells at footage +rates and are generally completed within nine to twelve months after the +commencement of drilling. We provide geological, engineering, and +drilling supervision on the drilling and completion process and use +subcontractors to perform drilling and completion services and accordingly we +have the risk of loss in performing services under these +arrangements. Accordingly, we report revenue under these agreements +gross of related expenses. Anticipated losses, if any, on uncompleted +contracts are recorded at the time that the estimated total costs exceed the +estimated total contract revenue. At December 31, 2007, included as a +component of other current liabilities on the consolidated balance sheets, we +had recorded a loss contract reserve of $0.2 million. No loss +contract reserve was recorded as of December 31, 2008. +Well operations and pipeline +income . Well operations and pipeline income are recognized +when persuasive evidence of an arrangement exists, services have been rendered, +collection of revenues is reasonably assured and the sales price is fixed or +determinable. We are paid a monthly operating fee for each well we +operate and natural gas transported for outside owners including the limited +partnerships we sponsored. The fee covers monthly operating and +accounting costs, insurance and other recurring costs. We may also +receive additional compensation for special non-recurring activities, such as +reworks and recompletions. +F-14 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Stock-Based +Compensation +On +January 1, 2006, we adopted SFAS No. 123 (revised 2004), Share-Based Payment (“SFAS +No. 123R”), to account for stock-based compensation. SFAS No. 123R +eliminated the use of Accounting Principles Board Opinion (“APB”) No. 25, Accounting for Stock Issued to +Employees , and the intrinsic value method of accounting for equity +compensation and requires us to recognize the cost of employee services received +in exchange for awards of equity instruments based on fair value at the date of +grant in our financial statements. We elected to use the modified +prospective method for adoption, and accordingly, prior period financial +statements have not been restated. For all unvested options and other +equity based awards outstanding as of January 1, 2006, the previously measured +but unrecognized compensation expense, based on the fair value at the original +grant date, will be recognized in the financial statements over the remaining +requisite service period for each separately vesting portion. For +equity-based compensation awards granted or modified subsequent to January 1, +2006, compensation expense, based on the fair value on the date of grant or +modification, will be recognized in the financial statements on a straight-line +basis over the vesting period for the entire award. To the extent +compensation cost relates to employees directly involved in oil and natural gas +acquisition, exploration and development activities, such amounts are +capitalized to properties and equipment. Amounts not capitalized to +properties and equipment are recognized in the appropriate cost and expense line +item in the statement of operations. No amounts for stock-based +compensation were capitalized in 2008, 2007 and 2006. +Earnings +Per Share +Basic +earnings per common share (“EPS”) is computed by dividing net income (the +numerator) by the weighted-average number of common shares outstanding for the +period (the denominator). Diluted EPS is similarly computed except +that the denominator includes the effect, using the treasury stock method, of +our outstanding stock options, unamortized portion of restricted stock and +shares held pursuant to our non-employee director deferred compensation plan, if +including such potential shares of common stock is dilutive. +The +following is a reconciliation of the basic and diluted weighted-average shares +outstanding for the years ended December 31: +2008 +2007 +2006 +(in +thousands, except per share data) +Weighted +average common shares outstanding - basic +14,736 +14,744 +15,660 +Dilutive +effect of share-based compensation: (1) +Unamortized +portion of restricted stock +71 +44 +22 +Stock +options +35 +48 +55 +Non +employee director deferred compensation +6 +5 +4 +Weighted +average common and common share equivalents outstanding - +diluted +14,848 +14,841 +15,741 +(1) +Weighted average common share equivalents excluded from diluted +earnings per share due to their anti-dilutive affect: +Unamortized +portion of restricted stock +73 +18 +- +Stock +options +- +- +24 +Total +anti-dilutive common share equivalents +73 +18 +24 +F-15 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Recent +Accounting Standards +Recently Adopted Accounting +Standards +We +adopted the provisions of Statement of SFAS No. 157, Fair Value Measurements , +effective January 1, 2008. SFAS No. 157 defines fair value, +establishes a framework for measuring fair value and expands disclosures related +to fair value measurements. SFAS No. 157 applies broadly to financial and +nonfinancial assets and liabilities that are measured at fair value under other +authoritative accounting pronouncements, but does not expand the application of +fair value accounting to any new circumstances. In February 2008, the +Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“FSP”) +FAS No. 157-2, Effective Date +of FASB Statement No. 157 , which delays the effective date of SFAS No. +157 by one year (to January 1, 2009) for nonfinancial assets and liabilities, +except those that are recognized or disclosed at fair value in the financial +statements on a recurring basis (at least annually). Nonfinancial +assets and liabilities for which we have not applied the provisions of SFAS No. +157 include those initially measured at fair value, including our asset +retirement obligations. As of the adoption date, we have applied the +provisions of SFAS No. 157 to our recurring measurements and the impact was not +material to our underlying fair values and no amounts were recorded relative to +the cumulative effect of a change in accounting. We are currently +evaluating the potential effect that the nonfinancial assets and liabilities +provisions of SFAS No. 157 will have on our financial statements when adopted in +2009. See Note 2 , Fair Value of Financial +Instruments . +In +October 2008, the FASB issued FSP No. FAS 157-3, Determining the Fair Value of a +Financial Asset in a Market That Is Not Active , which applies to +financial assets within the scope of accounting pronouncements that require or +permit fair value measurements in accordance with SFAS No. 157. This FSP +clarifies the application of SFAS No. 157 in a market that is not active and +defines additional key criteria in determining the fair value of a financial +asset when the market for that financial asset is not active. FSP No. +FAS 157-3 was effective upon issuance and did not have a material impact on our +financial statements. +In +February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial +Assets and Financial Liabilities . SFAS No. 159 permits +entities to choose to measure, at fair value, many financial instruments and +certain other items that are not currently required to be measured at fair +value. The objective is to improve financial reporting by providing +entities with the opportunity to mitigate volatility in reported earnings caused +by measuring related assets and liabilities differently without having to apply +complex hedge accounting provisions. SFAS No. 159 establishes +presentation and disclosure requirements designed to facilitate comparisons +between entities that choose different measurement attributes for similar types +of assets and liabilities. The statement will be effective as of the +beginning of an entity's first fiscal year beginning after November 15, +2007. We have not elected to measure additional financial assets and +liabilities at fair value. +In April +2007, the FASB issued FSP No. FIN 39-1, Amendment of FASB Interpretation No. +39 (“FIN 39-1”), to amend certain portions of Interpretation +39. FIN 39-1 replaces the terms “conditional contracts” and “exchange +contracts” in Interpretation 39 with the term “derivative instruments” as +defined in Statement 133. FIN 39-1 also amends Interpretation 39 to +allow for the offsetting of fair value amounts for the right to reclaim cash +collateral or receivable, or the obligation to return cash collateral or +payable, arising from the same master netting arrangement as the derivative +instruments. FIN 39-1 applies to fiscal years beginning after +November 15, 2007, with early adoption permitted. The January 1, +2008, adoption of FSP FIN 39-1 had no impact on our financial +statements. +In June +2006, the FASB issued EITF No. 06-3, How Taxes Collected from Customers +and Remitted to Governmental Authorities Should be Presented in the Income +Statement (That Is, Gross versus Net Presentation) . EITF 06-3 +addresses the income statement presentation of any tax collected from customers +and remitted to a government authority and concludes that the presentation of +taxes on either a gross basis or a net basis is an accounting policy decision +that should be disclosed pursuant to APB No. 22, Disclosures of Accounting +Policies . For taxes that are reported on a gross basis +(included in revenues and costs), EITF 06-3 requires disclosure of the amounts +of those taxes in interim and annual financial statements, if those amounts are +significant. EITF 06-3 became effective for interim and annual +reporting periods beginning after December 15, 2006. The adoption of +the standard, effective January 1, 2007, did not have a significant effect on +our consolidated financial statements. Our existing accounting +policy, which was not changed upon the adoption of EITF 06-3, is to present +taxes within the scope of EITF 06-3 on a net basis. +In July +2006, the FASB issued FIN No. 48, Accounting for Uncertainty in Income +Taxes - an Interpretation of FASB Statement 109 , which prescribes a +comprehensive model for accounting for uncertainty in tax +positions. FIN No. 48 provides that the tax effects from an uncertain +tax position can be recognized in the financial statements, only if the position +is more likely than not of being sustained on audit by the Internal Revenue +Service (“IRS”), based on the technical merits of the position. We +adopted the provisions of FIN No. 48 effective January 1, 2007. The +cumulative effect of applying the provisions of FIN No. 48 has been accounted +for as an adjustment to retained earnings in the first quarter of +2007. The adoption of FIN No. 48 resulted in a $0.3 million +cumulative effect adjustment (see Note 5 , Income Taxes , for further +discussion). +F-16 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +In May +2007, the FASB issued FASB Staff Position FIN No. 48-1, Definition of Settlement in FASB +Interpretation No. 48 (“FIN No. 48-1”). FIN No. 48-1 amends +FIN No. 48 to provide guidance on how an entity should determine whether a tax +position is effectively settled for the purpose of recognizing previously +unrecognized tax benefits. The term “effectively settled” replaces +the term “ultimately settled” when used to describe recognition, and the terms +“settlement” or “settled” replace the terms “ultimate settlement” or “ultimately +settled” when used to describe measurement of a tax position under FIN No. +48. FIN No. 48-1 clarifies that a tax position can be effectively +settled upon the completion of an examination by a taxing authority without +being legally extinguished. For tax positions considered effectively +settled, an entity would recognize the full amount of tax benefit, even if the +tax position is not considered more likely than not to be sustained based solely +on the basis of its technical merits and the statute of limitations remains +open. The adoption of FIN No. 48-1, effective January 1, 2007, did +not have an incremental effect on our consolidated financial +statements. +In +September 2006, the Securities and Exchange Commission (“SEC”) issued Staff +Accounting Bulletin (“SAB”) No. 108, Considering the Effects of Prior +Year Misstatements when Quantifying Misstatements in Current Year Financial +Statements . SAB No. 108 provides guidance on how the effects +of prior year misstatements should be considered in quantifying misstatements in +the current year financial statements. SAB No. 108 requires +registrants to quantify misstatements using both the income statement +(“rollover”) and balance sheet (“iron curtain”) approach and evaluate whether +either approach results in a misstatement that, when all relevant quantitative +and qualitative factors are considered, is material. Historically, we +evaluated uncorrected misstatements using the “rollover” method which resulted +in an accumulation of quantitatively and qualitatively immaterial misstatements +to our consolidated financial statements. SAB No. 108 provides for a +one time transitional adjustment to retained earnings for errors which were not +deemed material to prior year financial statements, but which is material under +guidance of SAB No. 108. We adopted SAB No. 108 during the fourth +quarter of 2006 and recorded a one-time adjustment to reduce retained earnings +by $1.0 million. +In +December 2004, the FASB issued SFAS No. 123(R), Share-Based +Payment . In March 2005, the SEC issued Staff Accounting +Bulletin (“SAB”) No. 107, Share-Based Payment , +regarding the interaction between SFAS No. 123(R) and certain SEC rules and +regulations. Effective January 1, 2006, we adopted SFAS No. 123(R). +We elected to use the modified prospective method for adoption, which requires +compensation expense to be recognized in the statement of operations for all +unvested stock options and other equity-based compensation beginning in the +first quarter of adoption. Prior to the adoption of SFAS No. 123(R), +we followed the intrinsic value method in accordance with APB No. 25 (as +amended) to account for employee stock-based compensation. The +adoption of SFAS No. 123(R) required the unamortized stock award recorded under +APB No. 25 related to stock-based compensation awards as of January 1, 2006, in +the amount of $0.8 million to be eliminated against additional +paid-in-capital. See Stock-Based Compensation +policy above and Note 9, Common Stock , for further +discussion of the Company's accounting for share-based compensation +awards. +Recently Issued Accounting +Standards +In +December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (“SFAS +No. 141R”). SFAS No. 141R requires an acquirer to recognize the +assets acquired, the liabilities assumed and any noncontrolling interest in the +acquiree at their acquisition-date fair values. SFAS No. 141R also +requires disclosure of the information necessary for investors and other users +to evaluate and understand the nature and financial effect of the business +combination. Additionally, SFAS No. 141R requires that +acquisition-related costs be expensed as incurred. The provisions of +SFAS No. 141R will become effective for acquisitions completed on or after +January 1, 2009; however, the income tax provisions of SFAS No. 141R will become +effective as of that date for all acquisitions, regardless of the acquisition +date. SFAS No. 141R amends SFAS No. 109, Accounting for Income Taxes , +to require the acquirer to recognize changes in the amount of its deferred tax +benefits recognizable due to a business combination either in income from +continuing operations in the period of the combination or directly in +contributed capital, depending on the circumstances. SFAS No. 141R +further amends SFAS No. 109 and FIN 48, Accounting for Uncertainty in Income +Taxes , to require, subsequent to a prescribed measurement period, changes +to acquisition-date income tax uncertainties to be reported in income from +continuing operations and changes to acquisition-date acquiree deferred tax +benefits to be reported in income from continuing operations or directly in +contributed capital, depending on the circumstances. Upon our +adoption of SFAS No. 141R effective January 1, 2009, we will recognize expense +of $1.4 million in deferred acquisition related costs. +In +December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in +Consolidated Financial Statements—An Amendment of ARB No. +51 . SFAS No. 160 states that accounting and reporting for +minority interests will be recharacterized as non-controlling interests and +classified as a component of equity. Additionally, SFAS No. 160 +establishes reporting requirements that provide sufficient disclosures which +clearly identify and distinguish between the interests of the parent and the +interests of the non-controlling owners. SFAS No. 160 is effective as +of the beginning of an entity’s first fiscal year beginning after December 15, +2008. We are evaluating the impact that SFAS No. 160 will have, if +any, on our consolidated financial statements and related disclosures when it is +adopted in 2009. +F-17 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +In March +2008, the FASB issued SFAS No. 161, Disclosures about Derivative +Instruments and Hedging Activities—An Amendment of FASB Statement No. +133 , which changes the disclosure requirements for derivative instruments +and hedging activities. Enhanced disclosures are required to provide +information about (a) how and why an entity uses derivative instruments, (b) how +derivative instruments and related hedged items are accounted for under +Statement 133 and its related interpretations and (c) how derivative instruments +and related hedged items affect an entity’s financial position, financial +performance and cash flows. SFAS No. 161 is effective for financial +statements issued for fiscal years and interim periods beginning after November +15, 2008, with early application encouraged. As SFAS No. 161 is +disclosure related, we do not expect its adoption to have a material impact on +our financial statements. +In +January 2009, the SEC published its final rule, Modernization of Oil and Gas +Reporting , which modifies the SEC’s reporting and disclosure rules for +oil and natural gas reserves. The most notable changes of the final +rule include the replacement of the single day period-end pricing to value oil +and natural gas reserves to a 12-month average of the first day of the month +price for each month within the reporting period. The final rule also +permits voluntary disclosure of probable and possible reserves, a disclosure +previously prohibited by SEC rules. The revised reporting and +disclosure requirements are effective for our Form 10-K for the year ended +December 31, 2009. Early adoption is not permitted. We are +evaluating the impact that adoption of this final rule will have on our +consolidated financial statements, related disclosure and management’s +discussion and analysis. +NOTE +2 – FAIR VALUE OF FINANCIAL INSTRUMENTS +Derivative Financial +Instruments . +Determination of fair +value . We measure fair value based upon quoted market +prices, where available. Our valuation determination includes: (1) +identification of the inputs to the fair value methodology through the review of +counterparty statements and other supporting documentation, (2) determination of +the validity of the source of the inputs, (3) corroboration of the original +source of inputs through access to multiple quotes, if available, or other +information and (4) monitoring changes in valuation methods and +assumptions. The methods described above may produce a fair value +calculation that may not be indicative of future fair values. Our +valuation determination also gives consideration to our nonperformance risk on +our own liabilities as well as the credit standing of our +counterparties. We primarily use two investment grade financial +institutions as our counterparties to our derivative contracts. We +have evaluated the credit risk of our derivative assets from our counterparties +using relevant credit market default rates, giving consideration to amounts +outstanding for each counterparty and the duration of each outstanding +derivative position. Based on our evaluation, we have determined that +the impact of the nonperformance of our counterparties on the fair value of our +derivative instruments is insignificant. As of December 31, +2008, no valuation allowance was recorded. Furthermore, while +we believe these valuation methods are appropriate and consistent with that used +by other market participants, the use of different methodologies, or +assumptions, to determine the fair value of certain financial instruments could +result in a different estimate of fair +value. +Valuation +hierarchy . SFAS No. 157 establishes a fair value hierarchy +that requires an entity to maximize the use of observable inputs and minimize +the use of unobservable inputs when measuring fair value. The +valuation hierarchy is based upon the transparency of inputs to the valuation of +an asset or liability as of the measurement date, giving the highest priority to +quoted prices in active markets (Level 1) and the lowest priority to +unobservable data (Level 3). In some cases, the inputs used to +measure fair value might fall in different levels of the fair value +hierarchy. The lowest level input that is significant to a fair value +measurement in its entirety determines the applicable level in the fair value +hierarchy. Assessing the significance of a particular input to the +fair value measurement in its entirety requires judgment, considering factors +specific to the asset or liability. The three levels of inputs that +may be used to measure fair value are defined as: +Level 1 – Quoted prices +(unadjusted) in active markets for identical assets or +liabilities. Instruments included in Level 1 consist of our commodity +derivatives for New York Mercantile Exchange (“NYMEX”)-based natural gas +swaps. +Level 2 – Inputs other than +quoted prices included within Level 1 that are either directly or indirectly +observable for the asset or liability, including (i) quoted prices for similar +assets or liabilities in active markets, (ii) quoted prices for identical or +similar assets or liabilities in inactive markets, (iii) inputs other than +quoted prices that are observable for the asset or liability and (iv) inputs +that are derived from observable market data by correlation or other +means. +Level 3 – Unobservable inputs +for the asset or liability, including situations where there is little, if any, +market activity for the asset or liability. Instruments included in +Level 3 consist of our commodity derivatives for Colorado Interstate Gas (“CIG”) +and Panhandle Eastern Pipeline (“PEPL”)-based natural gas swaps, oil swaps, +natural gas basis protection swaps, oil and natural gas options, and physical +sales and purchases. +F-18 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +The +following table presents, for each hierarchy level, our assets and liabilities, +including both current and non-current portions, measured at fair value on a +recurring basis as of December 31, 2008: +Level +1 +Level +3 +Total +(in +thousands) +Assets: +Commodity +based derivatives +$ +19,359 +$ +144,677 +$ +164,036 +Liabilities: +Commodity +based derivatives +(658 +) +(9,828 +) +(10,486 +) +Net +fair value of commodity based derivatives +$ +18,701 +$ +134,849 +$ +153,550 +The +following table sets forth a reconciliation of our Level 3 fair value +measurements: +Year +Ended +December 31, +2008 +(in +thousands) +Fair +value, net asset (liability), beginning of period +$ +(2,368 +) +Unrealized +gains (losses) included in statement of operations line +item: +Cost +of natural gas marketing activities +(1,079 +) +Unrealized +gains (losses) included in balance sheet line item: +Accounts +receivable - affiliates +821 +Accounts +payable - affiliates +35,338 +Purchases +Oil +and gas sales activities +105,214 +Sales +from natural gas marketing activities +438 +Cost +of natural gas marketing activities +(4,590 +) +Settlements +Oil +and gas sales activities +549 +Sales +from natural gas marketing activities +(129 +) +Cost +of natural gas marketing activities +655 +Fair +value, net asset (liability), end of period +$ +134,849 +Change +in unrealized gains (losses) relating to assets (liabilities) still held +as of December 31, 2008, included in statement of operations line +item: +Oil +and gas price risk management, net +$ +105,214 +Sales +from natural gas marketing activities +438 +Cost +of natural gas marketing activities +(5,669 +) +$ +99,983 +See Note 3 , Derivative Financial +Instruments , for additional disclosure related to our derivative +financial instruments. +Non-Derivative Financial Assets and +Liabilities . +The +carrying values of the financial instruments comprising cash and cash +equivalents, restricted cash, accounts receivable and accounts payable +approximate fair value due to the short-term maturities of these +instruments. +F-19 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +The +portion of our long-term debt related to our credit facility, approximates fair +value due to the variable nature of its related interest rate. We +estimate the fair value of the portion of our long-term debt related to our +senior notes to be approximately $127 million or approximately 62.5% of par +value as of December 31, 2008. We determined this valuation based +upon measurements of trading activity and quotes provided by brokers and traders +participating in the trading of the securities. +NOTE +3 – DERIVATIVE FINANCIAL INSTRUMENTS +We +are exposed to the effect of market fluctuations in the prices of oil and +natural gas as they relate to our oil and natural gas sales and natural gas +marketing segments. Price risk represents the potential risk of loss +from adverse changes in the market price of oil and natural gas +commodities. We employ established policies and procedures to manage +the risks associated with these market fluctuations using commodity +derivatives. Our policy prohibits the use of oil and natural gas +derivative instruments for speculative purposes. +Concentration of +Credit Risk . A significant portion of our +liquidity is concentrated in derivative instruments that enable us to manage a +portion of our exposure to price volatility from producing oil and natural +gas. These arrangements expose us to credit risk from our +counterparties. These contracts consist of fixed price swaps, basis +swaps and collars. We primarily use two investment grade financial +institutions as our counterparties to our derivative contracts who are also +major lenders in our credit facility arrangement. We have evaluated +the credit risk of our derivative assets from our counterparties using relevant +credit market default rates, giving consideration to amounts outstanding for +each counterparty and the duration of each outstanding derivative +position. Based on our evaluation, we have determined that the impact +of the nonperformance of our counterparties on the fair value of our derivative +instruments is insignificant. As of December 31, 2008, no +valuation allowance was recorded. +As of +December 31, 2008, the following counterparties expose us to credit +risk. +Fair +Value of Derivatives +As +of December 31, 2008 +Counterparty +Name +Assets +Liabilities +Net +(in +thousands) +JPMorgan +Chase Bank, N.A. +(1) +$ +83,291 +$ +(322 +) +$ +82,969 +BNP Paribas +(1) +79,316 +- +79,316 +Various +(2) +1,429 +(10,164 +) +(8,735 +) +Total +$ +164,036 +$ +(10,486 +) +$ +153,550 +(1) +Major lender in our credit facility, see Note 6. +(2) +Represents a total of 48 counterparties, includes two lenders in our +credit faciity. +Economic Hedging +Strategies . Our results of operations and operating cash flows +are affected by changes in market prices for oil and natural gas. To +mitigate a portion of the exposure to adverse market changes, we have entered +into various derivative contracts. As of December 31, 2008, our oil +and natural gas derivative instruments were comprised of futures, swaps, basis +protection swaps and collars. These instruments generally consist of +NYMEX-traded natural gas futures contracts and option contracts for Appalachian +and Michigan production, PEPL-based contracts for NECO production and CIG-based +contracts for other Colorado production and NYMEX-based crude oil swaps for our +Colorado oil production. +· +For +swap instruments, we receive a fixed price for the hedged commodity and +pay a floating market price to the counterparty. The +fixed-price payment and the floating-price payment are netted, resulting +in a net amount due to or from the +counterparty. +· +Basis +protection swaps are arrangements that guarantee a price differential for +natural gas from a specified delivery point. For CIG basis +protection swaps, which have negative differentials to NYMEX, we receive a +payment from the counterparty if the price differential is greater than +the stated terms of the contract and pay the counterparty if the price +differential is less than the stated terms of the +contract. +· +Collars +contain a fixed floor price (put) and ceiling price (call). If +the market price exceeds the call strike price or falls below the fixed +put strike price, we receive the fixed price and pay the market +price. If the market price is between the call and the put +strike price, no payments are due from either +party. +F-20 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +We +purchase puts and set collars and swaps for our own and affiliated partnerships’ +production to protect against price declines in future periods while retaining +much of the benefits of price increases. RNG enters into fixed-price +physical purchase and sale agreements that are derivative +contracts. In order to offset these fixed-price physical derivatives, +we enter into financial derivative instruments that have the effect of locking +in the prices we will receive or pay for the same volumes and period, offsetting +the physical derivative. While these derivatives are structured to +reduce our exposure to changes in price associated with the derivative +commodity, they also limit the benefit we might otherwise have received from +price changes in the physical market. We believe our derivative +instruments continue to be effective in achieving the risk management objectives +for which they were intended. +Validation +of a contract’s fair value is performed internally and while we use common +industry practices to develop our valuation techniques, changes in our pricing +methodologies or the underlying assumptions could result in significantly +different fair values. At December 31, 2008 and 2007, we had the +following open commodity based derivative instruments designed as an economic +hedge for a portion of our oil and natural gas production for periods after +December 2008: +Year +Ended December 31, +2008 +2007 +(in +thousands) +Derivative +net assets (liabilities) +Oil +and gas sales activities: +Fixed-price +natural gas swaps +$ +55,747 +$ +- +Natural +gas collars +50,752 +2,969 +Natural +gas basis protection swaps +(4,292 +) +- +Natural +gas floors +- +105 +Fixed-price +oil swaps +51,508 +(5,097 +) +153,715 +(2,023 +) +Natural +gas marketing activities: +Fixed-price +natural gas swaps +(159 +) +649 +Natural +gas basis protection swaps +(13 +) +- +Natural +gas collars +7 +- +(165 +) +649 +Estimated +net fair value of derivative instruments +$ +153,550 +$ +(1,374 +) +In +addition to including the gross assets and liabilities related to our share of +oil and gas production, the above table and our consolidated balance sheets +include the gross assets and liabilities related to derivative contracts we +entered into and those that we allocate to our affiliated partnerships as the +managing general partner. See Note 11 , Transactions with Affiliates , +for a discussion of our allocation methodology. For those derivative +contracts which we have allocated to the affiliated partnerships, we have on our +consolidated balance sheets a corresponding payable to and receivable from the +partnerships of $37.5 million and $1.6 million, respectively, as of December 31, +2008, and $1 million and $2.4 million as of December 31, 2007, +respectively. +F-21 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +The +following table identifies the fair value of commodity based derivatives as +classified in our consolidated balance sheets. +December +31, +2008 +2007 +(in +thousands) +Classification +in the Condensed Consolidated Balance Sheets: +Fair +value of derivatives - current asset +$ +116,881 +$ +4,817 +Other +assets - long-term asset +47,155 +193 +164,036 +5,010 +Fair +value of derivatives - current liability +4,766 +6,291 +Other +liabilities - long-term liability +5,720 +93 +10,486 +6,384 +Net +fair value of commodity based derivatives - asset +(liability) +$ +153,550 +$ +(1,374 +) +The +following changes in the fair value of commodity based derivatives are reflected +in our consolidated statements of operations. +Year +Ended December 31, +2008 +2007 +2006 +Statement +of operations line item +Realized +Unrealized +Realized +Unrealized +Realized +Unrealized +(in +thousands, gain/(loss)) +Oil +and gas price risk management gain (loss), net +(1) +$ +9,487 +$ +118,351 +$ +7,173 +$ +(4,417 +) +$ +1,895 +$ +7,252 +Sales +from natural gas marketing activities +(2) +(1,882 +) +4,614 +3,870 +(1,736 +) +2,592 +12,291 +Cost +of natural gas marketing activities +(2) +32 +(5,429 +) +(482 +) +1,511 +(1,908 +) +(11,923 +) +__________ +(1) +Includes +realized and unrealized gains and losses on commodity based derivative +instruments related to PDC. +(2) +Includes +realized and unrealized gains and losses on commodity based derivatives +instruments related to RNG only. +NOTE +4 – PROPERTIES AND EQUIPMENT +December +31, +2008 +2007 +(in +thousands) +Properties +and equipment, net: +Oil +and gas properties (successful efforts method of +accounting) +Proved +$ +1,245,316 +$ +953,904 +Unproved +32,768 +41,023 +Total +oil and gas properties +1,278,084 +994,927 +Pipelines +and related facilities +34,067 +22,408 +Transportation +and other equipment +31,693 +23,669 +Land +and buildings +14,570 +11,303 +Construction +in progress +(1) +275 +2,929 +1,358,689 +1,055,236 +Accumulated +DD&A +(325,611 +) +(209,372 +) +$ +1,033,078 +$ +845,864 +(1) At +December 31, 2007 includes costs primarily related to a new integrated oil and +gas financial software system. +F-22 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Suspended +Well Costs +The +following table identifies the capitalized exploratory well costs that are +pending the determination of proved reserves and included in oil and gas +properties on the consolidated balance sheets. +2008 +2007 +2006 +(in +thousands, except for number of wells) +Beginning +balance at January 1 +$ +2,300 +$ +765 +$ +1,918 +Additions +to capitalized exploratory well costs pending the determination of proved +reserves +15,644 +3,953 +12,016 +Reclassifications +to wells, facilities and equipment based on the determination of proved +reserves +(10,259 +) +(878 +) +(13,169 +) +Capitalized +exploratory well costs charged to expense +(6,505 +) +(1,540 +) +- +Ending +balance at December 31 +$ +1,180 +$ +2,300 +$ +765 +Number +of wells pending determination at December 31 +6 +3 +1 +As of +December 31, 2008, none of the wells awaiting the determination of proved +reserves have been capitalized for more than one year after the completion of +drilling. +NOTE +5 - INCOME TAXES +For each +of the years in the three-year period ended December 31, 2008, we utilized our +tax election to currently expense approximately $30 million, $44 million and $55 +million, respectively, of intangible drilling costs (“IDC”). This +election substantially reduced our current tax expense but resulted in a +correspondingly higher deferred tax expense as shown +below. Additionally, in 2006, we had a substantial taxable gain from +the sale of undeveloped oil and gas properties, see Note 13 , Sale of Oil and Gas +Properties . We have chosen to use the favorable deferral +aspects of the Internal Revenue Code (“IRC”) Section 1031 like-kind exchange +(“LKE”) rules to +defer the tax liability on a portion of the gain realized by purchasing +replacement properties, see Note 14 , Acquisitions . Accordingly, +our current and deferred provision for income taxes increased proportionately in +2006 due to the current and deferred tax associated with this large taxable +gain. The components of our tax expense consisted of the +following: +2008 +2007 +2006 +(in +thousands) +Current: +Federal +$ +6,198 +$ +7,579 +$ +54,467 +State +(3,818 +) +1,201 +8,739 +Total +current income taxes +2,380 +8,780 +63,206 +Deferred: +Federal +55,500 +11,074 +74,003 +State +3,579 +1,127 +12,428 +Total +deferred income taxes +59,079 +12,201 +86,431 +Total +income taxes +$ +61,459 +$ +20,981 +$ +149,637 +F-23 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Income +tax expense differed from the amounts computed by applying the U.S. federal +income tax rate of 35%. +2008 +2007 +2006 +(in +thousands) +Computed +"expected" tax +$ +61,169 +$ +18,966 +$ +135,594 +State +income tax, net +5,265 +1,907 +13,744 +Percentage +depletion +(1,150 +) +(624 +) +(545 +) +Domestic +production activities deduction +(249 +) +(374 +) +- +Other +(3,576 +) +1,106 +844 +$ +61,459 +$ +20,981 +$ +149,637 +In order +to reduce current income taxes payable, we elected to expense, for income tax +purposes, a large amount of IDC in each of the three years presented +above. This expensing election reduces our domestic production +activities deduction, which in 2008 and 2007 was statutorily equal to six +percent of our qualified production activity income (“QPAI”), to $0.7 million +and $1.1 million, respectively. In 2006, due to our decision to +expense $55 million of IDC, our domestic production deduction, which in 2006 was +statutorily equal to three percent of QPAI, was zero. In addition, +the amount in “Other” for 2008 was primarily for discrete tax benefit realized +upon the implementation of state tax strategies during the second and third +quarters. The amount in “Other” for 2007 was primarily nondeductible +tax penalties. +The +federal examination of our 2005 and 2006 tax returns is currently ongoing with +no significant adjustments noted as of December 31, 2008. +The tax +effects of temporary differences that give rise to significant portions of the +deferred tax assets and deferred tax liabilities at December 31, 2008 and 2007, +are presented below. +2008 +2007 +(in +thousands) +Deferred +tax assets: +Allowance +for doubtful accounts +$ +205 +$ +138 +Drilling +notes +27 +31 +Allowance +for lease impairment +4,910 +912 +Litigation +allowance +- +578 +Deferred +revenue related to cash withheld for future plugging +cost +1,043 +1,011 +Deferred +compensation +2,846 +2,058 +Asset +retirement obligations +8,519 +7,782 +Unrealized +loss - derivatives +- +703 +Employee +benefits +547 +456 +State +tax credit - carryforward +309 +- +Other +57 +16 +Total +gross deferred tax assets +18,463 +13,685 +Less +valuation allowance +- +- +Deferred +tax assets +18,463 +13,685 +Deferred +tax liabilities: +Properties +and equipment +(165,212 +) +(145,499 +) +Unrealized +gains - derivatives +(44,199 +) +(55 +) +Total +gross deferred tax liabilities +(209,411 +) +(145,554 +) +Net +deferred tax liability +$ +(190,948 +) +$ +(131,869 +) +Classification +in the Consolidated Balance Sheets: +Net +current deferred tax (liabilities) assets* +$ +(28,355 +) +$ +4,621 +Net +non-current deferred tax liability +(162,593 +) +(136,490 +) +Net +deferred tax liability +$ +(190,948 +) +$ +(131,869 +) +______________ +* +Included in other current assets on the consolidated balance +sheets. +F-24 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +As noted +above, deferred tax liabilities for properties and equipment increased in 2008 +and 2007, primarily as a result of our election to expense $30 million and $44 +million of IDC for income tax purposes. +In +assessing whether a valuation allowance for the deferred tax assets should be +recorded, we consider whether it is more likely than not that some portion or +all of the deferred tax assets will not be realized. The ultimate +realization of deferred tax assets is dependent upon the generation of future +taxable income during the periods in which those temporary differences become +deductible. Based upon the level of historical taxable income and +projections for future taxable income over the periods in which the deferred tax +assets are deductible, we believe it is more likely than not that we will +realize the benefits of these deductible differences. The amount of +the deferred tax asset considered realizable, however, could be reduced in the +near term if estimates of future taxable income during the carry-forward period +are reduced. +We +adopted the provisions of FIN No. 48 effective January 1, 2007. As a +result of adoption, retained earnings decreased by $0.3 million, deferred income +taxes payable decreased by $0.9 million, current income taxes payable increased +by $0.2 million and the liability for unrecognized tax benefit increased by $1 +million. +The +following table sets forth a reconciliation of the total amounts of unrecognized +tax benefits for 2008: +(in +thousands) +Balance, +December 31, 2007 +$ +888 +Gross +increases for tax positions of prior years +216 +Gross +increases for tax positions of current year +167 +Balance, +December 31, 2008 +$ +1,271 +Interest +and penalties related to uncertain tax positions are recognized in income tax +expense. As of January 1, 2008, and December 31, 2008, we have +approximately $0.1 and $0.3 million of accrued interest related to uncertain tax +positions, respectively. In addition, at December 31, 2008, $0.3 +million of income tax penalties were accrued compared to $0.2 million accrued at +January 1, 2008. The total amount of unrecognized tax benefits that +would affect the effective tax rate, if recognized, is $0.9 million as of +December 31, 2008 and $0.5 million as of January 1, 2008. We expect +the unrecognized tax benefit at December 31, 2008, to decrease in the next +twelve months because of the ongoing IRS examination of our 2005 and 2006 tax +years that will be finalized in 2009. It is currently estimated that +the decrease in our unrecognized tax benefits during the next year will be +approximately $0.8 million. +The +statute of limitations for tax years 2004-2007 remains open for both federal and +state taxing jurisdictions. However, due to the July 31, +2007, completion date of the federal examination of our 2003 and 2004 tax years, +we believe that certain tax positions related to these tax years have been +“effectively settled” for federal tax purposes. Additionally, for the +majority of our state tax jurisdictions, the statute of limitations for the 2003 +tax year remains open at December 31, 2008. +Our +subsidiary, Unioil Inc., which was acquired on December 6, 2006, filed separate +tax returns for years prior to the acquisition date. Unioil’s +2003-2006 tax returns remain open to examination at December 31, +2008. Any unrecognized tax benefit associated with Unioil's tax +returns is included in the above table amount. +NOTE +6 - LONG-TERM DEBT +December +31, +2008 +2007 +(in +thousands) +Credit +facility +$ +194,500 +$ +235,000 +12% +Senior notes due 2018, net of discount of $2.6 million +200,367 +- +Total +long-term debt +$ +394,867 +$ +235,000 +F-25 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Credit +facility +We have a +credit facility co-arranged by JPMorgan Chase Bank, N.A. ("JPMorgan") and BNP +Paribas, as amended last on November 12, 2008, dated as of November 4, 2005, +with an available commitment of $375 million as of December 31, +2008. The credit facility, through a series of amendments, includes +commitments from: Wachovia Bank N.A.; Bank of America, N.A.; Bank of Oklahoma; +Allied Irish Banks p.l.c.; Guaranty Bank, FSB; Royal Bank of Canada; The Royal +Bank of Scotland, plc; Calyon New York Branch; Compass Bank; The Bank of Nova +Scotia; and BMO Capital Markets Financing, Inc. The maximum allowable +commitment under the current credit facility is $400 million. The +credit facility is subject to and secured by required levels of oil and natural +gas reserves. The credit facility requires an aggregated security of +a value no less than 80% of the value of the direct interests included in the +borrowing base properties. Our credit facility borrowing base is +subject to size redeterminations each April and October based upon a +quantification of our reserves at December 31st and +June 30th, respectively. A commodity price deck reflective of the +current and future commodity pricing environment, as agreed upon by us and our +lenders, is utilized to quantify our reserve reports and determine the +underlying borrowing base. +We are +required to pay a commitment fee of .5% per annum on the unused portion of the +activated credit facility. Interest accrues at an alternative base +rate ("ABR") or adjusted LIBOR at our discretion. The ABR is the +greater of JPMorgan's prime rate, an adjusted secondary market rate for a +three-month certificate of deposit plus 1% or the federal funds effective rate +plus .5%. ABR borrowings are assessed an additional margin spread up +to 1.375% and adjusted LIBOR borrowings are assessed an additional margin spread +of 1.625% to 2.375% based upon the outstanding balance as a percentage of the +available balance. The credit agreement requires, among other things, +the maintenance of certain working capital and tangible net worth +ratios. No principal payments are required until the credit agreement +expires on November 4, 2010. +The +credit facility contains covenants customary for agreements of this type, +including, but not limited to, limitations on our ability to: (a) incur +additional indebtedness and guarantees, (b) create liens and other encumbrances +on our assets, (c) consolidate, merge or sell assets, (d) pay dividends and +other distributions, (e) make certain investments, loans and advances, (f) enter +into sale/leaseback transactions, (g) enter into transactions with our +affiliates, (h) change the character of our business, (i) engage in hedging +activities unless certain requirements are satisfied, (j) issue certain types of +stock, and (k) make certain amendments to our organizational +documents. The credit facility also requires us to execute and +deliver specified mortgages and other evidences of security and to deliver +specified opinions of counsel and other evidences of title. In +addition, we are required to comply with certain financial tests and maintain +certain financial ratios. The financial tests and ratios include requirements +to: (a) maintain a minimum ratio of consolidated current assets to consolidated +current liabilities, or working capital ratio, and (b) not to exceed a maximum +leverage ratio. +As of +December 31, 2008, we had drawn $194.5 million from our credit facility compared +to $235 million as of December 31, 2007. The borrowing rate on the +outstanding balance was 4.6% as of December 31, 2008 compared to 7.1% as of +December 31, 2007. Amounts outstanding under our credit facility are +secured by substantially all of our properties. We were in compliance +with all covenants at December 31, 2008, and expect to remain in compliance +throughout 2009. +12% +Senior Notes Due 2018 +Our +outstanding 12% senior notes were issued on February 8, 2008. The +principal amount of the senior notes is $203 million, which is payable at +maturity on February 15, 2018. Interest is payable in cash +semi-annually in arrears on each February 15 and August 15. The +senior notes were issued at a price of 98.572% of the principal +amount. In addition, $5.4 million in costs associated with the +issuance of the debt has been capitalized as a deferred loan +cost. The original discount and the deferred loan costs are being +amortized to interest expense over the term of the debt using the effective +interest method. As a result of recent negative global financial +market conditions, we estimate that the fair value of the senior notes was +approximately $127 million or approximately 62.5% of par. We +determined this valuation based upon measurements of trading activity and quotes +provided by brokers and traders participating in the trading of the +securities. +The +indenture governing the notes contains customary representations and warranties +as well as typical restrictive covenants that, among other things, limit our +ability and the ability of our restricted subsidiaries to: (a) incur additional +debt, (b) make certain investments or pay dividends or distributions on our +capital stock or purchase or redeem or retire capital stock, (c) sell assets, +including capital stock of our restricted subsidiaries, (d) pay dividends or +other payments by restricted subsidiaries, (e) create liens that secure debt, +(f) enter into transactions with affiliates, and (g) merge or consolidate with +another company. Additionally, we are subject to two incurrence +covenants: 1) earnings before interest, taxes, depreciation, amortization and +capital expenditures (“EBITDAX”) of at least two times interest expense and 2) +total debt of less than 4.0 times EBITDAX. As of December 31, 2008, +our EBITDAX was 8.3 times interest expense and total debt was 1.8 time +EBITDAX. We were in compliance with all covenants as of December 31, +2008, and expect to remain in compliance throughout 2009. +The notes +are senior unsecured obligations and rank, in right of payment, equally with all +of our existing and future senior unsecured indebtedness and senior to any of +our existing and future subordinated indebtedness. The notes are +effectively subordinated to any of our existing or future secured indebtedness +to the extent of the assets securing such indebtedness. +F-26 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +The notes +are not initially guaranteed by any of our subsidiaries. However, +subsidiaries may be obligated to guarantee the notes if: +• a +subsidiary is a guarantor under our senior credit facility; and +• the +subsidiary has consolidated tangible assets that constitute 10% or more of our +consolidated tangible assets. +Subject +to specified exceptions, any subsidiary guarantor will be restricted from +entering into certain transactions including the disposition of all or +substantially all of its assets or merging with or into another +entity. Subsidiary guarantors may be released from a guarantee under +circumstances specified in the indenture. As of December 31, 2008, +none of our subsidiaries were obligated as guarantors of our senior +notes. +The +indenture provides that at any time, which may be more than once, before +February 15, 2011, we may redeem up to 35% of the outstanding notes with +proceeds from one or more equity offerings at a redemption price of 112% of the +principal amount of the notes redeemed, plus accrued and unpaid interest, as +long as: +• +at +least 65% of the aggregate principal amount of the notes issued on +February 8, 2008, remains outstanding after each such redemption; +and +• +the redemption occurs within 180 days after the closing of the equity +offering. +The notes +also provide that we may, at our option, redeem all or part of the notes, at any +time prior to February 15, 2013, at the make-whole price set forth in the +indenture, and on or after February 15, 2013, at fixed redemption prices, plus +accrued and unpaid interest, if any, to the date of +redemption. Further, the indenture provides that upon a change of +control, we must give holders of the notes the opportunity to put their notes to +us for repurchase at a repurchase price of 101% of the principal amount, plus +accrued and unpaid interest. +In +connection with the issuance of the notes, we entered into a registration rights +agreement with the initial purchasers in which we agreed to file a registration +statement with the SEC related to an offer to exchange the notes for other +freely tradable notes and to use commercially reasonable efforts to cause the +registration statement to become effective on or prior to February 7, +2009. On April 24, 2008, we filed the related registration statement +on Form S-4. The registration statement was declared effective May +23, 2008. +NOTE +7 - ASSET RETIREMENT OBLIGATIONS +Changes +in carrying amounts of the asset retirement obligations associated with our +working interest in oil and gas properties are as follows: +2008 +2007 +(in +thousands) +Balance +at beginning of year +$ +20,781 +$ +11,966 +Obligations +assumed with development activities and acquisitions +1,189 +7,909 +Obligations +discharged with disposed properties and asset retirements +(114 +) +(93 +) +Accretion +expense +1,230 +999 +Balance +at end of year +$ +23,086 +$ +20,781 +If the +fair value of the estimated asset retirement obligation changes, an adjustment +is recorded to both the asset retirement obligation and the asset retirement +cost. Approximately $0.1 million of the asset retirement obligations +were classified as short-term and included in other accrued expenses as of +December 31, 2008 and 2007. +F-27 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +NOTE +8 - COMMITMENTS AND CONTINGENCIES +Drilling and Development +Agreements . We are a party to a pipeline expansion agreement +with an unrelated third party, which is also currently the purchaser of the +majority of our Wattenberg Field natural gas production. Pursuant to +the agreement, we have agreed to invest a minimum of $65 million to develop +specified acreage in the Wattenberg Field, during a three-year period ending +December 31, 2009. Such capital spending will include costs to drill +new wells and the cost to recomplete existing wells in this +area. Should we not meet the minimum commitment by December 31, 2009, +we will be required to pay liquidated damages of $2 million, prorated based on +our actual capital investment made to date. As of December 31, 2008, +our total capital expenditures pursuant to the agreement were $61.3 million, +resulting in a maximum potential liquidating damages charge of $0.1 +million. +In +connection with the acquisition of oil and gas properties in October 2007 from +an unaffiliated party, we are obligated to drill 100 wells in the Appalachian +Basin by January 2016. We will retain a majority interest in each +well drilled. For each well we fail to drill, we are obligated to pay +to the seller liquidated damages of $25,000 per undrilled well for a total +contingent obligation of $2.5 million or reassign to the seller the interest +acquired in the number of undrilled well locations. As of December +31, 2008, we have drilled 28 wells pursuant to this agreement. +We have +entered into contracts that provide firm transportation, sales and processing +charges on pipeline systems which we transport or sale our natural gas and the +natural gas of other companies, working interest owners and our affiliated +partnerships. The remaining terms of the contracts range from two to +14 years and require us to pay these transportation and processing charges +regardless if the required volumes are delivered or not. The table +below represents our gross future minimum firm transportation, sales and +processing charges as of December 31, 2008, for the periods +indicated. We will record in our financial statements only our share +based upon our working and net revenue interest in the wells. +Year +(in +thousands) +2009 +$ +8,391 +2010 +19,047 +2011 +18,443 +2012 +25,071 +2013 +25,262 +Thereafter +121,281 +$ +217,495 +In +September 2008, we entered into a pipeline and processing plants expansion +agreement with an unrelated party, which is currently the purchaser of the +majority of our Wattenberg Field natural gas production. Pursuant to +the agreement, we have agreed to make a capital investment of $60 million, for +our own benefit, over a three-year period commencing on January 1, 2009, to +develop or facilitate production in our Wattenberg Field dedicated to this +purchaser. If the purchaser fails to complete the pipeline and +processing plants in accordance with the agreement, then the agreement +effectively terminates. The agreement also provides for certain +volume commitments to be obtained by December 31, 2012. Qualifying +capital expenditures include the cost to drill new wells and the cost to +recomplete existing wells in this area. Failure to meet our drilling +commitment would result in a maximum payment to the counterparty of $15 million +in 2012; failure to meet our volume delivery commitment by December 31, 2012, +would result in a maximum payment to the counterparty of $10 million in +2013. +Partnership Repurchase +Provision . Substantially all of our drilling programs contain +a repurchase provision where investing partners may request that we purchase +their partnership units at any time beginning with the third anniversary of the +first cash distribution. The provision provides that we are obligated +to purchase an aggregate of 10% of the initial subscriptions per calendar year +(at a minimum price of four times the most recent 12 months' cash +distributions), if repurchase is requested by investors, and subject to our +financial ability to do so. The maximum annual repurchase obligation +as of December 31, 2008, was approximately $15.9 million. We have +adequate liquidity to meet this obligation. During 2008 and 2007, we +paid $1.8 million and $1.6 million, respectively, under this provision for the +repurchase of partnership units. As of December 31, 2008, outstanding +repurchase offers to investing partners totaled $0.7 million, of which $0.2 +million were consummated in 2009 prior to expiration. +Performance +Supplements . Our drilling programs formed from 1996 through +the second quarter of 2005 contain a performance supplement that provides for +changes in the distribution of partnership profits if certain levels of +performance are not met. The terms of this provision in the +partnership agreements are not a guarantee of a rate of return on an investment +in the partnership. Under those specific conditions, such changes can +result in our share of an affected partnership’s profits being reduced by up to +one half of the amount to which we otherwise would be entitled in the affected +period. In no event would we be obligated to assume a +disproportionate share of losses in such partnerships; should the partnerships +that contain this provision in the partnership agreements incur a loss, our +share of such losses would be unaffected by the terms of this +provision. In accordance with these provisions, our share of +partnership profits was reduced by an aggregate of $1 million, $0.6 million, and +$1 million during 2008, 2007and 2006, respectively. As of December +31, 2008 and 2007, based on production through December 31 of the corresponding +year, we had accrued $0.3 million and $0.2 million, respectively. +Partnership Casualty +Losses. As Managing General Partner of 33 partnerships, we +have liability for any potential casualty losses in excess of the partnership +assets and insurance. We believe the casualty insurance coverage that +we and our subcontractors carry is adequate to meet this potential +liability. +Drilling Rig +Contracts. In order to secure the services for drilling rigs, +we made commitments to the drilling contractors, which call for a minimum +commitment of $12,500 daily for a specified amount of time if we cease to use +the drilling rigs and a maximum commitment of $40,680 daily for a specified +amount of time for daily use of the drilling rigs. As of December 31, +2008, commitments for these two separate contracts expire in August 2009 and +July 2010. As of December 31, 2008, we have an outstanding minimum +commitment for $4.2 million and an outstanding maximum commitment for $15.9 +million, which includes $5.1 million related to a rig sublet to a third party +and remains our obligation should the third party default on terms of the sublet +agreement. +F-28 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Litigation . +Colorado +royalty . On May 29, 2007, Glen Droegemueller, individually and +as representative plaintiff on behalf of all others similarly situated, filed a +class action complaint against the Company in the District Court, Weld County, +Colorado alleging that we underpaid royalties on natural gas produced from wells +operated by us in parts of the State of Colorado (the “Droegemueller +Action”). The plaintiff sought declaratory relief and to recover an +unspecified amount of compensation for underpayment of royalties paid by us +pursuant to leases. We removed the case to Federal Court on June 28, +2007. On October 10, 2008, the court preliminarily approved a +settlement agreement between the plaintiffs and the Company, on behalf of itself +and the partnerships for which the Company is the managing general +partner. Based on the settlement terms, the settlement amount payable +by the Company is $5.8 million. Such moneys, in addition to moneys +related to the settlement on behalf of the partnerships for which the Company is +the managing general partner, were deposited in an escrow account on November 3, +2008. We have accrued as of December 31, 2008, and included in other +accrued expenses in our consolidated balance sheets, a related $5.8 million +litigation reserve. We believe that the amount accrued is adequate to +satisfy this obligation. Notice of the settlement was mailed to +members of the class action suit in the fourth quarter of 2008. The +final settlement approval hearing is expected on April 7, 2009. +See Note 17 , Subsequent Events , regarding +two West Virginia royalty lawsuits filed in January 2009. +Colorado Stormwater +Permit . On December 8, 2008, we received a Notice of Violation +/Cease and Desist Order (the “Notice”) from the Colorado Department of Public +Health, related to the stormwater permit for the Garden Gulch +Road. The Company manages this private road for Garden Gulch +LLC. The Company is one of four equal owners of Garden Gulch LLC, all +of which are oil and gas companies operating in the Piceance region of +Colorado. The Notice alleges a deficient and/or incomplete stormwater +management plan, failure to implement best management practices and failure to +conduct required permit inspections. The Notice requires corrective +action and states that the recipient shall cease and desist such alleged +violations. The Notice states that a violation could result in civil +penalties up to $10,000 per day. The Company’s initial response was +submitted on February 6, 2009. No civil penalties have been imposed +or requested at this time. Given the preliminary stage of this +proceeding and the inherent uncertainty in litigation, the Company is unable to +predict the ultimate outcome of this suit at this time. +We are +involved in various other legal proceedings that we consider normal to our +business. Although the results cannot be known with certainty, we +believe that the ultimate results of such proceedings will not have a material +adverse effect on our financial position or results of operations. +Employment Agreements with Executive +Officers . We have employment agreements with our Chief +Executive Officer, Chief Financial Officer, Chief Accounting Officer and other +executive officers. The employment agreements provide for annual base +salaries, eligibility for performance bonus compensation, and other various +benefits, including retirement and termination benefits. +In the +event of termination without cause or if an executive officer terminates +employment for good reason, which includes a change in control, the executive +officer is entitled to receive a payment in the amount up to three times the sum +of his highest base salary during the previous two years of employment +immediately preceding the termination date and his highest bonus received during +the same two year period. The executive officer is also entitled to +(i) vesting of any unvested equity compensation, (ii) reimbursement for any +unpaid expenses, (iii) retirement benefits earned under the current and/or +previous agreements, (iv) continued coverage under our medical plan for up to 18 +months, and (v) payment of any earned and unpaid bonus amounts. In +addition, the executive officer is entitled to receive any benefits that he +would have otherwise been entitled to receive under our 401(k) and profit +sharing plan, although those benefits are not increased or +accelerated. +In the +event that an executive officer is terminated for just cause, we are required to +pay the executive officer his base salary through the termination date plus any +bonus (only for periods completed and accrued, but not paid), incentive, +deferred, retirement or other compensation, and to provide any other benefits, +which have been earned or become payable as of the termination date but which +have not yet been paid or provided. +In the +event that an executive officer voluntarily terminates his employment for other +than good reason, he is entitled to receive (i) his base salary, bonus and +incremental retirement payment prorated for the portion of the year that the +executive officer is employed, (ii) any incentive, deferred or other +compensation which has been earned or has become payable, but which has not yet +been paid under the schedule originally contemplated in the agreement under +which they were granted or in full without discount within 60 days of the +termination date at our discretion, (iii) any unpaid expense reimbursement upon +presentation by the executive officer of an accounting of such expenses in +accordance with our normal practices, and (iv) any other payments for benefits +earned under the employment agreement or our plans. +F-29 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +In the +event of death or disability, the executive is entitled to receive (i) his base +salary and bonus for the portion of the year the executive officer is employed; +(ii) the base salary that would have been earned for six months after +termination; (iii) immediate vesting of all equity and option awards; (iv) the +payment of deferred retirement compensation based upon the schedule originally +contemplated in the deferred retirement compensation agreement or in a lump-sum +no later than two and one-half months following the close of the calendar year +in which the death or disability occurred; (v) reimbursement for any unpaid +expenses; (vi) and benefits earned under the 401(k) and profit sharing plan; and +(vii) continued coverage under our medical plan for up to 18 +months. +Derivative +Contracts . We would be exposed to oil and natural gas price +fluctuations on underlying purchase and sale contracts should the counterparties +to our derivative instruments or the counterparties to our gas marketing +contracts not perform. Nonperformance is not +anticipated. There were no counterparty default losses in 2008, 2007 +or 2006. +NOTE +9 - COMMON STOCK +Stock-Based +Compensation Plans +As +approved by the shareholders in June 2004, we maintain a long-term equity +compensation plan for our officers and certain key employees (the “2004 +Plan”). In accordance with the plan, awards may be issued in the form +of stock options, stock appreciation rights, restricted stock or performance +shares. A total of 750,000 new shares of common stock have been +reserved for issuance. Awards pursuant to the plan vest over periods +set at the discretion of the Compensation Committee of our Board of Directors +(“Board”) and have a maximum exercisable period of ten years. As of +December 31, 2008, 312,418 common shares remain available for future +awards. +As +approved by the shareholders, we also maintain a restricted stock plan for +non-employee directors. A total of 100,000 new shares of common stock +have been reserved for issuance under the plan. During 2008, 2007 and +2006, 14,000, 12,710 and 6,551 common shares, respectively, were awarded in +accordance with the plan. Compensation expense for each of the years +ended December 31, 2008, 2007 and 2006, related to these restricted shares was +$1 million, $0.2 million and $0.1 million, respectively. As of +December 31, 2008, 59,844 common shares remain available for future +awards. +In August +1999, the shareholders approved the 1999 Incentive Stock Option and +Non-Qualified Stock Option Plan. A total of 500,000 shares of our +common stock were reserved for issuance upon the exercise of stock +options. All shares authorized to be awarded pursuant to this plan +were awarded in years prior to 2002. As of December 31, 2007, options +for 11,000 common shares remained outstanding and exercisable; in 2008, +these outstanding options were exercised. +The +following table provides a summary of the effect of our stock based compensation +plans on the results of operations for the periods presented. +Year +Ended December 31, +2008 +2007 +2006 +(in +thousands) +Total +stock-based compensation expense (1) +$ +6,702 +$ +2,286 +$ +1,516 +Income +tax benefit +(2,557 +) +(882 +) +(585 +) +Net +income impact +$ +4,145 +$ +1,404 +$ +931 +______________ +(1) 2008 +includes $1.1 million related to a separation agreement with our former +president and $1.5 million related to a retirement agreement with our former +chief executive officer. +Stock Option +Awards. As of December 31, 2008, all outstanding stock options +were issued pursuant to our 2004 Plan. Outstanding options expire ten +years from the date of grant and become vested and exercisable ratably over a +four year period. We have not granted any new stock option awards +since 2006. In 2008, pursuant to a separation agreement with our +former president and an agreement with our former chief executive officer, we +modified options to purchase 9,905 shares by accelerating the vesting schedule, +none of which would have vested pursuant to the original terms of the +award. The incremental change in fair value per share of the modified +awards was immaterial. The fair value of options modified in 2008 and +granted in 2006, were estimated at the date of modification or grant using a +Black-Scholes option-pricing model assuming no dividends and the following +weighted average assumptions, with the exception of 4,678 shares in 2008, which +were estimated to approximate fair value on the date of modification due to the +short-term nature of the award: +F-30 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Year +Ended December 31, +2008 +2006 +Expected +volatility +43.0% +40.4% +Expected +term (in years) +- +6.0 +Risk-free +interest rate +1.6% +4.2% +Weighted-average +grant date fair value per share +$ +18.03 +$ +20.30 +Expected +volatilities are based on our historical volatility. The expected +life of an award is estimated using historical exercise behavior +data. The risk-free interest rate is based on the U.S. Treasury +yields in effect at the time of grant and extrapolated to approximate the +expected life of the award. We do not expect to pay dividends, nor do +we expect to declare dividends in the foreseeable future. +The +following table provides a summary of our stock option award activity for the +year ended December 31, 2008: +Weighted +Weighted +Average +Number +of +Average +Remaining +Shares +Exercise +Contractual +Underlying +Price +Term +Options +Per +Share +(years) +Outstanding +at December 31, 2007 +51,567 +$ +33.55 +6.4 +Modified +9,905 +43.03 +Exercised +(25,699 +) +24.41 +Forfeited +(17,422 +) +43.86 +Outstanding +at December 31, 2008 +18,351 +41.68 +6.8 +Vested +and expected to vest at December 31, 2008 +18,351 +41.68 +6.8 +Exercisable +at December 31, 2008 +12,736 +40.41 +6.6 +Year +Ended December 31, +2008 +2007 +2006 +(in +thousands, except market price) +Total +intrinsic value of options exercised +$ +659 +$ +1,691 +$ +281 +Total +intrinsic value of options outstanding +- +1,319 +1,984 +Total +intrinsic value of options exercisable +- +971 +1,934 +Market +price per common share as of December 31 +24.07 +59.13 +43.05 +The +intrinsic value of options exercised represents the amount by which the market +value of our stock at date of exercise exceeds the exercise price of the +option. The intrinsic values of the options outstanding and +exercisable represent the amount by which the closing market price of our common +stock at the last trading day of the year exceeds the exercise price of the +options. Total compensation cost related to stock options +granted under the 2004 Plan not yet recognized as of December 31, 2008, was $0.1 +million. This cost is expected to be recognized over a weighted +average period of 1.5 years. +F-31 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Restricted +Stock Awards +We have +issued restricted stock awards with vesting conditions that are either +time-based or market-based. +Time-Based +Awards . The fair value +of the time-based awards is amortized ratably over the requisite service period, +primarily over four years. Time-based awards for non-employee directors vest on +July 1 of the year following the date of grant. Total intrinsic value +is based upon the closing market price of our common stock on the last trading +date of the year. In 2008, pursuant to a separation agreement with +our former president and an agreement with our former chief executive officer, +we modified time-based awards to vest 25,027 shares by accelerating the vesting +schedule, none of which would have vested pursuant to the original terms of the +award, resulting in an increase in the original fair value of $0.4 +million. +The +following table sets forth the changes in non-vested time-based awards for the +year ended December 31, 2008: +Weighted +Average +Grant-Date +Shares +Fair +Value +Non-vested +at December 31, 2007 +201,845 +$ +37.97 +Granted/modified +161,982 +57.64 +Vested +(110,562 +) +34.59 +Forfeited +(35,205 +) +45.53 +Non-vested +at December 31, 2008 +218,060 +$ +52.59 +Year +Ended December 31, +2008 +2007 +2006 +(in +thousands, except market price) +Total +intrinsic value of time-based awards vested +$ +6,710 +$ +2,208 +$ +844 +Total +intrinsic value of time-based awards non-vested +5,249 +10,161 +5,671 +Market +price per common share as of December 31 +24.07 +59.13 +43.05 +Total +intrinsic value of time-based awards vested is based on the closing market price +of our common stock on the date of vest. Total intrinsic value of +time-based awards not yet vested is based on the closing market price of our +common stock on the last trading day of the year. The total +compensation cost related to non-vested time-based awards not yet recognized as +of December 31, 2008, was $8.8 million. This cost is expected to be +recognized over a weighted-average period of 2.9 years. +Market-Based +Awards . The fair value of the market-based awards is amortized +ratably over the requisite service period, primarily over three years for +market-based awards. The market-based shares vest only upon the +achievement of certain per share price thresholds and continuous employment +during the vesting period. All compensation cost related to the +market based-awards will be recognized if the requisite service period is +fulfilled, even if the market condition is not achieved. In 2008, +pursuant to a separation agreement with our former president, we modified +market-based awards to vest 1,539 shares by accelerating the vesting schedule, +none of which would have vested pursuant to the original terms of the award; +pursuant to an agreement with our former chief executive officer, we modified +market-based awards to vest 37,440 shares by accelerating the vesting +schedule, none of which would have vested, nor was expected to vest, pursuant to +the original terms of the award. The incremental change in fair value +per share of the modified awards was immaterial. +The +weighted average grant date fair value per market-based share, including shares +modified pursuant to an agreement with our former chief executive officer, was +computed using the Monte Carlo pricing model using the following weighted +average assumptions: +Year +Ended December 31, +2008 +2007 +Expected +term of award +3 +years +3 +years +Risk-free +interest rate +2.7% +4.7% +Volatility +45.6% +44.0% +Weighted +average grant date fair value per share +$ +43.61 +$ +36.07 +F-32 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +The +following table sets forth the changes in non-vested market-based awards for the +year ended December 31, 2008: +Weighted +Average +Grant-Date +Shares +Fair +Value +Non-vested +at December 31, 2007 +31,972 +$ +36.07 +Granted/modified +87,384 +43.61 +Vested +(3,078 +) +52.00 +Forfeited +(43,595 +) +40.81 +Non-vested +at December 31, 2008 +72,683 +$ +41.62 +The +intrinsic value of market-based awards not yet vested at December 31, 2008 and +2007, was $1.7 million and $1.9 million, respectively, based upon the closing +market price of our common stock on the last trading date of the year. The total +compensation cost related to non-vested market-based awards not yet recognized +as of December 31, 2008, is $1.4 million. This cost is expected to be +recognized over a weighted-average period of 1.1 years. +Treasury +Share Purchases +In +January 2006, we announced that our Board authorized the purchase of up to 10% +(1,627,500 shares) of our common stock during 2006. Stock purchases +under this program were made in the open market or in private transactions, at +times and in amounts that we deemed appropriate. In October 2006, we +completed our January 2006 program. Total shares purchased pursuant +to the program were 1,627,500 common shares at a cost of $66.3 million ($40.75 +average price paid per share), including 100,000 shares from one of our +executive officers at a cost of $4.1 million ($40.66 price paid per +share). All shares purchased in accordance with the program have +subsequently been retired. +On +October 16, 2006, our board of directors of approved a second 2006 purchase +program authorizing us to purchase up to 10% (1,477,109 shares) of our then +outstanding common stock through April 2008. Stock purchases under +this program were made in the open market or in private transactions, at times +and in amounts that we deem appropriate. There were 1,465,089 shares +that were authorized but not yet purchased as of December 31, +2007. Total shares purchased in 2008 pursuant to the program were +64,263 common shares at a cost of $4.4 million ($67.97 average price paid per +share), including 63,756 shares from our executive officers at a cost of $4.3 +million ($67.98 price paid per share). Shares purchased in 2008 +from employees, excluding executive officers, were generally purchased at fair +market value based on the closing price on the date of purchase and were +primarily purchased to satisfy the statutory minimum tax withholding requirement +for restricted stock that vested in 2008. Shares purchased from +executive officers in 2008 were primarily pursuant to a separation agreement +with our former president and to satisfy the statutory minimum tax withholding +requirements for shares vested in 2008. Shares purchased in prior +years were generally purchased at fair market value based on the closing price +on the date of purchase and were primarily purchased to satisfy the statutory +minimum tax withholding requirement for shares vesting in prior +years. The authorization to purchase the remaining 1,400,826 shares +effectively expired on April 30, 2008. All shares purchased in +accordance with the program have been subsequently retired. +Pursuant +to our senior notes indenture entered on February 8, 2008, any future purchases +are limited, see Note 6 , Long-Term Debt . +Shareholders’ Rights +Agreement +On +September 11, 2007, we entered into a rights agreement, with Transfer Online, +Inc., as rights agent. The rights agreement is designed to improve +the ability of our board of directors to protect the interest of our +shareholders in the event of an unsolicited takeover attempt. Our +Board declared a dividend of one right for each outstanding share of our common +stock. The right dividend was paid to shareholders of record on +September 14, 2007. A “distribution date,” as defined in the rights +agreement, can occur after any individual shareholder exceeds 15% ownership of +our outstanding common stock. After the occurrence of a “distribution +date,” the right entitles each registered holder (other than the acquiring +shareholder who triggered the “distribution date”), to purchase shares of our +common stock (or, in certain circumstances, cash, property or other securities) +having a then-current value equal to two times the exercise price of the right +(i.e., for the $240 exercise price, the rights holder receives $480 worth of +common stock). The exercise price is subject to adjustment for +various corporate actions which affect all shareholders, such as a stock +split. The rights agreement and all rights will expire on September +11, 2017. +F-33 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Common +and Preferred stock +Effective +July 17, 2008, pursuant to shareholder approval, we amended and restated our +Articles of Incorporation to: (1) increase the number of the Company's +authorized shares of common stock, par value $0.01, from 50,000,000 shares to +100,000,000 shares, and (2) authorize 50,000,000 shares of Company preferred +stock, par value $0.01, which may be issued in one or more series, with such +rights, preferences, privileges and restrictions as shall be fixed by our Board +of Directors from time to time. As of December 31, 2008, no preferred +stock had been issued. +NOTE +10 - EMPLOYEE BENEFIT PLANS +We +sponsor a qualified retirement plan covering substantially all of our +employees. The plan consists of a 401(k) component and a profit +sharing component. The 401(k) component enables eligible employees to +contribute a portion of their compensation through pre-tax payroll deductions in +accordance with specific guidelines. We provide a discretionary +matching contribution based on a percentage of the employees' contributions up +to certain limits. Our contribution to the profit sharing component +is discretionary. Our total combined expense for both 401(k) and +profit sharing in 2008, 2007 and 2006, was $1.9 million, $1.4 million and $3.1 +million, respectively. +We +provide a supplemental retirement benefit of deferred compensation under terms +of the various employment agreements with certain executive +officers. During 2008, 2007 and 2006, we charged $0.2 million, $0.4 +million and $0.3 million related to this plan to general and administrative +expenses, respectively, and we have recorded a related liability in the amount +$2.4 million and $2.2 million as of December 31, 2008 and 2007, +respectively. +In +addition to the supplemental retirement benefit of deferred compensation, we +offer a supplemental healthcare benefit covering certain executive officers and +their spouses in accordance with each officer's employment +agreement. Expense incurred during 2008 and 2007 related to this plan +was immaterial. As of December 31, 2008 and 2007, we had a recorded +liability of $0.6 million. +We +maintain a non-qualified deferred compensation plan for our non-employee +directors. The amount of compensation deferred by each participant is +based on participant elections. The amounts deferred pursuant to the +plan are invested in our common stock, maintained in a rabbi trust and are +classified in the balance sheet as treasury shares as a component of +shareholders' equity. The plan may be settled in either cash or +shares as requested by the participant. As of December 31, 2008 and +2007, we had recorded a long-term liability of $0.2 million and $0.3 million, +respectively, which is included in other liabilities in our consolidated balance +sheets. +NOTE +11 - TRANSACTIONS WITH AFFILIATES +Funds +held for future distribution on our consolidated balance sheets represent +amounts owed to affiliated partnerships and others for production proceeds +received by us on their behalf and undistributed as of December 31, 2008 and +2007. +Amounts +due from/to the affiliated partnership are primarily related to derivative +positions, unbilled well lease operating expenses, and costs resulting from +audit and tax preparation services. +We enter +into derivative instruments for our own production as well as for our 33 +affiliated partnerships’ production. We enter into these derivative +instruments for us and, as the managing general partner, for the affiliated +partnerships jointly by area of operation. Prior to September 30, +2008, as volumes produced changed, the allocation between us and the affiliated +partnerships changed. As of September 30, 2008, we fixed the +allocation of the derivative positions between us and each affiliated +partnership. Fixed quantities of each of the then existing positions +were allocated to us and the affiliated partnerships based upon current +estimated future production. For positions entered into subsequent to +September 30, 2008, specific designations of the quantities between us and the +affiliated partnerships are made at the time the positions are entered into +based on estimated future production. As of December 31, 2008, we +have recorded a payable to affiliates of $37.5 million representing their +allocated portion of the fair value of our gross derivative assets and a due +from affiliates of $1.6 million representing their allocated portion of the fair +value of our gross derivative liabilities. +Our +natural gas marketing segment manages the marketing of oil and natural gas for +our affiliated partnerships in the Appalachian Basin. Our sales from +natural gas marketing activities include $12.4 million, $9.3 million and $17.6 +million in 2008, 2007 and 2006, respectively, related to the marketing of oil +and natural gas on behalf of our affiliated partnerships. Included in +our cost of natural gas marketing activities is $12.1 million, $9.1 million and +$17.3 million for 2008, 2007 and 2006, respectively, related to these sales . +F-34 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +We +provided oil and gas well drilling services to our affiliated +partnerships. Pursuant to our cost-plus drilling arrangements and our +corresponding net presentation, we performed drilling services for our +affiliated partnerships totaling $68 million, $68.4 million and $87 million in +2008, 2007 and 2006, for which we recognized $7.6 million, $11.4 million and +$12.4 million in oil and gas well drilling operations revenue, +respectively. As part of the oil and gas well drilling services we +provide to our affiliated partnerships, we sell to them at cost the oil and gas +leases upon which the wells are drilled. For the years ended December +31, 2008, 2007 and 2006, we sold to our affiliated partnerships leases in the +amounts of $0.5 million, $1.4 million and $1.8 million, +respectively. Further, we provide well operations and pipeline +services to our affiliated partnerships. Substantially all of our +revenue and expenses related to oil and gas well drilling operations and +revenues from well operations and pipeline income are associated with services +provided to our affiliated partnerships. +Revenues +from oil and gas well drilling operations and costs of oil and gas well drilling +operations each include $0.1 million during 2006 related to investments made by +executive officers for working interests in wells drilled during in +2006. Amounts invested by the executive officers during 2007 were +immaterial. No amounts were invested by the executive officers during +2008. +Management +fees collected from the affiliated partnerships were $1.3 million in each of the +years 2007 and 2006. Management fees are included in other income on +our consolidated statements of operations. In 2008, we did not offer +a drilling partnership; therefore, no management fee was collected from an +affiliated partnership in 2008. +Through +our wholly-owned subsidiary, PDC Securities Incorporated, we act as +Dealer-Manager of the drilling partnerships. PDC Securities receives +the applicable commissions and marketing allowances from the Escrow Agent of the +drilling program and distributes them to the soliciting broker/dealers who sell +the programs. The commissions and marketing allowances received by +PDC Securities are included in other income net of the commissions distributed +to the soliciting broker/dealer. The commissions and marketing +allowances retained by PDC Securities were $0.5 million and $0.6 million and +those distributed to the soliciting broker/dealers amounted to $8.3 million and +$8.8 million for the years ended December 31, 2007 and 2006, +respectively. In 2008, we did not offer a drilling partnership; +therefore, no commissions and marketing allowances were received, distributed or +retained by PDC Securities. +NOTE +12 - LEASE OBLIGATIONS +We +have entered into operating leases principally for the leasing of natural gas +compressors, office space in Denver and Bridgeport, and general office +equipment. The future minimum lease payments under these +non-cancelable operating leases as of December 31, 2008, are as +follows: +Year +(in +thousands) +2009 +$ +2,687 +2010 +1,645 +2011 +1,081 +2012 +309 +2013 +74 +Thereafter +44 +$ +5,840 +Operating +lease expense for the years ended December 31, 2008, 2007 and 2006, was $2.5 +million, $1.5 million and $0.4 million, respectively. +NOTE +13 - SALE OF OIL AND GAS PROPERTIES +Grand +Valley Field Properties +In July +2006, we sold to an unaffiliated company a portion of our undeveloped leasehold +located in Grand Valley Field, Garfield County, Colorado. The sale +encompassed 100% of the working interest in approximately 8,700 acres, including +approximately 6,400 acres of the Chevron leasehold and 2,300 acres of the +Puckett Land Company leasehold. We retained approximately 475 +undeveloped locations on 10 acre spacing on the Grand Valley Field leasehold in +addition to all of our producing properties in the field. The +proceeds from the sale were $353.6 million. We recorded a gain on +sale of leaseholds of $328 million and a deferred gain on sale of leaseholds of +$25.6 million. +F-35 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Pursuant +to the purchase and sale agreement, we were obligated to either drill 16 wells +on specifically identified acreage over the next three years or pay liquidated +damages of $1.6 million per un-drilled well for a total contingent obligation of +$25.6 million, which was reflected as a deferred gain on sale of leaseholds on +the balance sheet as of December 31, 2006. In May 2007, we entered +into a letter agreement amending the original purchase and sale +agreement. The letter agreement relieved us of the obligation, in its +entirety, to either drill 16 wells or pay liquidated damages, resulting in the +recognition of the remaining $25.6 million deferred gain on sale of leaseholds +in the second quarter of 2007. Pursuant to the letter agreement, we +were obligated to drill six wells on specifically identified +acreage. As of December 31, 2007, we had drilled all six wells, which +were drilled on the unaffiliated party's leasehold for its benefit and at its +cost. +In +conjunction with the purchase and sale agreement described above, we entered +into a LKE agreement, in accordance with Section 1031 of the Internal Revenue +Code, with a “qualified intermediary.” Proceeds in the amount of $300 +million were transferred directly to the qualified intermediary to be held in +trust pursuant to the terms of the LKE agreement. We had until +mid-January 2007 to close any acquisition of suitable like-kind property, +allowing us to take advantage of the income tax deferral benefits of a LKE +transaction. +In +December 2007, we sold to the same unaffiliated party above a portion of our +North Dakota properties for approximately $34.7 million. The +properties, located in Dunn, Williams and McKenzie Counties, North Dakota, +include interests in five producing Bakken wells and approximately 72,000 net +undeveloped acres. The reduction in our production and proved +reserves as a result of this transaction is not material. We recorded +a gain on sale of leaseholds of $7.7 million in the fourth quarter of +2007. Following the sale, we retain ownership in three producing +wells in Dunn County, ten producing wells in Burke County and approximately +60,000 acres of undeveloped leasehold in Burke County. +NOTE +14 – ACQUISITIONS +2007 +Acquisitions +Acquisition +of Internal Revenue Code Section 1031 – Like-Kind Exchange +Properties +During +the first quarter of 2007, we completed the acquisition of suitable like-kind +properties in accordance with the LKE agreement we entered into in connection +with our sale of undeveloped leaseholds located in Grand Valley Field, Garfield +County, Colorado in July 2006. We acquired, for cash, qualifying oil +and gas properties totaling $188.9 million, including costs of acquisition, as +described below. +EXCO +Properties. On January 5, 2007, we completed the purchase of +producing properties and undeveloped drilling locations and acreage in the +Wattenberg Field of the DJ Basin, Colorado from EXCO Resources Inc., an +unaffiliated party. The acquisition included substantially all of +EXCO’s assets in the area and encompassed 144 oil and natural gas wells +(approximating 25.5 Bcfe proved developed reserves as of December 31, 2005) and +8,160 acres of leasehold interests. The wells and leases acquired are +located in Weld, Adams, Larimer, and Broomfield Counties, +Colorado. We operate the assets and hold a majority working interest +in the properties . +Company Sponsored +Partnerships . On January 10, 2007, we completed the purchase +of the remaining working interests in 44 of our sponsored +partnerships. The transaction resulted in an increase in our +ownership in 718 gross (423 net) wells that we currently operate. The +wells are located primarily in the Appalachian Basin and Michigan. +The +following table presents the adjusted purchase price for the like-kind exchange +property acquisitions described above as of December 31, 2007. +EXCO +Partnerships +(in +thousands) +Cash +consideration paid +$ +128,672 +$ +57,776 +Plus: +direct costs of acquisition +1,662 +1,664 +Less: +acquisition cost adjustments +(119 +) +(2,792 +) +Total acquisition +cost +$ +130,215 +$ +56,648 +F-36 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +The +following table presents, as of the respective date of acquisition, the final +allocations of the purchase prices based on estimates of fair +value. +EXCO +Partnerships +(in +thousands) +Current +assets acquired +$ +91 +$ +- +Proved +oil and gas properties +117,099 +59,081 +Unproved +oil and gas properties +14,960 +- +Asset +retirement obligation +(422 +) +(2,433 +) +Other +liabilities assumed +(1,513 +) +- +Total acquisition +cost +$ +130,215 +$ +56,648 +The +assessment of fair value of proved oil and gas properties acquired was based +primarily on projections of expected discounted future cash flows of acquired +oil and natural gas reserves. To compensate for the inherent risk of +estimating and valuing unproved properties, the discounted future net revenues +of probable reserves were reduced by additional risk-weighting factors in that +valuation. +Other. In January +2007, we acquired from unaffiliated parties other like-kind undeveloped +leaseholds in Erath County, Texas for $2.1 million, including costs of +acquisition. Acreage in this area is prospective for development of +oil and natural gas reserves in the Barnett Shale. +Other +Acquisitions +On +February 22, 2007, we acquired, from an unaffiliated party, 28 producing wells +and associated undeveloped acreage located in Colorado (Wattenberg Field) for a +purchase price of $12 million, which was allocated to oil and gas +properties. +On +October 30, 2007, with an effective date of October 1, 2007, we purchased from +unrelated parties, Castle Gas Company, et.al., a majority working interest in +762 natural gas wells located in southwestern Pennsylvania for approximately $54 +million. We estimated that the acquisition included approximately 47 +Bcfe of reserves, or 31 Bcfe of proved reserves and 16 Bcfe of unproved +reserves. The purchase also included associated pipelines, equipment, +real estate and undeveloped acreage. +The +following table presents the adjusted purchase price for the Castle acquisition +described above as of December 31, 2007. +(in +thousands) +Cash +consideration paid +$ +53,041 +Plus: +direct costs of acquisition +443 +Plus: +acquisition cost adjustments +583 +Total acquisition +cost +$ +54,067 +The +following table presents, as of the respective date of acquisition, the final +allocation of the purchase price based on estimates of fair value. +(in +thousands) +Current +assets acquired +$ +185 +Proved +oil and gas properties +55,778 +Unproved +oil and gas properties +217 +Real +estate and equipment, and other assets +2,115 +Non +current assets +783 +Asset +retirement obligation +(4,043 +) +Other +liabilities assumed +(968 +) +Total acquisition +cost +$ +54,067 +F-37 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +The +assessment of fair value of proved oil and gas properties acquired was based +primarily on projections of expected discounted future cash flows of acquired +oil and natural gas reserves. To compensate for the inherent risk of +estimating and valuing unproved properties, the discounted future net revenues +of probable reserves were reduced by additional risk-weighting factors in that +valuation. +Pro +Forma Financial Information +The +results of operations for all of the above acquisitions have been included in +our consolidated financial statements from the dates of +acquisition. The pro forma effect of the inclusion in our +consolidated statement of operations for the year ended December 31, 2007, of +the results of operations for the January and February 2007 acquisitions +described above, individually and in the aggregate, was not +material. +The +following unaudited pro forma financial information presents a summary of our +consolidated results of operations for the years ended December 31, 2007 and +2006, assuming the acquisitions of the EXCO properties, our sponsored +partnerships and the Castle properties had been completed as of January 1, 2006, +including adjustments to reflect the allocation of the purchase price to the +acquired net assets. The pro forma effect of the inclusion of the +results of operations for all of the other acquisitions described above, +individually and in the aggregate, was not material. +Year +Ended December 31, +2007 +2006 +(in +thousands, except per share data) +Total +revenues +$ +310,351 +$ +315,492 +Net +income +$ +34,571 +$ +243,105 +Earnings +per common share: +Basic +$ +2.34 +$ +15.52 +Diluted +$ +2.33 +$ +15.44 +The pro +forma results of operations are not necessarily indicative of what our results +of operations would have been had the EXCO properties, our sponsored +partnerships and the Castle properties been acquired at the beginning of the +periods indicated, nor does it purport to represent our results of operations +for any future periods. +2006 +Acquisitions +On +December 6, 2006, we completed a cash tender offer and purchased approximately +95.5% or 9,112,750 shares of the outstanding common stock of Unioil, an +independent energy company with properties in northern Colorado and southern +Wyoming. The acquisition of more than 90% of the outstanding shares +of common stock allowed us to effect a short-form merger of Unioil and one of +our wholly-owned subsidiaries, resulting in the acquisition of the remaining +428,719 shares of Unioil. Each share of Unioil common stock not +tendered through the offer was converted into the right to receive $1.91 in +cash, the same consideration paid for shares in the tender offer. The +total price paid for 100% of Unioil’s outstanding common stock was $18.6 +million, including $0.4 million in direct costs of the +acquisition. The final acquisition cost allocation as reflected on +our consolidated balance sheets as of December 31, 2007, included $25.8 million +in properties and equipment, current assets of $0.7 million, a deferred tax +liability of $6.8 million and other liabilities assumed of $1 +million. The pro forma effect of the inclusion of Unioil in our 2006 +results of operations was not material. +F-38 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +NOTE +15 – MAJOR CUSTOMERS +The +following table identifies sales to individual customers constituting 10% or +more of oil and natural gas sales, including natural gas sales by our natural +gas marketing activities segment, and total revenues. +Oil +and Gas Sales +Total +Revenues +Year +Ended December 31, +Year +Ended December 31, +2008 +2007 +2006 +2008 +2007 +2006 +Customer +Williams +Production RMT Company +16.3 +% +14.1 +% +8.7 +% +12.4 +% +12.9 +% +7.5 +% +Tepco +Crude Oil, LLC +14.3 +% +14.8 +% +14.9 +% +10.8 +% +13.5 +% +12.9 +% +DCP +Midstream, LP +8.8 +% +7.8 +% +10.6 +% +6.6 +% +7.1 +% +9.1 +% +Sempra +Energy Trading +5.4 +% +6.0 +% +10.3 +% +4.1 +% +5.5 +% +8.9 +% +NOTE +16 - BUSINESS SEGMENTS +We +separate our operating activities into four segments: oil and gas +sales, natural gas marketing, well operations and pipeline income and oil and +gas well drilling operations. All material inter-company accounts and +transactions between segments have been eliminated. +Oil and Gas Sales. Our +oil and gas sales segment represents revenues and expenses from the production +and sale of oil and natural gas. Segment revenue includes oil and gas +price risk management, net. Segment profit consists of oil and gas +sales revenues less its proportionate share of oil and gas production and well +operations cost, exploration expense, direct general and administrative expense +and DD&A expense. Segment DD&A expense was $100.2 million, +$68.1 million and $31.3 million in 2008, 2007 and 2006, +respectively. +Natural Gas Marketing +Activities. Our +natural gas marketing segment is composed of our wholly owned subsidiary, RNG, +through which we purchase, aggregate and resell natural gas produced by us and +others. Segment profit primarily represents sales from natural gas +marketing activities and direct interest income less costs of natural gas +marketing activities, direct general and administrative expense. +Well Operations and Pipeline +Income. We +charge our affiliated partnerships and other third parties competitive industry +rates for well operations and natural gas gathering. Segment revenue +includes monthly operating and gas gathering fees we charge for each well in +which we operate that is owned by others, including our sponsored +partnerships. Segment profit consists of well operations and pipeline +income revenues less its proportionate share of oil and gas production and well +operations cost and direct DD&A expense. Segment DD&A expense +was $1.9 million, $1.2 million and $1.9 million in 2008, 2007, 2006, +respectively. +Oil and Gas Well Drilling +Operations. We drill natural gas +wells for Company-sponsored drilling partnerships and retain an interest in each +well. Our drilling and development segment reflects results of drilling and +development activities conducted for affiliated and non-affiliated +parties. Segment profit consists of oil and gas well drilling +revenues less cost of oil and gas well drilling. +Other. This +segment includes unallocated corporate general administrative expense, direct +DD&A expense, direct interest income and interest expense. +F-39 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Segment +information for the years ended December 31, 2008, 2007 and 2006 is presented +below. +Year +Ended December 31, +2008 +2007 +2006 +Revenues: +(in +thousands) +Oil +and gas sales +$ +449,715 +$ +177,943 +$ +124,336 +Natural +gas marketing activities +140,263 +103,624 +131,326 +Well +operations and pipeline income +11,474 +9,342 +10,704 +Oil +and gas well drilling operations +7,615 +12,154 +17,917 +Unallocated +amounts +293 +2,172 +2,220 +Total +$ +609,360 +$ +305,235 +$ +286,503 +Segment +Income Before Income Taxes: +Oil +and gas sales +$ +231,885 +$ +42,068 +$ +61,868 +Natural +gas marketing activities +1,329 +3,822 +1,816 +Well +operations and pipeline income +3,933 +3,136 +2,823 +Oil +and gas well drilling operations +5,402 +9,646 +5,300 +Unallocated +amounts +(67,781 +) +(4,482 +) +315,602 +Total +$ +174,768 +$ +54,190 +$ +387,409 +Expenditures +for Segment Long-Lived Assets: +Oil +& gas sales +$ +309,395 +$ +226,801 +$ +133,401 +Natural +gas marketing activities +- +- +- +Well +operations and pipeline income +7,564 +6,715 +1,419 +Oil +and gas well drilling operations +- +- +- +Unallocated +amounts +6,194 +5,472 +12,125 +Total +$ +323,153 +$ +238,988 +$ +146,945 +As +of December 31, +Segment +Assets: +Oil +& gas sales +$ +1,247,687 +$ +862,237 +$ +394,952 +Natural +gas marketing activities +50,117 +40,269 +39,899 +Well +operations and pipeline income +50,052 +26,156 +28,895 +Oil +and gas well drilling operations +2,028 +4,959 +87,746 +Unallocated +amounts +52,820 +116,858 +332,795 +Total +$ +1,402,704 +$ +1,050,479 +$ +884,287 +NOTE +17 – SUBSEQUENT EVENTS +West +Virginia royalty litigation . On January 26, 2009, we received notice of a lawsuit +filed in West Virginia state court in Barbour County, Beymer +and Beymer v. Petroleum Development Corporation and Riley National Gas +Company , CA No. 09-C-3 (“Beymer lawsuit”) , alleging a class action for +failure to properly pay royalties. The allegations state that the +Company improperly deducted certain charges and costs before applying the +royalty percentage. Punitive damages are requested in addition to +breach of contract, tort, and fraud allegations. On February 25, +2009, we filed to remove the action to federal court. +On +January 30, 2009, the Company was served with another lawsuit alleging class +action related to royalty payments file in West Virginia state court in Harrison +County, Gobel, +Phares and Cather v. Petroleum Development Corporation , CA No. +09-40-2. West Virginia oil and gas production constitutes +approximately 8% of the Company’s current oil and gas sales. Given +the preliminary stage of these proceedings and the inherent uncertainty in +litigation, the Company is unable to predict the ultimate outcome of these suits +at this time. +F-40 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +NOTE +18 – SUPPLEMENTAL OIL AND GAS INFORMATION – UNAUDITED +Costs +Incurred in Oil and Gas Property Acquisition, Exploration and Development +Activities +We +incurred costs in oil and gas property acquisition, exploration and development +are presented below. +Year +Ended December 31, +2008 +2007 +2006 +(in +thousands) +Acquisition +of properties: +Proved +properties +$ +6,147 +$ +257,330 +$ +802 +Unproved +properties +6,890 +13,701 +11,926 +Development +costs +257,656 +194,031 +114,487 +Exploration +costs: +Exploratory +drilling +26,499 +12,972 +18,660 +Geological +and Geophysical +2,121 +6,299 +2,234 +Total +costs incurred +$ +299,313 +$ +484,333 +$ +148,109 +The +proved reserves attributable to the development costs in the above table were +125,198 MMcf and 2,354 MBbls for 2008, 216,383 MMcf +and 3,700 MBbls for 2007 and 64,126 MMcf and 2,955 MBbls for 2006. Of +the above development costs incurred for the years ended December 31, 2008, 2007 +and 2006, the amounts of $66.2 million, $37.1 million, and $20.1 million, +respectively, were incurred to develop proved undeveloped properties from the +prior year end. +Property +acquisition costs include costs incurred to purchase, lease or otherwise acquire +a property. Development costs include costs incurred to gain access +to and prepare development well locations for drilling, to drill and equip +development wells, recompletions and to provide facilities to extract, treat, +gather and store oil and gas. Exploration costs include costs +incurred in identifying areas that may warrant examination and in examining +specific areas that are considered to have prospects of containing oil and gas +reserves. +Capitalized +Oil and Gas Costs +Aggregate +capitalized costs for related to oil and gas exploration and production +activities with applicable accumulated depreciation, depletion and amortization +are presented below: +December +31, +2008 +2007 +(in +thousands) +Proved +oil and gas properties +$ +1,245,316 +$ +953,904 +Unproved +oil and gas properties +32,768 +41,023 +1,278,084 +994,927 +Less +accumulated depreciation, depletion and amortization +306,142 +196,310 +$ +971,942 +$ +798,617 +F-41 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Results +of Operations for Oil and Gas Producing Activities +The +results of operations for oil and gas producing activities, excluding natural +gas marketing activities, are presented below. +Year +Ended December 31, +2008 +2007 +2006 +(in +thousands) +Revenue: +Oil +and gas sales +$ +321,877 +$ +175,187 +$ +115,189 +Oil +and gas price risk management gain, net +127,838 +2,756 +9,147 +449,715 +177,943 +124,336 +Expenses: +Production +costs +72,518 +44,238 +20,855 +Depreciation, +depletion and amortization +100,207 +68,086 +30,988 +Exploration +costs +45,105 +23,551 +8,131 +217,830 +135,875 +59,974 +Results +of operations for oil and gas producing activities before provision for +income taxes +231,885 +42,068 +64,362 +Provision +for income taxes +86,493 +16,280 +24,818 +Results +of operations for oil and gas producing activities, excludes corporate +overhead and interest costs +$ +145,392 +$ +25,788 +$ +39,544 +Production +costs include those costs incurred to operate and maintain productive wells and +related equipment, including costs such as labor, repairs, maintenance, +materials, supplies, fuel consumed, insurance and production and severance +taxes. In addition, production costs include administrative expenses +and depreciation applicable to support equipment associated with these +activities. Depreciation, depletion and amortization expense includes those +costs associated with capitalized acquisition, exploration and development +costs, but does not include the depreciation applicable to support +equipment. The provision for income taxes is computed using effective +tax rates. +Net +Proved Oil and Gas Reserves +We +utilized the services of independent petroleum engineers to estimate our oil and +gas reserves. For the years ended December 31, 2008 and 2007, our +reserve estimates for the Appalachian and Michigan Basins are based on reserve +reports prepared by Wright & Company and for the Rocky Mountain Region, +reserve estimates are based on reserve reports prepared by Ryder Scott Company, +L.P. For the year ended December 31, 2006, our reserve estimates for +the Appalachian and Michigan Basins and NECO Area were based on reserve reports +prepared by Wright & Company and our reserve estimates for the Rocky +Mountain Region, with the exception of the NECO properties, were based on +reserve reports prepared by Ryder Scott. These reserve estimates have +been prepared in compliance with professional standards and the reserves +definitions prescribed by the SEC. +Proved +reserves are the estimated quantities of oil and natural gas that geologic and +engineering data demonstrate with reasonable certainty to be recoverable in +future years from known reservoirs under existing economic and operating +conditions. Estimates of proved reserves may change, either +positively or negatively, as additional information becomes available and as +contractual, economic and political conditions change. The Company's +net proved reserve estimates have been adjusted as necessary to reflect all +contractual agreements, royalty obligations and interests owned by others at the +time of the estimate. +Proved +developed reserves are the quantities of oil and natural gas expected to be +recovered through existing wells with existing equipment and operating +methods. In some cases, proved +undeveloped reserves may require substantial new investments in +additional wells and related facilities. +F-42 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +An +analysis of the change in estimated quantities of oil and gas reserves, all of +which are located within the U.S., is shown below. +Oil +(MBbl) +Gas +(MMcf) +Total +(MMcfe) +Proved +Reserves: +Proved +reserves, January 1, 2006 +4,538 +247,288 +274,516 +Revisions +of previous estimates +226 +(21,721 +) +(20,365 +) +Extensions, +discoveries and other additions +Michigan +Basin +- +225 +225 +Rocky +Mountain Region +2,955 +63,901 +81,631 +Purchases +of reserves +Appalachian +Basin +- +222 +222 +Michigan +Basin +- +35 +35 +Rocky +Mountain Region +276 +3,504 +5,160 +Dispositions +to partnerships +(92 +) +(1,215 +) +(1,767 +) +Production +(631 +) +(13,161 +) +(16,947 +) +Proved +reserves, December 31, 2006 +7,272 +279,078 +322,710 +Revisions +of previous estimates +1,375 +14,177 +22,427 +Extensions, +discoveries and other additions +Appalachian +Basin +- +5,493 +5,493 +Michigan +Basin +- +488 +488 +Rocky +Mountain Region +3,700 +210,402 +232,602 +Purchases +of reserves +Appalachian +Basin +2 +63,014 +63,026 +Michigan +Basin +- +6,059 +6,059 +Rocky +Mountain Region +4,490 +39,239 +66,179 +Dispositions +to partnerships +(591 +) +(1,874 +) +(5,420 +) +Production +(910 +) +(22,513 +) +(27,973 +) +Proved +reserves, December 31, 2007 +15,338 +593,563 +685,591 +Revisions +of previous estimates +(1,538 +) +(25,216 +) +(34,444 +) +Extensions, +discoveries and other additions +Appalachian +Basin +- +24,875 +24,875 +Rocky +Mountain Region +2,354 +100,323 +114,447 +Purchases +of reserves +Appalachian +Basin +- +83 +83 +Michigan +Basin +- +46 +46 +Rocky +Mountain Region +106 +1,712 +2,348 +Dispositions +to partnerships +(63 +) +(769 +) +(1,147 +) +Production +(1,160 +) +(31,760 +) +(38,720 +) +Proved +reserves, December 31, 2008 +15,037 +662,857 +753,079 +Proved +Developed Reserves (1) , +as of: +January +1, 2006 +2,848 +146,664 +163,752 +December +31, 2006 +3,503 +144,672 +165,690 +December +31, 2007 +5,219 +286,570 +317,884 +December +31, 2008 +5,438 +297,041 +329,669 +______________ +(1) +December +31, 2008, 2007, 2006, and January 1, 2006, reserve amounts reflect the +reclassification of our Rocky Mountain Region refrac and behind pipe +reserves of 75,863 MMcfe, 49,801 MMcfe, 21,062 MMcfe and 14,762 MMcfe, +respectively, from proved developed to proved +undeveloped. +F-43 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +2008 +Activity. In 2008, we +recorded a downward revision of our previous estimate of proved reserves of +approximately 34 Bcfe. The revision was primarily due to a decrease +of approximately 50 Bcfe due to lower commodity prices, 26 Bcfe due to increased +operating costs, and 15 Bcfe due to adjustments to proved undeveloped reserve +values, partially offset be an increase of 55 Bcfe due to asset +performance. New discoveries and extensions of 139 Bcfe in 2008 are +due to drilling of 229 net wells and the addition of new proved undeveloped +reserves. Approximately 25 Bcfe were added in the Appalachian Basin, +and approximately 114 Bcfe were added in the Rocky Mountain Region with 26 Bcfe +in the Wattenberg Field, 80 Bcfe in Grand Valley Field, and 8 Bcfe in the NECO +area. We acquired approximately 2 Bcfe of proved reserves through the +purchases of interest in some of our existing properties. We +primarily acquired reserves in the Wattenberg Field with the remaining reserves +being split between the Appalachian Basin, Michigan, Piceance, the NECO area and +North Dakota. We sold proved reserves of approximately 1 Bcfe to +unaffiliated third parties and to our sponsored partnerships for drilling +activity. +2007 Activity . In +2007, we recorded an upward revision to our previous estimate of proved reserves +of approximately 22 Bcfe. The revision was primarily due to an +increase of approximately 25 Bcfe and 12 Bcfe, respectively, due to asset +performance and higher commodity prices, partially offset by a decrease of +approximately 15 Bcfe due primarily to increased operating costs, adjustments to +proved undeveloped reserve values and change in well ownership +interests. New discoveries and extensions of 239 Bcfe in 2007 are due +to the drilling of 218 net wells and the addition of new proved undeveloped +reserves. Approximately 233 Bcfe were added in the Rocky Mountain +Region, with 43 Bcfe in the Wattenberg Field, 170 Bcfe in Grand Valley Field and +19 Bcfe in the NECO area. We acquired approximately 135 Bcfe of +proved reserves through purchases of oil and natural gas +properties. In the Rocky Mountain Region approximately 66 Bcfe of +proved reserves were acquired in the Wattenberg Field, in the Appalachian Basin +approximately 75 Bcfe were acquired and approximately 6 Bcfe in the Michigan +Basin. We sold proved reserves of approximately 5 Bcfe to +unaffiliated third parties and to our sponsored partnerships for drilling +activity. +2006 Activity. In +2006 we recorded a downward revision to our previous estimate of proved reserves +of approximately 20 Bcfe. The revision was primarily due to a +decrease of 3 Bcfe due to asset performance and a decrease of 10 Bcfe due to +lower commodity prices and a decrease of approximately 7 Bcfe due to changes in +proved undeveloped reserve value, operating expense, and well ownership +interests. New discoveries and extensions in 2006 of approximately 82 +Bcfe were primarily due to the drilling of 91 net wells and adding new proved +undeveloped reserves in the Rocky Mountain Region. Approximately 34 +Bcfe were added in Wattenberg Field, 33 Bcfe in Grand Valley Field and 12 Bcfe +in the NECO area. We acquired approximately 5 Bcfe of proved reserves +through purchases of oil and natural gas properties in Wattenberg +Field. We sold proved reserves of approximately 2 Bcfe to our +sponsored partnerships. +Standardized +Measure of Discounted Future Net Cash Flows and Changes Therein Relating to +Proved Oil and Gas Reserves +Summarized +in the following table is information with respect to the standardized measure +of discounted future net cash flows relating to proved oil and gas +reserves. Future cash inflows are computed by applying year-end +prices of oil and gas relating to our proved reserves to the year-end quantities +of those reserves. Future production, development, site restoration +and abandonment costs are derived based on current costs assuming continuation +of existing economic conditions. Future income tax expenses are +computed by applying the statutory rate in effect at the end of each year to the +future pretax net cash flows, less the tax basis of the properties and gives +effect to permanent differences, tax credits and allowances related to the +properties. +2008 +2007 +2006 +(in +thousands) +Future +estimated cash flows +$ +3,867,461 +$ +5,257,962 +$ +1,804,796 +Future +estimated production costs +(1,325,362 +) +(1,374,027 +) +(571,346 +) +Future +estimated development costs +(1,100,533 +) +(876,961 +) +(373,460 +) +Future +estimated income tax expense +(384,676 +) +(1,159,489 +) +(334,536 +) +Future +net cash flows +1,056,890 +1,847,485 +525,454 +10% +annual discount for estimated timing of cash flows +(700,085 +) +(1,094,414 +) +(309,792 +) +Standardized +measure of discounted future +estimated net cash flows +$ +356,805 +$ +753,071 +$ +215,662 +F-44 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +The +following table summarizes the principal sources of change in the standardized +measure of discounted future estimated net cash flows. +2008 +2007 +2006 +(in +thousands) +Sales +of oil and gas production net of production costs +$ +(261,692 +) +$ +(137,725 +) +$ +(94,337 +) +Net +changes in prices and production costs +(479,894 +) +157,797 +(301,132 +) +Extensions, +discoveries, and improved recovery, less related costs +80,859 +317,031 +46,109 +Sales +of reserves +(2,012 +) +(7,846 +) +(3,356 +) +Purchase +of reserves +4,280 +342,792 +11,003 +Development +costs incurred during the period +88,008 +42,510 +20,051 +Revisions +of previous quantity estimates +(79,536 +) +92,462 +(22,090 +) +Changes +in estimated income taxes +239,054 +(335,327 +) +120,818 +Accretion +of discount +122,409 +38,660 +62,838 +Timing +and other +Timing +(20,117 +) +27,055 +(29,672 +) +Net +changes in future development costs +(87,625 +) +- +- +Total +$ +(396,266 +) +$ +537,409 +$ +(189,768 +) +It is +necessary to emphasize that the data presented should not be viewed as +representing the expected cash flow from, or current value of, existing proved +reserves since the computations are based on a large number of estimates and +arbitrary assumptions. Reserve quantities cannot be measured with +precision and their estimation requires many judgmental determinations and +frequent revisions. The required projection of production and related +expenditures over time requires further estimates with respect to pipeline +availability, rates of demand and governmental control. Actual future +prices and costs are likely to be substantially different from the current +prices and costs utilized in the computation of reported amounts. Any +analysis or evaluation of the reported amounts should give specific recognition +to the computational methods utilized and the limitations inherent +therein. +The +estimated present value of future cash flows relating to proved reserves is +extremely sensitive to prices used at any measurement period. The +average December 31 price used for each commodity at December 31, 2008, 2007 and +2006 is presented below. +Average +Price +As +of December 31, +Oil +Gas +2008 +$ +37.85 +$ +4.98 +2007 +80.67 +6.77 +2006 +57.70 +4.96 +F-45 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +NOTE +19 - QUARTERLY FINANCIAL DATA (UNAUDITED) +Quarterly +financial data for the years ended December 31, 2008 and 2007, are presented +below The sum of the quarters may not equal the total of the +year's net income per share due to changes in the weighted average shares +outstanding throughout the year. +2008 +Quarter +Ended +3/31/2008 +6/30/2008 +9/30/2008 +12/31/2008 +Year +Ended +(in +thousands, except per share data) +Revenues: +Oil +and gas sales +$ +71,646 +$ +94,549 +$ +99,422 +$ +56,260 +$ +321,877 +Sales +from natural gas marketing activities +23,325 +30,941 +53,372 +32,625 +140,263 +Oil +and gas well drilling +3,083 +2,887 +1,232 +413 +7,615 +Well +operations and pipeline income +2,352 +2,438 +3,356 +3,328 +11,474 +Oil +and gas price risk management gain (loss), net +(42,310 +) +(101,798 +) +169,402 +102,544 +127,838 +Other +income +3 +34 +20 +236 +293 +Total +revenues +58,099 +29,051 +326,804 +195,406 +609,360 +Costs +and expenses: +Oil +and gas production and well operations costs +18,132 +20,815 +22,173 +17,089 +78,209 +Cost +of natural gas marketing activities +22,121 +30,117 +54,372 +32,624 +139,234 +Cost +of oil and gas well drilling +78 +518 +501 +1,116 +2,213 +Exploration +expense +4,283 +3,467 +10,212 +27,143 +45,105 +General +and administrative expense +9,823 +9,231 +8,106 +10,555 +37,715 +Depreciation, +depletion and amortization +21,131 +22,105 +28,645 +32,694 +104,575 +Total +costs and expenses +75,568 +86,253 +124,009 +121,221 +407,051 +Income +(loss) from operations +(17,469 +) +(57,202 +) +202,795 +74,185 +202,309 +Interest +income +271 +75 +151 +94 +591 +Interest +expense +(4,932 +) +(6,394 +) +(7,817 +) +(8,989 +) +(28,132 +) +Income +(loss) before income taxes +(22,130 +) +(63,521 +) +195,129 +65,290 +174,768 +Provision +(benefit) for income taxes +(8,202 +) +(22,809 +) +68,233 +24,237 +61,459 +Net +income (loss) +$ +(13,928 +) +$ +(40,712 +) +$ +126,896 +$ +41,053 +$ +113,309 +Earnings +per common share: +Basic +$ +(0.95 +) +$ +(2.76 +) +$ +8.59 +$ +2.78 +$ +7.69 +Diluted +$ +(0.95 +) +$ +(2.76 +) +$ +8.55 +$ +2.78 +$ +7.63 +Weighted +average common and common equivalent shares outstanding: +Basic +14,738 +14,742 +14,767 +14,778 +14,736 +Diluted +14,738 +14,742 +14,835 +14,791 +14,848 +F-46 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +2007 +Quarter +Ended +3/31/2007 +6/30/2007 +9/30/2007 +12/31/2007 +Year +Ended +(in +thousands, except per share data) +Revenues: +Oil +and gas sales +$ +34,016 +$ +39,246 +$ +44,437 +$ +57,488 +$ +175,187 +Sales +from natural gas marketing activities +21,987 +29,924 +19,934 +31,779 +103,624 +Oil +and gas well drilling +4,030 +1,739 +1,573 +4,812 +12,154 +Well +operations and pipeline income +3,298 +1,292 +2,092 +2,660 +9,342 +Oil +and gas price risk management (loss) gain, net +(5,645 +) +3,742 +6,345 +(1,686 +) +2,756 +Other +income +226 +2 +1,894 +50 +2,172 +Total +revenues +57,912 +75,945 +76,275 +95,103 +305,235 +Costs +and expenses: +Oil +and gas production costs and well operations costs +9,035 +11,628 +12,645 +15,956 +49,264 +Cost +of natural gas marketing activities +21,512 +28,780 +19,810 +30,482 +100,584 +Cost +of oil and gas well drilling +564 +246 +749 +949 +2,508 +Exploration +expense +2,678 +6,780 +5,337 +8,756 +23,551 +General +and administrative expense +7,424 +6,886 +7,513 +9,145 +30,968 +Depreciation, +depletion and amortization +13,074 +17,429 +20,354 +19,987 +70,844 +Total +costs and expenses +54,287 +71,749 +66,408 +85,275 +277,719 +Gain +on sale of leaseholds +- +25,600 +- +7,691 +33,291 +Income +from operations +3,625 +29,796 +9,867 +17,519 +60,807 +Interest +income +1,143 +454 +462 +603 +2,662 +Interest +expense +(831 +) +(1,450 +) +(2,544 +) +(4,454 +) +(9,279 +) +Income +before income taxes +3,937 +28,800 +7,785 +13,668 +54,190 +Income +taxes +1,436 +10,749 +3,326 +5,470 +20,981 +Net +income +$ +2,501 +$ +18,051 +$ +4,459 +$ +8,198 +$ +33,209 +Earnings +per common share: +Basic +$ +0.17 +$ +1.22 +$ +0.30 +$ +0.56 +$ +2.25 +Diluted +$ +0.17 +$ +1.21 +$ +0.30 +$ +0.55 +$ +2.24 +Weighted +average common and common equivalent shares outstanding: +Basic +14,726 +14,740 +14,757 +14,758 +14,744 +Diluted +14,854 +14,860 +14,827 +14,859 +14,841 +F-47 +Table of Contents +PETROLEUM +DEVELOPMENT CORPORATION +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) +Schedule +II -VALUATION AND QUALIFYING ACCOUNTS +Description +Beginning +Balance +January 1 +Charged +to +Costs +and Expenses +Deductions +Ending +Balance +December 31 +(in +thousands) +2008: +Allowance +for doubtful accounts +(a) +$ +357 +$ +180 +$ +- +$ +537 +Valuation +allowance for unproved oil and gas properties +(b) +$ +2,365 +$ +12,798 +$ +2,293 +$ +12,870 +2007: +Allowance +for doubtful accounts +(a) +$ +415 +$ +50 +$ +108 +$ +357 +Valuation +allowance for unproved oil and gas properties +(b) +$ +596 +$ +2,183 +$ +414 +$ +2,365 +2006: +Allowance +for doubtful accounts +(a) +$ +409 +$ +7 +$ +1 +$ +415 +Valuation +allowance for unproved oil and gas properties +(b) +$ +33 +$ +653 +$ +90 +$ +596 +(a) +Deductions represent the write-off of accounts receivable deemed +uncollectible. +(b) +Deductions represent amortization of expired or abandoned unproved +oil and gas +properties. +F-48 \ No newline at end of file diff --git a/raw/filings/0000077877/2008/0001140361-09-005340/item13.txt b/raw/filings/0000077877/2008/0001140361-09-005340/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..ba1c26de9fd2d41993ce093b43242887954e1a07 --- /dev/null +++ b/raw/filings/0000077877/2008/0001140361-09-005340/item13.txt @@ -0,0 +1,9 @@ +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +AND DIRECTOR INDEPENDENCE +The +information called for by Item 13 is incorporated by reference from information +under the captions entitled Certain Relationships and Related +Transactions and +Director Independence in our definitive proxy statement to be +filed pursuant to Regulation 14A no later than 120 days after the close of our +fiscal year. \ No newline at end of file diff --git a/raw/filings/0000077877/2008/0001140361-09-005340/item9a.txt b/raw/filings/0000077877/2008/0001140361-09-005340/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..e642e0f06ef8391342e30dea186d4fffdfb2acaa --- /dev/null +++ b/raw/filings/0000077877/2008/0001140361-09-005340/item9a.txt @@ -0,0 +1,82 @@ +ITEM 9A. CONTROLS AND PROCEDURES +Evaluation +of Disclosure Controls and Procedures +As of +December 31, 2008, we carried out an evaluation, under the supervision and with +the participation of our management, including our Chief Executive Officer and +Chief Financial Officer, of the effectiveness of the design and operation of our +disclosure controls and procedures pursuant to Securities Exchange Act Rule +13a-15. Based upon that evaluation, our Chief Executive Officer and +Chief Financial Officer concluded that our disclosure controls and procedures +were effective as of December 31, 2008, to ensure that the information required +to be disclosed by the Company in the reports that we file or submit under the +Exchange Act is recorded, processed, summarized and reported, within the time +periods specified in the SEC rules and forms, and that the information is +accumulated and communicated to our management, including our Chief Executive +Officer and Chief Financial Officer, as appropriate to allow timely decisions +regarding required disclosure. +Changes +in Internal Control over Financial Reporting +We made +no changes in our internal control over financial reporting (as such term is +defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934) +during the quarter ended December 31, 2008, that have materially affected or are +reasonably likely to materially affect our internal control over financial +reporting. +See Remediation of Material Weaknesses +in Internal Control below for a discussion of changes in our internal +control over financial reporting that occurred throughout 2008. +49 +Table of Contents +Remediation +of Material Weaknesses in Internal Control +We, with +oversight from the Audit Committee of our Board of Directors, have been +addressing the material weaknesses disclosed in our 2007 Form 10-K and Item 4 of +our subsequently filed Form 10-Q for each of the quarterly periods in the +nine-month period ended September 30, 2008. We have concluded, based +on our assessment, that, through the implementation of the changes in internal +controls over financial reporting described below, we have remediated these +previously reported material weaknesses as of December 31, +2008. Management’s annual report on internal control over financial +reporting and the audit report on our internal control over financial reporting +of our independent registered public accounting firm are included in response to +Item 8 of this report on pages F-2 and F-3 included +herein. +The +remediation initiatives that were undertaken during 2008 include: +· +In +the first quarter of 2008, we implemented the general ledger, accounts +receivable, and joint interest billing modules as part of a new broader +financial reporting system. We have taken the necessary steps +to monitor and maintain appropriate internal controls during this period +of change. These steps included providing training related to +business process changes and the financial reporting system software to +individuals using the financial reporting system to carry out their job +responsibilities as well as those who rely on the financial +information. The implementation of the financial reporting +system strengthened the overall internal controls due to enhanced +automation and integration of related processes. The design and +documentation of internal control process and procedures relating to the +new system has been modified to supplement and complement existing +internal controls over financial +reporting. +· +In +the third quarter of 2008, we implemented controls over key financial +statement spreadsheets that support all significant balance sheet and +income statement accounts. Specifically, we enhanced the +spreadsheet policy to provide additional clarification and guidance with +regard to risk assessment and enforced controls over: 1) the security and +integrity of the data used in the various spreadsheets, 2) access to the +spreadsheets, 3) changes to spreadsheet functionality and the related +approval process and documentation and 4) increased managements review of +the spreadsheets. +· +In +the third quarter of 2008, key personnel attended an accredited derivative +training course and a desktop procedure was implemented to ensure the +completeness and accuracy over derivative activities, which supplemented +the key controls that previously existed in the +process. \ No newline at end of file diff --git a/raw/filings/0000077877/2008/0001140361-09-005340/rp_note.txt b/raw/filings/0000077877/2008/0001140361-09-005340/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2008/0001140361-09-005340/rpt_disclosure.txt b/raw/filings/0000077877/2008/0001140361-09-005340/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..f81326eee46479fbc9a932e6c2831ba5c9370709 --- /dev/null +++ b/raw/filings/0000077877/2008/0001140361-09-005340/rpt_disclosure.txt @@ -0,0 +1,236 @@ +The related party transaction policy applies to each director +and executive officer of the Company, any nominee for election +as a Director, any security holder who is known to own more than +five percent of the Company’s voting securities, any +immediate family member of any of the foregoing persons and any +corporation, firm or association in which one or more of the +Company’s directors are directors or officers, or have a +substantial financial interest. +Under the related party transaction policy, a related person +transaction is a transaction or arrangement involving a related +person in which the Company is a participant or that would +require disclosure in the Company’s filings with the SEC as +a transaction with a related person. +17 +Table of Contents +The related persons must disclose to the Audit Committee any +potential related person transactions and must disclose all +material facts with respect to such interest. All related person +transactions will be reviewed by the Audit Committee. In +determining whether to approve or ratify a transaction, the +Audit Committee will consider the relevant facts and +circumstances of the transaction which may include factors such +as the relationship of the related person with the Company, the +materiality or significance of the transaction to the Company +and the business purpose and reasonableness of the transaction, +whether the transaction is comparable to a transaction that +could be available to the Company on an arms-length basis, and +the impact of the transaction on the Company’s business and +operations. +Since January 1, 2008 to the present, there was no +transaction or series of transactions, or any currently proposed +transaction, in which the amount involved exceeds $120,000 and +in which any director, executive officer, holder of more than +five percent of the Company’s common stock or any member of +the immediate family of any of the foregoing persons had or will +have a direct or indirect material interest. +Indemnification +of Directors and Officers +The Company’s By-Laws provide that the Company shall +indemnify any director, officer, employee, or other agent of the +Company who is or was a party, or is threatened to be made a +party, to any proceeding (other than an action by or in the +right of the Company to procure a judgment in its favor) by +reason of the fact that such person is or was an agent of the +Company, against expenses, judgments, fines, settlements, and +other amounts actually and reasonably incurred in connection +with such proceeding, if that person acted in good faith and in +a manner that person reasonably believed to be in the best +interest of the Company, and in the case of a criminal +proceeding, had no reasonable cause to believe the conduct of +that person was unlawful. +The Company has entered into separate indemnification agreements +with each of its Directors whereby the Company has agreed to +indemnify the Director against all expenses, including +attorneys’ fees, and other amounts reasonably incurred by +the director in connection with any threatened, pending or +completed civil, criminal, administrative or investigative +action or proceeding to which such person is party by reason of +the fact that he is or was a Director, as the case may be, of +the Company, if the person acted in good faith and in a manner +reasonably believed to be in or not opposed to the best +interests of the Company, and, with respect to any criminal +action or proceeding, the person had no reasonable cause to +believe such conduct to be unlawful. The agreements provide for +the advancement of expenses and that the Company has the right +to purchase and maintain insurance on behalf of the director +against any liability or liabilities asserted against such +person, whether or not the Company would have the power to +indemnify the person against such liability under any provision +of the agreement. The Company has agreed to indemnify such +person against expenses actually and reasonably incurred in +connection with any action in which the person has been +successful on the merits or otherwise. Indemnification must also +be provided by the Company (unless ordered otherwise by a court) +only as authorized in the specific case upon a determination +that the indemnification of the person is appropriate because he +or she has met the applicable standard of conduct described in +the agreement made by (i) the Board of Directors, by a +majority vote of a quorum consisting of Directors who are not +parties to such action or proceeding, (ii) independent +legal counsel in a written opinion or (iii) the +shareholders of the Company. +Additional +Information +The “Corporate Governance” section of the +Company’s internet site contains additional information, +including PDC’s Certificate of Incorporation and By-Laws; +written charters for each Board committee; and Board policy +statements. +The Company files annual, quarterly and current reports, proxy +statements and other information with the SEC. Copies of the +Company’s filings with the SEC are available to the public +at the SEC’s website at +http://www.sec.gov . +These documents may also be viewed at the SEC’s public +reference room located at 100 F Street, N.E., +Washington, D.C. 20549. Please call the SEC at +1-800-SEC-0330 +for further information on the public reference room. +18 +Table of Contents +EXECUTIVE +OFFICERS +The current executive officers of the Company, their principal +occupations for the past five years and additional information +is set forth below. +Directorship +Director +Term +Name +Age +Position(s) +Since +Expires +Richard W. McCullough (1) +57 +Chairman, Chief Executive Officer and Director +2007 +2010 +Eric R. Stearns +51 +Executive Vice President +– +– +Gysle R. Shellum (2) +57 +Chief Financial Officer +– +– +Barton R. Brookman, Jr. (3) +46 +Senior Vice President Exploration and Production +– +– +Daniel W. Amidon +48 +General Counsel and Secretary +– +– +R. Scott Meyers. (4) +34 +Chief Accounting Officer +– +– +(1) +Mr. Williams retired as CEO effective June 23, 2008. +Mr. McCullough was selected as his successor upon +Mr. Williams’ retirement. +(2) +Mr. Shellum became Chief Financial Officer in November 2008. +(3) +Mr. Brookman was appointed to the executive position of +Senior Vice President on March 8, 2008. +(4) +Mr. Meyers assumed the duties of Chief Accounting Officer +on April 2, 2009. During 2008 and until April 2, 2009, +Darwin L. Stump served in that position. +Richard W. McCullough was appointed Chief Executive +Officer in June 2008 and Chairman in November 2008. +Mr. McCullough also served the Company as President since +March 2008. Mr. McCullough served as Chief Financial +Officer from November 2006 until November 2008. Prior to joining +PDC, Mr. McCullough served as an energy consultant from +July 2005 to November 2006. From January 2004 to July 2005, +Mr. McCullough served as President and Chief Executive +Officer of Gasource, LLC, Dallas, Texas, a marketer of +long-term, natural gas supplies. From 2001 to 2003, +Mr. McCullough served as an investment banker with +J.P. Morgan Securities, Atlanta, Georgia, and served in the +public finance utility group supporting bankers nationally in +all natural gas matters. Additionally, Mr. McCullough has +held senior positions with Progress Energy, Deloitte and Touche, +and the Municipal Gas Authority of Georgia. Mr. McCullough, +a CPA, was a practicing certified public accountant for +8 years. +Eric R. Stearns was appointed Executive Vice President in +March 2008. Prior to his current position, Mr. Stearns +served as Executive Vice President Exploration and Production +since December 2004, Executive Vice President Exploration and +Development from November 2003 until December 2004, and Vice +President Exploration and Development from April 1995 until +November 2003. Mr. Stearns joined PDC as a geologist in +1985 after working at Hywell, Incorporated and for Petroleum +Consultants. +Gysle R. Shellum was appointed Chief Financial Officer +effective November 11, 2008. Prior to joining the Company, +Mr. Shellum served as Vice President, Finance and Special +Projects of Crosstex Energy, L.P., Dallas, Texas. +Mr. Shellum served in this capacity from September 2004 +through September 2008. Prior thereto from March 2001 until +September 2004, Mr. Shellum served as a consultant to Value +Capital, a private consulting firm in Dallas, where he worked on +various projects, including corporate finance and Sarbanes-Oxley +Act compliance. Crosstex Energy, L.P. is a publicly traded +Delaware limited partnership, whose securities are listed on the +NASDAQ Global Select Market and is an independent midstream +energy company engaged in the gathering, transmission, treating, +processing and marketing of natural gas and natural gas liquids. +Barton R. Brookman, Jr. was appointed Senior Vice +President Exploration and Production in March 2008. Previously +Mr. Brookman served as Vice President Exploration and +Production since joining PDC in July 2005. Prior to joining PDC, +Mr. Brookman worked for Patina Oil and Gas and its +predecessor Snyder Oil for 17 years in a series of +positions of increasing responsibility, ending his service as +Vice President of Operations of Patina. +19 +Table of Contents +Daniel W. Amidon was appointed General Counsel and +Secretary in July 2007. Prior to his current position, +Mr. Amidon was employed by Wheeling-Pittsburgh Steel +Corporation beginning in July 2004; he served in several +positions including General Counsel and Secretary. Prior to his +employment with Wheeling-Pittsburgh Steel, Mr. Amidon +worked for J&L Specialty Steel Inc. from 1992 through July +2004 in positions of increasing responsibility, including +General Counsel and Secretary. Mr. Amidon practiced with +the Pittsburgh law firm of Buchanan Ingersoll PC from 1986 +through 1992. +Darwin L. Stump was Chief Accounting Officer from +November 2006 until April 2, 2009. Mr. Stump has been +an officer of PDC since April 1995 and held the position of +Chief Financial Officer and Treasurer from November 2003 until +November 2006. Previously, Mr. Stump served as Corporate +Controller from 1980 until November 2003. Mr. Stump, a CPA, +was a senior accountant with Main Hurdman, Certified Public +Accountants prior to joining PDC. +R. Scott Meyers was appointed Chief Accounting +Officer on April 2, 2009. Prior to joining the Company, +Mr. Meyers served as a Senior Manager with Schneider Downs +Co., Inc., an accounting firm based in Pittsburgh, Pennsylvania. +Mr. Meyers served in such capacity from April 2008 to March +2009. Prior thereto, from November 2002 to March 2008, +Mr. Meyers was employed by PricewaterhouseCoopers LLP, the +last two and one-half years serving as Senior Manager. +COMPENSATION \ No newline at end of file diff --git a/raw/filings/0000077877/2009/0001140361-10-009868/filing.txt b/raw/filings/0000077877/2009/0001140361-10-009868/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..58317bd2c0458aae04219de681a7da16c09cfe53 --- /dev/null +++ b/raw/filings/0000077877/2009/0001140361-10-009868/filing.txt @@ -0,0 +1,7847 @@ +10-K +1 +form10k.htm +PETROLEUM DEVELOPMENT CORP 10-K 12-31-2009 +form10k.htm +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +FORM 10-K +T 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 +£ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period from __________ to _________ +Commission File Number 000-07246 +PETROLEUM DEVELOPMENT CORPORATION +(Exact name of registrant as specified in its charter) +Nevada +95-2636730 +(State of Incorporation) +(I.R.S. Employer Identification No.) +1775 Sherman Street, Suite 3000 +Denver, Colorado 80203 +(Address of principal executive offices) (Zip Code) +Registrant's telephone number, including area code: (303) 860-5800 +Securities registered pursuant to Section 12(b) of the Act: +Title of Each Class +Name of Each Exchange on Which Registered +Common Stock, par value $.01 per share +NASDAQ Global Select Market +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 ¨ No þ +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 ¨ 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 ¨ +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 ¨ No ¨ +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. ¨ +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 definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. +Large accelerated filer +¨ +Accelerated filer þ +Non-accelerated filer +¨ (Do not check if a smaller reporting company) +Smaller reporting company ¨ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No þ +The aggregate market value of our common stock held by non-affiliates on June 30, 2009, was $228,721,681 (based on the then closing price of $15.69). +As of February 16, 2010, there were 19,240,478 shares of our common stock outstanding. +DOCUMENTS INCORPORATED BY REFERENCE +The information required by Part III of this Form is incorporated by reference to our definitive proxy statement to be filed pursuant to Regulation 14A for our 2010 Annual Meeting of Shareholders. +PE TROLEUM DEVELOPMENT CORPORATION +2009 ANNUAL REPORT ON FORM 10-K +TABLE OF CONTENTS +PART I +Page +Item 1. +Business +2 +Item 1A. +Risk Factors +17 +Item 1B. +Unresolved Staff Comments +26 +Item 2. +Properties +27 +Item 3. +Legal Proceedings +27 +Item 4. +[Reserved] +27 +PART II +Item 5. +Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities +27 +Item 6. +Selected Financial Data +29 +Item 7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations +30 +Item 7A. +Quantitative and Qualitative Disclosures About Market Risk +47 +Item 8. +Financial Statements and Supplementary Data +49 +Item 9. +Changes in and Disagreements With Accountants on Accounting and Financial Disclosure +49 +Item 9A. +Controls and Procedures +49 +Item 9B. +Other Information +49 +PART III +Item 10. +Directors, Executive Officers and Corporate Governance +49 +Item 11. +Executive Compensation +49 +Item 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +50 +Item 13. +Certain Relationships and Related Transactions, and Director Independence +50 +Item 14. +Principal Accounting Fees and Services +50 +PART IV +Item 15. +Exhibits, Financial Statement Schedules +50 +SIGNATURES +51 +GLOSSARY OF NATURAL GAS AND OIL TERMS +52 +Table of Contents +PART I +REFERENCES TO THE REGISTRANT +Unless the context otherwise requires, references to "PDC," "the Company," "we," "us," "our," "ours" or "ourselves" in this report refer to the registrant, Petroleum Development Corporation, together with its wholly owned subsidiaries, entities in which it has a controlling financial interest and proportionate share of its sponsored drilling partnerships. +GLOSSARY OF NATURAL GAS AND OIL TERMS +Words defined in the Glossary of Natural Gas and Oil Terms are set in boldface type the first time they appear. +UNITS OF MEASUREMENT +The following presents a list of units of measurement used throughout the document. +Bbl – One oil barrel or 42 gallons of liquid volume. +Bcf – One billion cubic feet of natural gas volume. +Bcfe – One billion cubic feet of natural gas equivalent. +Btu – British thermal unit. +MBbls – One thousand oil barrels. +Mcf – One thousand cubic feet of natural gas volume. +Mcfe – One thousand cubic feet of natural gas equivalent (six Mcf of natural gas equals one Bbl of oil). +Mmbtu – One million British thermal units. +Mmcf – One million cubic feet of natural gas volume. +Mmcfe – One million cubic feet of natural gas equivalent. +WHERE YOU CAN FIND MORE INFORMATION +We file annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission ("SEC"). Our SEC filings are available free of charge from the SEC’s website at www.sec.gov or from our website at www.petd.com . You may also read or copy any document we file at the SEC’s public reference room in Washington, D.C., located at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Please call the SEC at (800) SEC-0330 for further information on the public reference room. We also make available free of charge any of our SEC filings by mail. For a mailed copy of a report, please contact Petroleum Development Corporation, Investor Relations, 1775 Sherman Street, Suite 3000, Denver, CO 80203, or call toll free 800-624-3821. +In addition to our SEC filings, our website can be used to access other information, including our recent news releases, bylaws, committee charters, code of business conduct and ethics, shareholder communication policy, director nomination procedures and our whistleblower hotline. However, the information available on our website is not part of this report and is not hereby incorporated by reference. +SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS +This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 ("Securities Act") and Section 21E of the Securities Exchange Act of 1934 ("Exchange Act") regarding our business, financial condition, results of operations and prospects. All statements other than statements of historical facts included in and incorporated by reference into this report are forward-looking statements. Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements herein, which include statements of estimated natural gas and oil production and reserves , drilling plans, future cash flows, anticipated liquidity, anticipated capital expenditures and our management’s strategies, plans and objectives. However, these are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Consequently, forward-looking statements are inherently subject to risks and uncertainties, including risks and uncertainties incidental to the exploration for, and the acquisition, development, production and marketing of natural gas and oil, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements. Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to: +· +changes in production volumes, worldwide demand and commodity prices for natural gas and oil; +· +the timing and extent of our success in discovering, acquiring, developing and producing natural gas and oil reserves; +· +our ability to acquire leases, drilling rigs, supplies and services at reasonable prices; +· +the availability and cost of capital to us; +· +risks incident to the drilling and operation of natural gas and oil wells; +· +future production and development costs; +1 +Table of Contents +· +the availability of sufficient pipeline and other transportation facilities to carry our production and the impact of these facilities on price; +· +the effect of existing and future laws, governmental regulations and the political and economic climate of the United States of America ("U.S."); +· +the effect of natural gas and oil derivatives activities; +· +conditions in the capital markets; and +· +losses possible from pending or future litigation. +Further, we urge you to carefully review and consider the disclosures made in this report, including the risks and uncertainties that may affect our business as described herein under Item 1A, Risk Factors , and our other filings with the SEC. We caution you not to place undue reliance on forward-looking statements, which speak only as of the date of this report. We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. +IT EM 1. BUSINESS +Overview +We are an independent energy company engaged in the exploration for and the acquisition, development, production and marketing of natural gas and oil. Since we began natural gas and oil operations in 1969, we have grown through drilling and development activities, acquisitions of producing natural gas and oil wells and the expansion of our natural gas marketing business. +During 2009, we managed our balance sheet in an effort to ensure that we had sufficient liquidity during an uncertain economic environment and we intend to maintain this spending discipline going forward. We focused our efforts on our ability to control spending by concentrating on cost reductions in lease operating expenses and per well capital expenditures and limiting our capital budget to be within our expected operating cash flows. Additionally, we raised capital through an equity offering and asset monetization through the formation of our Appalachian joint venture. +Based on unstable economic conditions existing early in 2009 and uncertainty as to when commodity and financial markets would recover to a perceived normal level, we reduced our planned 2009 capital expenditures to $108 million, or approximately 33% of our 2008 level. Additionally, we targeted our drilling dollars in the oil–rich section of the Wattenberg Field in our Rocky Mountain Region to take advantage of the pricing of oil over natural gas. Then, in August 2009, we completed an underwritten public offering of 4.3 million shares of the Company’s common stock at a price of $12.00 per share for net proceeds of $48.5 million. Finally, in October 2009, we entered into a joint venture arrangement with an unaffiliated party that monetized a portion of our Appalachian Basin assets. We entered into the joint venture with Lime Rock Partners ("Lime Rock") primarily to develop our Marcellus Shale acreage in the Appalachian Basin. At closing, we received a return of capital payment of $45 million. Upon the fulfillment of Lime Rock's commitment to provide future operational funding of $68.5 million, Lime Rock will earn a 50% interest in our Appalachian assets, exclusive of our interest in our affiliated partnerships’ wells. We do not expect to make any capital contributions to the joint venture in 2010 or until Lime Rock achieves a 50% interest, which is expected to occur in 2011. +Business Strategy +Our primary objective is to increase shareholder value through the growth of our reserves and production, while operating our properties in an efficient manner to maximize the cash flow and earnings potential of our assets. +Drill and Develop. Our acreage holdings include positions primarily in the Rocky Mountain Region and, through our joint venture, the Appalachian Basin. We believe that we will be able to continue to drill a substantial number of new wells on our current undeveloped properties. As of December 31, 2009, we had approximately 2,285 gross drill sites available in the Rocky Mountain Region and, through our joint venture, 569 gross drill sites available in the Appalachian Basin. In 2010, we plan to drill approximately 226 gross, 188.5 net, development wells in our Rocky Mountain Region and 26 gross wells , 15.6 net wells , targeted for the Marcellus Shale in the Appalachian Basin. +Rocky Mountain Region . Our primary focus in the Rocky Mountain Region is on developmental drilling in the Wattenberg Field and in Northeastern Colorado, or NECO, (both located in the DJ Basin) and the Grand Valley Field in the Piceance Basin. We seek to maximize the value of our existing wells through a program of well recompletions , refractures and workovers . In 2010, we plan to workover 50 wells and recomplete and/or refrac 12 wells. +2 +Table of Contents +Appalachian Basin . Historically, our focus was on developmental drilling, targeting predominantly gas reserves in Devonian and Mississippian aged tight sandstone reservoirs. In 2009, our focus shifted to that of exploratory drilling, targeting the Marcellus Shale formation in West Virginia and Pennsylvania. In 2010, through our joint venture, our preliminary budget includes plans to drill 26 development wells targeting the Marcellus and 50 recompletes and 29 workovers targeting the shallow Devonian. +Strategically Acquire . Our acquisition efforts focus on producing properties that have a significant undeveloped acreage component. When weighing potential acquisitions, we prefer properties that have most of their value in producing wells, behind pipe reserves and high quality proved undeveloped locations. Historically, acquisitions have offered efficiency improvements through economies of scale in management and administration costs. During the period December 2006 through October 2007, we completed a series of asset and company acquisitions, three in our core operating area of the Rocky Mountain Region and two in the Appalachian Basin. While we had no significant acquisitions of properties in 2008 or 2009, we continue to identify and evaluate acquisition opportunities that will enhance our current properties and provide an opportunity to explore and develop new prospects. +Manage Risk . Historically, we have concentrated on development drilling and geographical diversification to reduce risk levels associated with natural gas and oil drilling, production and markets. Currently, a majority of our proved reserves are located in the Rocky Mountain Region. However, we benefit from operational diversity in the Rocky Mountain Region by maintaining significant activity and production in three separate areas, including the Wattenberg Field in north central Colorado and the NECO area, both located in the DJ Basin, and the Grand Valley Field in the Piceance Basin in western Colorado. Additionally, we regularly review opportunities to further diversify into other regions where we can apply our operational expertise. We believe development drilling will remain the foundation of our drilling activities in the future because it is less risky than exploratory drilling and is likely to generate cash returns more quickly. In addition to improving our liquidity position, the formation of the joint venture serves to mitigate the risks associated with exploring our Marcellus rights. We view exploratory activities as having the potential to identify new development opportunities at a cost competitive with the current cost of acquiring proven locations. +We maintain a conservative financial approach and proactively employ strategies to reduce the effects of commodity price volatility to help manage the risks associated with the oil and natural gas industry (the "industry"). We use natural gas and oil derivatives contracts primarily to reduce the effects of volatile commodity prices. At any given time, we have derivative contracts in place on a varying portion of our production; however, pursuant to our derivative policy, all volumes for derivatives contracts are limited to 80% of our future production from producing wells at the time we enter into the derivative contracts, with the exception of put contracts, or floors, for which volumes are not limited. As of December 31, 2009, we had natural gas and oil hedges in place covering 66.2% of our expected natural gas production and 59.8% of our expected oil production in 2010. Further, while our derivative instruments are utilized to manage the impact of price volatility of our natural gas and oil production, we have elected not to formally designate these instruments as hedging instruments and therefore, we do not use hedge accounting. Accordingly, we are required to recognize changes in the fair value of our derivative instruments in earnings each reporting period and, therefore, have the potential for significant earnings volatility. Our policy prohibits the use of natural gas and oil derivative instruments for speculative purposes. See Note 2, Summary of Significant Accounting Polices – Derivative Financial Instruments and Note 4, Derivative Financial Instruments , to our consolidated financial statements included in this report. +Business Segments +We divide our operating activities into two segments: natural gas and oil sales and natural gas marketing. See Note 14, Business Segments , to our consolidated financial statements included in this report. +Natural Gas and Oil Sales . Our natural gas and oil sales segment primarily reflects revenues and expenses from the production and sale of natural gas and oil. During 2009, natural gas and oil represented 82.1% and 17.9% of our total production volumes, respectively, with 87% of our total production being generated by our Rocky Mountain Region properties and 9.4% by our Appalachian Basin properties. The majority of our undeveloped acreage is in our Rocky Mountain Region, where our 2009 drilling activities were focused and will continue to be the focus in 2010. +We operate approximately 92.7% of the wells in which we own a working interest . With respect to wells we operate and own an interest of less than 100%, we charge the other working interest owners, including our drilling partnerships, a competitive fee for operating the well and transporting natural gas. Revenues and expenses related to our well operations and transportation of natural gas are included in our natural gas and oil sales segment. +Natural Gas Marketing . Our natural gas marketing segment is comprised of our wholly-owned subsidiary Riley Natural Gas ("RNG"), through which we purchase, aggregate and resell natural gas produced by us and others. This allows us to diversify our operations beyond natural gas drilling and production. Through RNG, we have established relationships with many of the natural gas producers in the Appalachian Basin and have gained significant expertise in the natural gas end-user market. +3 +Table of Contents +Areas of Operations +The following map presents the general locations of our exploration, development and production activities as of December 31, 2009. +We focus our exploration, development and production efforts primarily in two geographic areas: the Rocky Mountain Region and the Appalachian Basin. The majority of our undeveloped acreage is in the Rocky Mountain Region and our current drilling plans continue to be focused predominantly in this area. +Rocky Mountain Region. Our Rocky Mountain Region is divided into three major operating areas: (1) Grand Valley Field, (2) Wattenberg Field and (3) NECO area. Our Rocky Mountain Region includes approximately 293,600 gross acres of leasehold and 2,524 gross, 1,654.3 net, natural gas and oil wells in which we own an interest. +· +Grand Valley Field, Piceance Basin, Garfield County, Colorado. Development wells drilled in the area range from 7,000 to 9,500 feet in depth and the majority of wells are drilled directionally from multi-well pads generally ranging from two to ten wells per drilling pad. The primary target in the area is gas reserves, developed from multiple sandstone reservoirs in the Mesaverde Williams Fork formation. Well spacing is approximately ten acres per well. +· +Wattenberg Field, DJ Basin, Weld County, Colorado . Wells drilled in the area range from approximately 7,000 to 8,000 feet in depth and generally target natural gas and oil reserves in the Niobrara, Codell and J Sand reservoirs. Well spacing ranges from 20 to 40 acres per well. Operations in the area, in addition to the drilling of new development wells, include the refrac of Codell and Niobrara reservoirs in existing wellbores whereby the Codell sandstone reservoir is fraced a second time and/or initial completion attempts are made in the slightly shallower Niobrara carbonate reservoir. Unlike our other two Rocky Mountain areas, the Wattenberg Field produces a significant amount of oil and, to a lesser extent, natural gas liquids . +· +NECO area, DJ Basin, Yuma County, Colorado and Cheyenne County, Kansas . Wells drilled in the area range from approximately 1,500 to 3,000 feet in depth and target gas reserves in the shallow Niobrara reservoir. Well spacing is approximately 40 acres per well. Drilling operations range from exploratory wells to test undrilled, seismically defined, structural features at the Niobrara horizon to development wells targeting known reserves in existing identified features. +4 +Table of Contents +· +Other Rocky Mountain Region Areas . We currently own an interest in 14 gross, 5 net, natural gas and oil wells in Burke County, North Dakota and 3 gross, 0.7 net, oil wells in Wyoming. As of December 31, 2009, our remaining North Dakota leasehold encompasses approximately 58,400 gross acres with approximately 25,600 net undeveloped acres remaining for development and our Wyoming leasehold encompasses approximately 19,200 gross and net undeveloped acres. We currently have no drilling activity planned for these areas in 2010. +Appalachian Basin. We own an interest in approximately 271 gross, 88.5 net, natural gas and oil wells in West Virginia, Pennsylvania and Tennessee outside of our interest in our joint venture with Lime Rock. Additionally, in association with the joint venture, we own an interest in approximately 1,980 gross, 1,586.4 net, wells. Wells located in this area are approximately 4,500 feet deep and target predominantly gas reserves in Devonian and Mississippian aged tight sandstone reservoirs. +Other Areas . We own an interest in approximately 210 gross, 146.5 net, natural gas and oil wells in the Michigan Basin that produced 1.4 Bcfe net to our interest in 2009. As of December 31, 2009, our remaining Michigan leasehold encompasses 10,000 gross, 8,500 net, undeveloped acres. Wells in the area range from 1,000 to 2,500 feet in depth and produce gas from the Antrim Shale. We also hold a total of 27,200 gross, 21,500 net, undeveloped acres in New York and Texas. We currently have no drilling activity planned for these three areas in 2010. +The table below presents our productive wells by operating area at December 31, 2009. +Productive Wells +Natural Gas +Oil +Total +Location +Gross +Net +Gross +Net +Gross +Net +Rocky Mountain Region +Wattenberg +1,459 +944.7 +25 +19.2 +1,484 +963.9 +Grand Valley +306 +180.4 +- +- +306 +180.4 +NECO +717 +504.3 +- +- +717 +504.3 +Other +5 +1.3 +12 +4.4 +17 +5.7 +Total Rocky Mountain Region +2,487 +1,630.7 +37 +23.6 +2,524 +1,654.3 +Appalachian Basin (1) +2,212 +1,659.4 +39 +15.5 +2,251 +1,674.9 +Other +208 +148.8 +7 +2.7 +215 +151.5 +Total productive wells +4,907 +3,438.9 +83 +41.8 +4,990 +3,480.7 +(1) Includes 100% of the wells owned by the joint venture. +Operations +Prospect Generation +Our staff of professional geologists is responsible for identifying areas with potential for economic production of natural gas and oil. They utilize results from logs, seismic data and other tools to evaluate existing wells and to predict the location of economically attractive new natural gas and oil reserves. To further this process, we have collected and continue to collect logs, core data, production information and other raw data available from state and private agencies and other companies and individuals actively drilling in the regions being evaluated. From this information, the geologists develop models of the subsurface structures and formations that are used to predict areas for prospective economic development. +On the basis of these models, our land department obtains available natural gas and oil leaseholds, farm-outs and other development rights in these prospective areas. In most cases, to secure a lease, we pay a lease bonus and an annual rental payment, converting, upon initial production, to a royalty . In addition, overriding royalty payments may be granted to third parties in conjunction with the acquisition of drilling rights initially leased by others. See a summary of our acreage available for development below. +5 +Table of Contents +Financing of Company Drilling and Development Activities +We have historically funded our drilling and development activities through our cash flows from operations, capital provided from our credit facility, sale of leaseholds, a senior notes issuance and, in August 2009, an equity offering. Further, in October 2009, we entered into a joint venture arrangement that monetized a portion of our Appalachian Basin assets in which we received $45 million as a return of capital and provides for future operational funding of $68.5 million in the same area. In addition to any combination of our historical sources, future sources of funding may include, but not limited to, volumetric production payments, debt securities and convertible debt securities. +Purchases of Producing Properties +In addition to drilling new wells, we continue to pursue opportunities to purchase existing wells and development rights from other owners, as well as greater ownership interests in the wells we operate. Generally, outside interests purchased include a majority interest in the wells and the right to operate the wells. In January 2007, we completed the purchase from an unrelated party of approximately 144 natural gas and oil wells and 8,160 acres of leaseholds in the Wattenberg Field. Also in January 2007, we purchased the outside partnership interests in 44 partnerships which we sponsored and formed primarily in the late 1980s and 1990s. These interests constituted the majority of the interests in 718 wells, primarily in the Appalachian and Michigan Basins. In February 2007, we acquired from an unrelated party 28 producing wells and associated undeveloped acreage in Colorado. In October 2007, we purchased from unrelated parties a majority working interest of 762 natural gas wells located in southwestern Pennsylvania. The purchase also included associated pipelines, equipment, real estate and undeveloped acreage. No significant acquisitions were made in 2008 or 2009. +Title to Properties +We believe that we hold good and defensible title to our developed properties, in accordance with standards generally accepted in the industry. As is customary in the industry, a preliminary title examination is conducted at the time the undeveloped properties are acquired. Prior to the commencement of drilling operations, a title examination is conducted and remedial work is performed with respect to discovered defects which we deem to be significant. Title examinations have been performed with respect to substantially all of our producing properties. +The properties we own are subject to royalty, overriding royalty and other outstanding interests customary to the industry. The properties may also be subject to additional burdens, liens or encumbrances customary to the industry, including items such as operating agreements, current taxes, development obligations under natural gas and oil leases, farm-out agreements and other restrictions. We do not believe that any of these burdens will materially interfere with the use of the properties. +Acreage +The following table presents, by operating area, leased acres as of December 31, 2009. +Developed +Undeveloped +Total +Location +Gross +Net +Gross +Net +Gross +Net +Rocky Mountain Region +Wattenberg +48,400 +45,500 +23,800 +19,400 +72,200 +64,900 +Grand Valley +2,700 +2,700 +5,300 +5,300 +8,000 +8,000 +NECO +23,600 +19,600 +103,500 +85,500 +127,100 +105,100 +Other +8,700 +4,700 +77,600 +44,800 +86,300 +49,500 +Total Rocky Mountain Region +83,400 +72,500 +210,200 +155,000 +293,600 +227,500 +Appalachian Basin (1) +109,600 +106,800 +11,300 +10,800 +120,900 +117,600 +Other +17,200 +15,200 +37,200 +30,000 +54,400 +45,200 +Total acreage +210,200 +194,500 +258,700 +195,800 +468,900 +390,300 +(1) +Includes 100% of the acreage related to the joint venture. +6 +Table of Contents +Drilling Activities +The following table presents our development and exploratory drilling activity for the last three years. There is no correlation between the number of productive wells completed during any period and the aggregate reserves attributable to those wells. Productive wells consist of producing wells and wells capable of commercial production. +Drilling Activity +2009 +2008 +2007 +Gross +Net +Gross +Net +Gross +Net +Development: +Productive (1) +Rocky Mountain Region +87 +68.2 +289 +243.8 +316 +247.9 +Appalachian Basin +2 +2.0 +60 +60.0 +8 +8.0 +Other +- +- +- +- +3 +3.0 +Total productive +89 +70.2 +349 +303.8 +327 +258.9 +Dry +Rocky Mountain Region +2 +1.0 +8 +8.0 +11 +9.7 +Appalachian Basin +- +- +- +- +- +- +Other +- +- +- +- +- +- +Total dry +2 +1.0 +8 +8.0 +11 +9.7 +Total development +91 +71.2 +357 +311.8 +338 +268.6 +Exploratory: +Productive (1) +Rocky Mountain Region +2 +1.0 +4 +4.0 +1 +0.2 +Appalachian Basin +5 +5.0 +- +- +- +- +Other +- +- +3 +3.0 +- +- +Total productive +7 +6.0 +7 +7.0 +1 +0.2 +Dry +Rocky Mountain Region +- +- +7 +7.0 +7 +4.5 +Appalachian Basin +- +- +- +- +- +- +Other +- +- +3 +2.6 +- +- +Total dry +- +- +10 +9.6 +7 +4.5 +Pending determination +2 +2.0 +5 +5.0 +3 +3.0 +Total exploratory +9 +8.0 +22 +21.6 +11 +7.7 +Total drilling activity +100 +79.2 +379 +333.4 +349 +276.3 +Recompletions/refractures +32 +30.6 +125 +106.9 +181 +155.3 +(1) +As of December 31, 2009, a total of 19 productive wells were waiting to be fractured and/or for gas pipeline connection, of which 10 were connected and turned in line by February 15, 2010. +7 +Table of Contents +The following table presents the wells drilled, by operating area, during the last three years, as well as our planned 2010 drilling activity. +Planned +2010 +2009 +2008 +2007 +Gross +Gross +Net +Gross +Net +Gross +Net +Rocky Mountain Region +Wattenberg +180 +82 +65.2 +149 +122.7 +158 +106.0 +Grand Valley +21 +1 +1.0 +62 +54.4 +53 +41.7 +NECO +25 +8 +4.5 +98 +88.2 +123 +115.0 +Other +- +1 +0.5 +2 +0.5 +3 +1.6 +Total Rocky Mountain Region +226 +92 +71.2 +311 +265.8 +337 +264.3 +Appalachian Basin (1) +26 +8 +8.0 +62 +62.0 +8 +8.0 +Other +- +- +- +6 +5.6 +4 +4.0 +Total wells planned/drilled +252 +100 +79.2 +379 +333.4 +349 +276.3 +______________ +(1) +During 2009, 7 gross wells were drilled prior to the formation of the joint venture and 1 was drilled subsequent to its formation. The drilling activity planned for 2010 will be conducted for the benefit of the joint venture and funded by our joint venture partner. +Much of the work associated with drilling, completing and connecting wells, including fracturing, logging and pipeline construction is performed by subcontractors, under our direction, specializing in those operations, as is common in the industry. When judged advantageous, we acquire materials and services used in the development process through competitive bidding by approved vendors. We also directly negotiate rates and costs for services and supplies when conditions indicate that such an approach is warranted. +Drilling and Development Activities Conducted for Company Sponsored Partnerships +We began sponsoring drilling partnerships in 1984, and had sponsored one or more every year through 2007. For many years, our drilling partners were primarily the public and private partnerships we sponsored. At closing, we contributed a cash investment to purchase an interest in the drilling and development activities of the partnership and then serve as the managing general partner. As wells produce for a number of years, we continue to serve as operator for 33 partnerships, as well as for other unaffiliated parties. +When developing wells for our partnerships or others, we entered into a development agreement with the investor partner, pursuant to which we agreed to sell some or all of our rights in a well to be drilled to the partnership or other entity. The partnership or other entity thereby became an owner of a working interest in the well. In our financial reporting, we report only our proportionate share of natural gas and oil reserves, production, natural gas and oil sales and costs associated with wells in which we have a noncontrolling financial interest. +In January 2008, we announced that we did not plan to sponsor new drilling partnerships in 2008. We affirmed this position in 2009 to change our business model from a partnership sponsor to that of an independent exploration and production company. Under our previous model, we drilled both partnership wells and wells for our own account. In the case of the partnership wells, we effectively limited drilling and operating risk borne by us to generally 20% to 37% of the total cost of the drilling activity. Since we have discontinued the partnership sponsor model, our composite exposure to risks associated with drilling and operating natural gas and oil properties have increased because we drill and operate all natural gas and oil wells using our operating cash flows and debt. +Drilling and Development Activities Conducted for Appalachian Joint Venture +With the formation of our joint venture arrangement with Lime Rock, we are able to engage in extensive drilling activities in the Appalachian Basin using capital of $68.5 million committed by our joint venture partner. After our joint venture partner achieves a 50% interest in the joint venture, all future funding of capital will be shared equally. While sharing the risk inherent in exploratory drilling, we are still able to maintain a portion of the potential benefits associated with such risk. +In our financial reporting, as of and for the year ended December 31, 2009, we consolidated the natural gas and oil revenues, production, natural gas and oil sales and costs associated with the wells within the joint venture which we have a controlling financial interest. +8 +Table of Contents +Natural Gas and Oil Reserves +All of our natural gas and oil reserves are located in the U.S. Our reserve estimates are prepared with respect to reserve categorization, using the definitions for proved reserves set forth in SEC Regulation S-X, Rule 4-10(a) and subsequent SEC staff regulations, interpretations and guidance. All of our proved natural gas and oil reserves, including reserves held by consolidated companies and our proportionate share of our affiliates partnerships, have been estimated by independent consultants. +We have a comprehensive process that governs the determination and reporting of our proved reserves. As part of our internal control process, our reserves are reviewed annually by an internal team composed of reservoir engineers, geologists and accounting personnel for adherence to SEC guidelines through a detailed review of land records, available geological and reservoir data as well as production performance data. The review includes, but is not limited to, confirmation that reserve estimates (1) include all properties owned; (2) are based on proper working and net revenue interests; and (3) reflect reasonable cost estimates and field performance. The internal team compiles the reviewed data and forwards the data to independent consulting firms engaged to estimate our reserves. +For each of the years in the three-year period ended December 31, 2009, our reserve estimates for the Rocky Mountain Region and Fort Worth Basin, approximately 89% of our total proved reserves, are based on reserve reports prepared by Ryder Scott Company, L.P. and for the Appalachian and Michigan Basins are based on reserve reports prepared by Wright & Company. When preparing our reserve estimates, the independent engineers did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, natural gas and oil production, well test data, historical costs of operations and development, product prices, or any agreements relating to current and future operations of properties and sales of production. +The independent petroleum engineers prepare an estimate of our reserves in conjunction with an ongoing review by our engineers. A final comparison of data is performed to assure that the reserve estimates are complete, determined by acceptable industry methods and to a level of detail we deem appropriate. The final independent petroleum engineers' estimated reserve reports are reviewed and approved by our engineering staff and management. +The professional qualifications of the lead engineer primarily responsible for overseeing the preparation of our reserve estimate meet the standards of Reserves Estimator as defined in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information as promulgated by the Society of Petroleum Engineers. This employee holds a Bachelor of Science degree in Petroleum and Natural Gas Engineering and has over 25 years of experience in reservoir engineering. The individual is a member of the Society of Petroleum Engineers, allowing the individual to remain current with the developments and trends in the industry. Further, during 2009, this individual attended ten hours of formalized training relating to the definitions and disclosure guidelines set forth in the SEC's final rule released January 2009, Modernization of Oil and Gas Reporting . +The tables below present information regarding our estimated proved reserves. Reserves cannot be measured exactly, because reserve estimates involve judgments. The estimates must be reviewed periodically and adjusted to reflect additional information gained from reservoir performance, new geological and geophysical data and economic changes. Neither the present value of estimated future net cash flows nor the standardized measure is intended to represent the current market value of the estimated natural gas and oil reserves we own. For additional information regarding both of these measures, see the Natural Gas and Oil Operations section of the supplemental information provided with our consolidated financial statements included in this report. +December 31, +2009 +2008 +2007 +Proved reserves +Natural gas ( MMcf ) +608,925 +662,857 +593,563 +Oil ( MBbl ) +18,070 +15,037 +15,338 +Total proved reserves ( MMcfe ) +717,345 +753,079 +685,591 +Proved developed reserves (MMcfe) +295,839 +329,669 +317,884 +Estimated future net cash flows (in thousands) (1) +$ +764,111 +$ +1,056,890 +$ +1,847,485 +Standardized measure (in thousands) (1)(2) +$ +347,636 +$ +356,805 +$ +753,071 +(1) +Estimated future net cash flow represents the undiscounted estimated future gross revenue to be generated from the production of proved reserves, net of estimated production costs, future development costs and income tax expense. +9 +Table of Contents +Prices used to estimate future gross revenues and production and development costs were based on the following: +· +Gross revenues +· +For 2009, a 12-month average price calculated as the unweighted arithmetic average of the price on the first day of each month, January through December. +· +For 2007 and 2008, prices in effect as of December 31 for the respective year. +· +Prices for each of the three years were adjusted by lease for Btu content, transportation and regional price differences; however, they were not adjusted to reflect the value of our commodity hedges. +· +Production and development costs +· +Prices as of December 31 for each of the respective years presented. +· +The amounts shown do not give effect to non-property related expenses, such as corporate general and administrative expenses and debt service, or to depreciation, depletion and amortization expense. +(2) +The standardized measure of discounted future net cash flow represents the present value of estimated future net cash flows discounted at a rate of 10% per annum to reflect timing of future cash flows. +December 31, 2009 +Natural Gas +(MMcf) +Oil +(MBbl) +Natural Gas Equivalent +(MMcfe) +Percent +Proved developed +Rocky Mountain Region +Wattenberg +55,233 +5,675 +89,283 +30 +% +Grand Valley +101,504 +243 +102,962 +34 +% +NECO +31,463 +- +31,463 +11 +% +Other +361 +251 +1,867 +1 +% +Total Rocky Mountain Region +188,561 +6,169 +225,575 +76 +% +Appalachian Basin +55,008 +34 +55,212 +19 +% +Other +14,806 +41 +15,052 +5 +% +Total proved developed +258,375 +6,244 +295,839 +100 +% +Proved undeveloped +Rocky Mountain Region +Wattenberg +70,838 +11,552 +140,150 +33 +% +Grand Valley +273,875 +274 +275,519 +66 +% +Total Rocky Mountain Region +344,713 +11,826 +415,669 +99 +% +Appalachian +5,837 +- +5,837 +1 +% +Total proved undeveloped +350,550 +11,826 +421,506 +100 +% +Proved reserves +Rocky Mountain Region +Wattenberg +126,071 +17,227 +229,433 +32 +% +Grand Valley (1) +375,379 +517 +378,481 +53 +% +NECO +31,463 +- +31,463 +4 +% +Other +361 +251 +1,867 +- +Total Rocky Mountain Region +533,274 +17,995 +641,244 +89 +% +Appalachian +60,845 +34 +61,049 +9 +% +Other +14,806 +41 +15,052 +2 +% +Total proved reserves +608,925 +18,070 +717,345 +100 +% +(1) +Two leases in our Grand Valley Field represent 53% of our total proved reserves. +10 +Table of Contents +Production, Sales, Prices and Lifting Costs +The following table presents information regarding our production volumes, natural gas and oil sales, average sales price received and average lifting cost. +Year Ended December 31, +2009 +2008 +2007 +Production (1) (2) +Natural gas (Mcf) +35,536,092 +31,759,792 +22,513,306 +Oil (Bbls) +1,291,488 +1,160,408 +910,052 +Natural gas equivalent (Mcfe) +43,285,020 +38,722,240 +27,973,618 +Mcfe per day +118,589 +106,088 +76,640 +Natural Gas and Oil Sales (in thousands) +Natural gas +$ +110,735 +$ +221,734 +$ +119,991 +Oil +71,064 +104,168 +55,196 +Provision for underpayment of natural gas sales +(2,706 +) +(4,025 +) +- +Total natural gas and oil sales +$ +179,093 +$ +321,877 +$ +175,187 +Average Sales Price (2) +Natural gas (per Mcf) +$ +3.12 +$ +6.98 +$ +5.33 +Oil (per Bbl) +$ +55.03 +$ +89.77 +$ +60.65 +Natural gas equivalent (per Mcfe) +$ +4.20 +$ +8.42 +$ +6.26 +Average Lifting Cost (per Mcfe) (2) (3) +$ +0.83 +$ +1.07 +$ +0.90 +(1) +Production is net and determined by multiplying the gross production volume of properties in which we have an interest by the percentage of the leasehold or other property interest we own. +(2) +See Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations – Natural Gas and Oil Sales for amounts per operating area. +(3) +Lifting costs represent natural gas and oil lease operating expenses, exclusive of ad valorem and severance taxes, on a per unit basis. +Natural Gas Sales +We sell our natural gas to other gas marketers, utilities, industrial end-users and other wholesale gas purchasers. We generally sell the natural gas that we produce under contracts with indexed monthly pricing provisions. Virtually all of our contracts include provisions wherein prices change monthly with changes in the market, for which certain adjustments may be made based on whether a well delivers to a gathering or transmission line, quality of natural gas and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. As a result, our revenues from the sale of natural gas are directly proportional, holding production volume constant, to market prices; as market prices decline, so too does our revenues, and as prices increase, our revenues increase. We believe that the pricing provisions of our natural gas contracts are customary in the industry. We also enter into financial derivatives in order to reduce the impact of possible price instability regarding the physical sales market. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation: Results of Operations – Commodity Price Risk Management, Net, Natural Gas and Oil Derivative Activities and Note 4, Derivative Financial Instruments , to our consolidated financial statements included in this report. +In general, we have been and expect to continue to be able to produce and sell natural gas from our wells without significant curtailment and at competitive prices. We do, however, experience limited curtailments from time to time due to pipeline maintenance and operating issues. Open access transportation through the country's interstate pipeline system gives us access to a broad range of markets. Whenever feasible, we obtain access to multiple pipelines and markets from each of our gathering systems seeking the best available market for our natural gas at any point in time. +11 +Table of Contents +Oil Sales +Our wells in the Wattenberg Field produce natural gas as well as oil. As of December 31, 2009, oil represented 15.1% of our total equivalent reserves, and for the year then ended, accounted for approximately 17.9% of our natural gas and oil production and 39.7% of our natural gas and oil sales revenue. +We are currently able to sell all the oil that we can produce under existing sales contracts with petroleum refiners and marketers. We do not refine any of our oil production. Our crude oil production is sold to purchasers at or near our wells under both short and long-term purchase contracts with monthly pricing provisions. +Well Operations +As of December 31, 2009, we had an interest in approximately 5,000 wells. We are paid a monthly operating fee for the portion of each well we operate that is owned by others, including our sponsored partnerships. The fee is competitive with rates charged by other operators in the area. The fee covers monthly operating and accounting costs, insurance and other recurring costs. +Transportation and Gathering +We develop, own and operate gathering systems in some of our areas of operations. We also continue to construct new trunk lines as necessary to provide for the marketing of natural gas being developed from new areas and to enhance or maintain our existing systems. Pipelines and related facilities can represent a significant portion of the capital costs of developing wells, particularly in new areas located at a distance from existing pipelines. We consider these costs in our evaluation of our leasing, development and acquisition opportunities. +Our natural gas and oil are transported through our own and third party gathering systems and pipelines, and we incur processing, gathering and transportation expenses to move our natural gas from the wellhead to a purchaser-specified delivery point. These expenses vary based on the volume and distance shipped, and the fee charged by the third-party processor or transporter. Capacity on these gathering systems and pipelines is occasionally limited and at times unavailable because of repairs or improvements, or as a result of priority transportation agreements with other gas transporters. While our ability to market our natural gas has been only infrequently limited or delayed, if transportation space is restricted or is unavailable, our cash flow from the affected properties could be adversely affected. In certain instances, we enter into firm transportation agreements to provide for pipeline capacity to flow and sell a portion of our gas volumes. In order to meet pipeline specifications, we are required, in some cases, to process our gas before we can transport it. We typically contract with third parties in the Grand Valley and NECO areas of our Rocky Mountain Region and Appalachian Basin for firm transportation of our natural gas. We also may enter into firm sales agreements to ensure that we are selling to a purchaser who has contracted for pipeline capacity. These agreements are subject to the same limitations discussed above in this paragraph. See Note 11, Commitments and Contingencies , to our consolidated financial statements included in this report for our long-term firm sales, processing and transportation agreements for pipeline capacity. +Natural Gas Marketing +RNG specializes in the purchase, aggregation and sale of natural gas production in our Eastern operating areas. RNG purchases for resale natural gas produced by third party producers as well as natural gas produced by us, our affiliated partnerships and joint venture. The gas is marketed to third party marketers, natural gas utilities, as well as industrial and commercial customers, either directly through our gathering system, or through transportation services provided by regulated interstate pipeline companies. RNG's employees have extensive knowledge of natural gas markets in our areas of operations. Such knowledge assists us in maximizing our prices as we market natural gas purchased by RNG. +Our industry competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual customers. A variety of factors affect the market for natural gas, including: +· +the availability of other domestic production; +· +natural gas imports; +· +the availability and price of alternative fuels; +· +the proximity and capacity of natural gas pipelines; +· +general fluctuations in the supply and demand for natural gas; and +· +the effects of state and federal regulations on natural gas production and sales. +12 +Table of Contents +Commodity Price Risk Management Activities +We utilize commodity based derivative instruments to manage a portion of our exposure to price volatility with regard to our natural gas and oil sales and natural gas marketing. We utilize both financial and physical instruments. The financial instruments generally consist of collars, swaps and basis swaps and are NYMEX -traded and CIG and PEPL -based contracts. We may utilize derivatives based on other indices or markets where appropriate. The contracts economically provide price stability for committed and anticipated natural gas and oil purchases and sales, generally forecasted to occur within the next two to four-year period. Our policies prohibit the use of commodity derivatives for speculative purposes and permit utilization of derivatives only if there is an underlying physical position. We manage price risk on only a portion of our anticipated production, so the remaining portion of our production is subject to the full fluctuation of market pricing. +RNG has extensive experience with the use of derivatives to reduce the risk and effect of natural gas price changes. RNG uses these financial derivatives to coordinate fixed purchases and sales. We use financial derivatives to establish "floors" and "ceilings" or "collars" on the possible range of the prices realized for the sale of natural gas and oil in addition to fixing prices by using swaps. RNG also enters into back-to-back fixed-price purchases and sales contracts with counterparties. These fixed physical contracts meet the definition of a derivative. Both types of derivatives (i.e., the physical deals and the cash settled contracts) are carried on the balance sheets at fair value with changes in fair values recognized currently in the statement of operations. +We are subject to price fluctuations for natural gas sold in the spot market and under market index contracts. RNG does not always hedge the area basis risk for third party trades with back-to-back fixed price purchases and sales. We continue to evaluate the potential for reducing these risks by entering into derivative transactions. In addition, we may close out any portion of derivatives that may exist from time to time which may result in a realized gain or loss on that derivative transaction. +Governmental Regulation +While the prices of natural gas and oil are set by the market, other aspects of our business and the industry in general are heavily regulated. The availability of a ready market for natural gas and oil production depends on several factors beyond our control. These factors include regulation of production, federal and state regulations governing environmental quality and pollution control, the amount of natural gas and oil available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. State and federal regulations generally are intended to protect consumers from unfair treatment and oppressive control, to reduce the risk to the public and workers from the drilling, completion, production and transportation of natural gas and oil, to prevent waste of natural gas and oil, to protect rights among owners in a common reservoir and to control contamination of the environment. Pipelines are subject to the jurisdiction of various federal, state and local agencies. In the western part of the U.S., the federal and state governments own a large percentage of the land and the rights to develop natural gas and oil. Generally, government leases are subject to additional regulations and controls not commonly seen on private leases. We take the steps necessary to comply with applicable regulations, both on our own behalf and as part of the services we provide to our drilling partnerships. We believe that we are in compliance with such statutes, rules, regulations and governmental orders, although there can be no assurance that this is or will remain the case. The following summary discussion of the regulation of the U.S. oil and natural gas industry is not intended to constitute a complete discussion of the various statutes, rules, regulations and environmental orders to which our operations may be subject. +Regulation of Natural Gas and Oil Exploration and Production. Our exploration and production business is subject to various federal, state and local laws and regulations on the taxation of natural gas and oil, the development, production and marketing of natural gas and oil and environmental and safety matters. Many laws and regulations require drilling permits and govern the spacing of wells, rates of production, water discharge, prevention of waste and other matters. Prior to commencing drilling activities for a well, we must procure permits and/or approvals for the various stages of the drilling process from the applicable state and local agencies in the state in which the area to be drilled is located. The permits and approvals include those for the drilling of wells. Additionally, other regulated matters include: +· +bond requirements in order to drill or operate wells; +· +the location of wells; +· +the method of drilling and casing wells; +· +the surface use and restoration of well properties; +· +the plugging and abandoning of wells; and +· +the disposal of fluids. +13 +Table of Contents +Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the density of wells which may be drilled and the unitization or pooling of properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely primarily or exclusively on voluntary pooling of lands and leases. In areas where pooling is voluntary, it may be more difficult to form units, and therefore, more difficult to develop a project if the operator owns less than 100% of the leasehold. In addition, state conservation laws may establish maximum rates of production from natural gas and oil wells, generally prohibiting the venting or flaring of natural gas and imposing certain requirements regarding the ratability of production. Where wells are to be drilled on state or federal leases, additional regulations and conditions may apply. The effect of these regulations may limit the amount of natural gas and oil we can produce from our wells and may limit the number of wells or the locations at which we can drill. Such laws and regulations may increase the costs of planning, designing, drilling, installing, operating and abandoning our natural gas and oil wells and other facilities. In addition, these laws and regulations, and any others that are passed by the jurisdictions where we have production, could limit the total number of wells drilled or the allowable production from successful wells, which could limit our reserves. As a result, we are unable to predict the future cost or effect of complying with such regulations. +Regulation of Sales and Transportation of Natural Gas. Historically, the price of natural gas was subject to limitation by federal legislation. The Natural Gas Wellhead Decontrol Act removed, as of January 1, 1993, all remaining federal price controls from natural gas sold in "first sales" on or after that date. The Federal Energy Regulatory Commission's, or FERC, jurisdiction over natural gas transportation was unaffected by the Decontrol Act. +We move natural gas through pipelines owned by other companies, and sell natural gas to other companies that also utilize common carrier pipeline facilities. Natural gas pipeline interstate transmission and storage activities are subject to regulation by the FERC under the Natural Gas Act of 1938, or NGA, and under the Natural Gas Policy Act of 1978, and, as such, rates and charges for the transportation of natural gas in interstate commerce, accounting, and the extension, enlargement or abandonment of its jurisdictional facilities, among other things, are subject to regulation. Each natural gas pipeline company holds certificates of public convenience and necessity issued by the FERC authorizing ownership and operation of all pipelines, facilities and properties for which certificates are required under the NGA. Each natural gas pipeline company is also subject to the Natural Gas Pipeline Safety Act of 1968, as amended, which regulates safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities. FERC regulations govern how interstate pipelines communicate and do business with their affiliates. Interstate pipelines may not operate their pipeline systems to preferentially benefit their marketing affiliates. +Each interstate natural gas pipeline company establishes its rates primarily through the FERC’s rate-making process. Key determinants in the ratemaking process are: +· +costs of providing service, including depreciation expense; +· +allowed rate of return, including the equity component of the capital structure and related income taxes; and +· +volume throughput assumptions. +The availability, terms and cost of transportation affect our natural gas sales. In the past, FERC has undertaken various initiatives to increase competition within the industry. As a result of initiatives like FERC Order No. 636, issued in April 1992, the interstate natural gas transportation and marketing system was substantially restructured to remove various barriers and practices that historically limited non-pipeline natural gas sellers, including producers, from effectively competing with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. The most significant provisions of Order No. 636 require that interstate pipelines provide transportation separate or "unbundled" from their sales service, and require that pipelines provide firm and interruptible transportation service on an open access basis that is equal for all natural gas suppliers. In many instances, the result of Order No. 636 and related initiatives has been to substantially reduce or eliminate the interstate pipelines' traditional role as wholesalers of natural gas in favor of providing only storage and transportation services. Another effect of regulatory restructuring is greater access to transportation on interstate pipelines. In some cases, producers and marketers have benefited from this availability. However, competition among suppliers has greatly increased and traditional long-term producer-pipeline contracts are rare. Furthermore, gathering facilities of interstate pipelines are no longer regulated by FERC, thus allowing gatherers to charge higher gathering rates. Historically, producers were able to flow supplies into interstate pipelines on an interruptible basis; however, recently we have seen the increased need to acquire firm transportation on pipelines in order to avoid curtailments or shut-in-gas, which could adversely affect cash flows from the affected area. +Additional proposals and proceedings that might affect the industry occur frequently in Congress, FERC, state commissions, state legislatures, and the courts. The industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by FERC and Congress will continue. We cannot determine to what extent our future operations and earnings will be affected by new legislation, new regulations, or changes in existing regulation, at federal, state or local levels. +14 +Table of Contents +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. Public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and tougher environmental legislation and regulations is expected to continue. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs and reduced access to the industry in general, our business and prospects could be adversely affected. +We generate wastes that may be subject to the Federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes. The U.S. Environmental Protection Agency, or EPA, and various state agencies have limited the approved methods of disposal for certain hazardous and non-hazardous wastes. Furthermore, certain wastes generated by our operations that are currently exempt from treatment as "hazardous wastes" may in the future be designated as "hazardous wastes," and therefore be subject to more rigorous and costly operating and disposal requirements. +We currently own or lease numerous properties that for many years have been used for the exploration and production of natural gas and oil. Although we believe that we have utilized good operating and waste disposal practices, and when necessary, appropriate remediation techniques, prior owners and operators of these properties may not have utilized similar practices and techniques, and hydrocarbons or other wastes may have been disposed of or released on or under the properties that we own or lease or on or under locations where such wastes have been taken for disposal. These properties and the wastes disposed thereon may be subject to the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, RCRA and analogous state laws, as well as state laws governing the management of natural gas and oil wastes. Under such laws, 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) or to perform remedial plugging operations to prevent future contamination. +CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed of or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for release of hazardous substances under CERCLA may be subject to full liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and 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. As an owner and operator of natural gas and oil wells, we may be liable pursuant to CERCLA and similar state laws. +Our operations may be subject to the Clean Air Act, or CAA, and comparable state and local requirements. Amendments to the CAA were adopted in 1990 and contain provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. The EPA and states have been developing regulations to implement these requirements. We may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues. The State of Colorado has also implemented new air emission regulations in 2009, which affect the industry, including our operations. +The Federal Clean Water Act, or CWA, and analogous state laws impose strict controls against the discharge of pollutants, including spills and leaks of oil and other substances. The CWA also regulates storm water run-off from natural gas and oil facilities and requires a storm water discharge permit for certain activities. Spill prevention, control, and countermeasure requirements of the CWA require appropriate containment terms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture, or leak. +Oil production is subject to many of the same operating hazards and environmental concerns as natural gas production, but is also subject to the risk of oil spills. Federal regulations require certain owners or operators of facilities that store or otherwise handle oil, including us, to procure and implement Spill Prevention, Control and Counter-measures plans relating to the possible discharge of oil into surface waters. The Oil Pollution Act of 1990, or OPA, subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from oil spills. Noncompliance with OPA may result in varying civil and criminal penalties and liabilities. We are also subject to the CWA and analogous state laws relating to the control of water pollution, which laws provide varying civil and criminal penalties and liabilities for release of petroleum or its derivatives into surface waters or into the ground. Historically, we have not experienced any significant oil discharge or oil spill problems. +15 +Table of Contents +In 2009, the State of Colorado’s Oil and Gas Conservation Commission implemented new broad-based environmental and wildlife protection regulations for the industry. These regulations will increase our costs and may ultimately limit some drilling locations. Our expenses relating to preserving the environment have risen over the past few years and are expected to continue to rise in 2010 and beyond. Environmental regulations have had no materially adverse effect on our operations to date, but no assurance can be given that environmental regulations or interpretations of such regulations will not, in the future, result in a curtailment of production or otherwise have a materially adverse effect on our business, financial condition or results of operations. See Note 11, Commitments and Contingencies – Litigation, Colorado Stormwater Permit , to our consolidated financial statements included in this report. +Operating Hazards and Insurance +Our exploration and production operations include a variety of operating risks, including, but not limited to, the risk of fire, explosions, blowouts, cratering, pipe failure, casing collapse, abnormally pressured formations, and environmental hazards such as gas leaks, ruptures and discharges of natural gas. The occurrence of any of these could result in substantial losses to us due to injury and loss of life, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. Our pipeline, gathering and distribution operations are subject to the many hazards inherent in the industry. These hazards include damage to wells, pipelines and other related equipment, damage to property caused by hurricanes, floods, fires and other acts of God, inadvertent damage from construction equipment, leakage of natural gas and other hydrocarbons, fires and explosions and other hazards that could also result in personal injury and loss of life, pollution and suspension of operations. +Any significant problems related to our facilities could adversely affect our ability to conduct our operations. In accordance with customary industry practice, we maintain insurance against some, but not all, potential risks; however, there can be no assurance that such insurance will be adequate to cover any losses or exposure for liability. The occurrence of a significant event not fully insured against could materially adversely affect our operations and financial condition. We cannot predict whether insurance will continue to be available at premium levels that justify our purchase or whether insurance will be available at all. Furthermore, we are not insured against our economic losses resulting from damage or destruction to third party property, such as the Rockies Express pipeline; such an event could result in significantly lower regional prices or our inability to deliver gas. +Competition +We believe that our exploration, drilling and production capabilities and the experience of our management and professional staff generally enable us to compete effectively. We encounter competition from numerous other natural gas and oil companies, drilling and income programs and partnerships in all areas of operations, including drilling and marketing natural gas and oil and obtaining desirable natural gas and oil leases on producing properties. Many of these competitors possess larger staffs and greater financial resources than we do, which may enable them to identify and acquire desirable producing properties and drilling prospects more economically. Our ability to explore for natural gas and oil prospects and to acquire additional properties in the future depends upon our ability to conduct our operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. We also face intense competition in the marketing of natural gas from competitors including other producers as well as marketing companies. Also, international developments and the possible improved economics of domestic natural gas exploration may influence other companies to increase their domestic natural gas and oil exploration. Furthermore, competition among companies for favorable prospects can be expected to continue, and it is anticipated that the cost of acquiring properties may increase in the future. +During 2008, our industry experienced continued strong demand for drilling services and supplies which resulted in increasing costs. In 2009, due to industry slowdown, we experienced overall reductions in our operating and drilling costs. Factors affecting competition in the industry include price, location of drilling, availability of drilling prospects and drilling rigs, pipeline capacity, quality of production and volumes produced. We believe that we can compete effectively in the industry in each of the listed areas. Nevertheless, our business, financial condition and results of operations could be materially adversely affected by competition. We also compete with other natural gas and oil companies as well as companies in other industries for the capital we need to conduct our operations. The 2008-2009 turmoil in the capital markets made financing more expensive and difficult to obtain. In the event that we do not have adequate capital to execute our business plan, we may be forced to curtail our drilling and acquisition activities. +Employees +As of December 31, 2009, we had 326 employees, including 200 in production, 7 in natural gas marketing, 25 in exploration and development, 62 in finance, accounting and data processing, and 32 in administration. Our employees are not covered by a collective bargaining agreement. We consider relations with our employees to be very good. +16 +Table of Contents +Our engineers, supervisors and well tenders are responsible for the day-to-day operation of wells and some pipeline systems. In addition, we retain subcontractors to perform drilling, fracturing, logging, and pipeline construction functions at drilling sites, with our employees supervising the activities of the subcontractors. +IT EM 1A. RISK FACTORS +You should carefully consider the following risk factors in addition to the other information included in this report. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common stock or other securities. +Risks Related to the Global Economic Environment +There may be a reoccurrence of the 2009 global economic environment which increased the magnitude and the likelihood of the occurrence of the negative consequences discussed in many of the risks factors that follow. +In particular, consider the risks related to (1) the rapid deterioration of demand for natural gas and oil resulting from the economic environment and the related negative effects on natural gas and oil pricing, and (2) the effect of the credit constraints on our business, including the severe reduction in the availability of credit for drilling or to finance acquisitions. Also consider the interplay between these two risks: decline in natural gas and oil prices can lead to a reduction in the borrowing base for our credit line, and hence a reduction in our credit available for drilling. Similarly, further reductions in natural gas and oil prices could result in some of our assets becoming uneconomic to exploit, which would reduce our reserves, which in turn would reduce our borrowing base and the credit available to us. These factors could result in less drilling and production by us, and could thereby adversely affect our profitability and could limit our ability to execute our business plan. These factors could also make it impossible or extremely expensive to extend the term of our revolving credit line. The global economic environment also increases the potential of counterparty failure risk for both the banks which are parties to our natural gas and oil derivative holdings and for payments from purchasers of our natural gas and oil. Lastly, inability to ascertain the ultimate depth and duration of the economic environment could cause us to refrain from capital expenditures in order to maintain higher liquidity; our uncertainty and caution could result in significantly reduced drilling and hence reduced future production, which in turn may result in reduced reserves, resulting in a reduced borrowing base and availability of funds from our credit facility. All these risks could have a significant adverse effect on our business and our financial results. Any additional deterioration in the domestic or global economic conditions will further amplify these risks. +There may be a reoccurrence of the 2009 disruptions in the global financial markets and the related economic environment may further decrease the demand for natural gas and oil and the prices of natural gas and oil, thereby limiting our future drilling and production, and thereby adversely affecting our profitability. +During much of 2009, prices for natural gas and oil decreased over 60% from the 2008 peak. The well-publicized global financial market disruptions and the related economic environment may further decrease demand for natural gas and oil and therefore lower natural gas and oil prices. If there is such an additional reduction in demand, the continued production of gas may increase current oversupply and result in still lower gas prices. There is no certainty how long this low price environment will continue. We operate in a highly competitive industry, and certain competitors may have lower operating costs in such an environment. Furthermore, as a result of these disruptions in the financial markets, it is possible that in future years we would not be able to borrow or otherwise raise sufficient funds to sustain or increase capital expenditures. Such market conditions may also make it more difficult or impossible for us to finance acquisitions, through either equity or debt; acquisitions have historically been a major source of growth for us. We may also have difficulty finding partners to develop new drilling prospects and to build the pipeline systems needed to transport our gas. Inability of third parties to finance and build additional pipelines out of the Rockies and elsewhere could cause significant negative pricing effects. Any of the above factors could adversely affect our operating results. +Risks Related to Our Business and the Industry +Natural gas and oil prices fluctuate unpredictably and a decline in natural gas and oil prices can significantly affect the value of our assets, our financial results and impede our growth. +Our revenue, profitability and cash flow depend in large part upon the prices and demand for natural gas and oil. The markets for these commodities are very volatile, and even relatively modest drops in prices can significantly affect our financial results and impede our growth. Changes in natural gas and oil prices have a significant effect on our cash flow and on the value of our reserves, which can in turn reduce our borrowing base under our senior credit agreement. Prices for natural gas and oil may fluctuate widely in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and a variety of additional factors that are beyond our control, including national and international economic and political factors and federal and state legislation. The prices in much of 2009 have been too low to economically justify many drilling operations, and it is uncertain how long such low pricing shall persist. +17 +Table of Contents +The prices of natural gas and oil are volatile, often fluctuating greatly. Lower natural gas and oil prices may not only reduce our revenues, but also may reduce the amount of natural gas and oil that we can produce economically. As a result, we may have to make substantial additional downward adjustments to our estimated proved reserves. If this occurs or if our estimates of development costs increase, production data factors change or our exploration results deteriorate, accounting rules may require us to write-down operating assets to fair value, as a non-cash charge to earnings. We assess impairment of capitalized costs of proved natural gas and oil properties by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which management reasonably estimates such products may be sold. In 2009, we recorded an impairment charge of $2.8 million related to our undeveloped leasehold acreage in North Dakota, and in 2008, we recorded impairment charges totaling $12.8 million related to our proved oil and gas properties, primarily related to our properties in the Fort Worth Basin and in North Dakota. There were no impairment charges recorded during 2007. We may incur impairment charges in the future, which could have a material adverse effect on the results of our operations. +A substantial part of our natural gas and oil production is located in the Rocky Mountain Region, making it vulnerable to risks associated with operating primarily in a single geographic area. +Our operations have been focused on the Rocky Mountain Region, which means our current producing properties and new drilling opportunities are geographically concentrated in that area. Because our operations are not as diversified geographically as many of our competitors, the success of our operations and our profitability may be disproportionately exposed to the effect of any regional events, including fluctuations in prices of natural gas and oil produced from the wells in the region, natural disasters, restrictive governmental regulations, transportation capacity constraints, curtailment of production or interruption of transportation, and any resulting delays or interruptions of production from existing or planned new wells. +Historically, natural gas prices in the Rocky Mountain Region often fell disproportionately when compared to other markets, due in part to continuing constraints in transporting natural gas from producing properties in the region. Because of the concentration of our operations in the Rocky Mountain Region, such price decreases are more likely to have a material adverse effect on our revenue, profitability and cash flow than those of our more geographically diverse competitors. Although current natural gas prices in the Rocky Mountain Region are not steeply discounted to NYMEX, there can be no assurance as to such continuation. +Our estimated natural gas and oil reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves. +Natural gas and oil reserve engineering requires subjective estimates of underground accumulations of natural gas and oil and assumptions concerning future natural gas and oil prices, production levels, and operating and development costs over the economic life of the properties. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be inaccurate. Independent petroleum engineers prepare our estimates of natural gas and oil reserves using pricing, production, cost, tax and other information that we provide. The reserve estimates are based on certain assumptions regarding future natural gas and oil prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect: +· +the estimates of reserves; +· +the economically recoverable quantities of natural gas and oil attributable to any particular group of properties; +· +future depreciation, depletion and amortization ("DD&A") rates and amounts; +· +impairments in the value of our assets; +· +the classifications of reserves based on risk of recovery; +· +estimates of the future net cash flows; and +· +timing of our capital expenditures. +Some of our reserve estimates must be made with limited production history, which renders these reserve estimates less reliable than estimates based on a longer production history. Numerous changes over time to the assumptions on which the reserve estimates are based, as described above, often result in the actual quantities of natural gas and oil recovered being different from earlier reserve estimates. +18 +Table of Contents +The present value of our estimated future net cash flows from proved reserves is not necessarily the same as the current market value of our estimated natural gas and oil reserves. As of December 31, 2009, the estimated discounted future net cash flows from proved reserves are based on prior year average prices, and are no longer based on selling prices in effect at year end. However, factors such as actual prices we receive for natural gas and oil and hedging instruments, the amount and timing of actual production, amount and timing of future development costs, supply of and demand for natural gas and oil, and changes in governmental regulations or taxation also affect our actual future net cash flows from our natural gas and oil properties. +The timing of both our production and incurrence of expenses in connection with the development and production of natural gas and oil properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor (the rate required by the SEC) we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates currently in effect and risks associated with our natural gas and oil properties or the industry in general. +Unless natural gas and oil reserves are replaced as they are produced, our reserves and production will decline, which would adversely affect our future business, financial condition and results of operations. +Producing natural gas and oil reservoirs generally is characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The rate of decline will change if production from existing wells declines in a different manner than we estimated and the rate can change due to other circumstances. Thus, our future natural gas and oil reserves and production and, therefore, our cash flow and income, are highly dependent on efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, discover or acquire additional reserves to replace our current and future production at acceptable costs. As a result, our future operations, financial condition and results of operations would be adversely affected. +Acquisitions are subject to the uncertainties of evaluating recoverable reserves and potential liabilities. +Acquisitions of producing properties and undeveloped properties have been an important part of our historical growth. We expect acquisitions will also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, many of which are beyond our control. These factors include recoverable reserves, development potential, future natural gas and oil prices, operating costs and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform engineering, geological and geophysical reviews of the acquired properties, which we believe is generally consistent with industry practices. However, such reviews are not likely to permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well prior to an acquisition and our ability to evaluate undeveloped acreage is inherently imprecise. Even when we inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise. In some cases, our review prior to signing a definitive purchase agreement may be even more limited. +Our focus on acquiring producing natural gas and oil properties may increase our potential exposure to liabilities and costs for environmental and other problems existing on acquired properties. Often we are not entitled to contractual indemnification associated with acquired properties. Normally, we acquire interests in properties on an "as is" basis with no or limited remedies for breaches of representations and warranties, as was the case in the acquisitions of assets from EXCO Resources Inc. and Castle Gas Company, as well as the acquisition of all shares of Unioil, Inc. We could incur significant unknown liabilities, including environmental liabilities, or experience losses due to title defects, in our acquisitions for which we have limited or no contractual remedies or insurance coverage. +Additionally, significant acquisitions can change the nature of our operations 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. For example, in the Castle acquisition, we acquired interests in wells which we will need to operate together with other partners, we acquired pipelines that we will need to operate and expect we will need to commit to drilling in the acquired areas to achieve the expected benefits. Consequently, we may not be able to efficiently realize the assumed or expected economic benefits of properties that we acquire, if at all. +19 +Table of Contents +When drilling prospects, we may not yield natural gas or oil in commercially viable quantities. +A prospect is a property on which our geologists have identified what they believe, based on available information, to be indications of natural gas or oil bearing rocks. However, our geologists cannot know conclusively prior to drilling and testing whether natural gas or oil will be present or, if present, whether natural gas or oil will be present in sufficient quantities to repay drilling or completion costs and generate a profit given the available data and technology. If a well is determined to be dry or uneconomic, which can occur even though it contains some oil or natural gas, it is classified as a dry hole and must be plugged and abandoned in accordance with applicable regulations. This generally results in the loss of the entire cost of drilling and completion to that point, the cost of plugging, and lease costs associated with the prospect. Even wells that are completed and placed into production may not produce sufficient natural gas and oil to be profitable. If we drill a dry hole or unprofitable well on current and future prospects, the profitability of our operations will decline and our value will likely be reduced. In sum, the cost of drilling, completing and operating any well is often uncertain and new wells may not be productive. +We may not be able to identify enough attractive prospects on a timely basis to meet our development needs, which could limit our future development opportunities. +Our geologists have identified a number of potential drilling locations on our existing acreage. These drilling locations must be replaced as they are drilled for us to continue to grow our reserves and production. Our ability to identify and acquire new drilling locations depends on a number of uncertainties, including the availability of capital, regulatory approvals, natural gas and oil prices, competition, costs, availability of drilling rigs, drilling results and the ability of our geologists to successfully identify potentially successful new areas to develop. Because of these uncertainties, our profitability and growth opportunities may be limited by the timely availability of new drilling locations. As a result, our operations and profitability could be adversely affected. +Drilling for and producing natural gas and oil are high risk activities with many uncertainties that could adversely affect our business, financial condition and results of operations. +Drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for natural gas and oil can be unprofitable, not only due to dry holes, but also due to curtailments, delays or cancellations as a result of other factors, including: +• unusual or unexpected geological formations; +• pressures; +• fires; +• blowouts; +• loss of drilling fluid circulation; +• title problems; +• facility or equipment malfunctions; +• unexpected operational events; +• shortages or delivery delays of equipment and services; +• compliance with environmental and other governmental requirements; and +• adverse weather conditions. +Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and regulatory penalties. We maintain insurance against various losses and liabilities arising from operations; however, insurance against all operational risks is not available. Additionally, our management may elect not to obtain insurance if the cost of available insurance is excessive relative to the perceived risks presented. Thus, losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business activities, financial condition and results of operations. +20 +Table of Contents +Under the "successful efforts" accounting method that we use, unsuccessful exploratory wells must be expensed in the period when they are determined to be non-productive, which reduces our net income in such periods and could have a negative effect on our profitability. +We have conducted exploratory drilling and plan to continue exploratory drilling in 2010 in order to identify additional opportunities for future development. Under the "successful efforts" method of accounting that we use, the cost of unsuccessful exploratory wells must be charged to expense in the period when they are determined to be unsuccessful. In addition, lease costs for acreage condemned by the unsuccessful well must also be expensed. In contrast, unsuccessful development wells are capitalized as a part of the investment in the field where they are located. Because exploratory wells generally are more likely to be unsuccessful than development wells, we anticipate that some or all of our exploratory wells may not be productive. The costs of such unsuccessful exploratory wells could result in a significant reduction in our profitability in periods when the costs are required to be expensed and have a negative effect on our debt covenants. +Increasing finding and development costs may impair our profitability. +In order to continue to grow and maintain our profitability, we must annually add new reserves that exceed our yearly production at a finding and development cost that yields an acceptable operating margin and DD&A rate. Without cost effective exploration, development or acquisition activities, our production, reserves and profitability will decline over time. Given the relative maturity of most natural gas and oil basins in North America and the high level of activity in the industry, the cost of finding new reserves through exploration and development operations has been increasing. The acquisition market for natural gas and oil properties has become extremely competitive among producers for additional production and expanded drilling opportunities in North America. Acquisition values climbed toward historic highs during 2007 and the first half of 2008 on a per unit basis, particularly in the Rocky Mountain Region, and although 2009 pricing multiples were stable these values may continue to increase in the future. This increase in finding and development costs results in higher DD&A rates. If the upward trend in finding and development costs continues, we will be exposed to an increased likelihood of a write-down in carrying value of our natural gas and oil properties in response to falling commodity prices and reduced profitability of our operations. +Our development and exploration operations require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our natural gas and oil reserves, and ultimately our profitability. +The industry is capital intensive. We expect to continue to make substantial capital expenditures in our business and operations for the exploration, development, production and acquisition of natural gas and oil reserves. To date, we have financed capital expenditures primarily with bank borrowings, cash generated by operations and our 2008 senior note issuance. We intend to finance our future capital expenditures with cash flow from operations, funds from our 2009 sale of equity, capital contributed to our joint venture by our joint venture partner and other existing and planned financing arrangements. Our cash flows from operations and access to capital are subject to a number of variables, including: +• our proved reserves; +• the amount of natural gas and oil we are able to produce from existing wells; +• the prices at which natural gas and oil are sold; +• the costs to produce natural gas and oil; and +• our ability to acquire, locate and produce new reserves. +If our revenues or the borrowing base under our credit facility decreases as a result of lower natural gas and oil prices, operating difficulties, declines in reserves or for any other reason, then we may have limited ability to obtain the capital necessary to sustain our operations at current levels. We may, from time to time, need to seek additional financing. There can be no assurance as to the availability or terms of any additional financing. +If our revenues or the borrowing base under our revolving credit facility decrease as a result of lower natural gas and oil prices, or we incur operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at planned levels, and our profitability may be adversely affected. +If additional capital is needed, we may not be able to obtain debt or equity financing on favorable terms, or at all. If cash generated by our operations or sale of drilling partnerships or available under our revolving credit facility is not sufficient to meet our capital requirements, failure to obtain additional financing could result in a curtailment of the exploration and development of our prospects, which in turn could lead to a possible loss of properties, decline in natural gas and oil reserves and a decline in our profitability. +21 +Table of Contents +Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate. +Seasonal weather conditions and lease stipulations designed to protect various wildlife affect natural gas and oil operations in the Rocky Mountains. In certain areas, including parts of the Piceance Basin in Colorado, drilling and other natural gas and oil activities are restricted or prohibited by lease stipulations, or prevented by weather conditions, for up to six months out of the year. This limits our operations in those areas and can intensify competition during those months for drilling rigs, oil field equipment, services, supplies and qualified personnel, which may lead to additional or increased costs or periodic shortages. These constraints and the resulting high costs or shortages could delay our operations and materially increase operating and capital costs and therefore adversely affect our profitability. +We have limited control over activities on properties in which we own an interest but we do not operate, which could reduce our production and revenues. +We operate most of the wells in which we own an interest. However, there are some wells we do not operate because we participate through joint operating agreements under which we own partial interests in natural gas and oil properties operated by other entities. If we do not operate the properties in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of underlying properties. The failure by an operator to adequately perform operations, or an operator’s breach of the applicable agreements, could reduce production and revenues and affect our profitability. The success and timing of drilling and development activities on properties operated by others therefore depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise (including safety and environmental compliance) and financial resources, inclusion of other participants in drilling wells, and use of technology. +Market conditions or operational impediments could hinder our access to natural gas and oil markets or delay production. +Market conditions or the unavailability of satisfactory natural gas and oil transportation arrangements may hinder our access to natural gas and oil markets or delay our production. The availability of a ready market for natural gas and oil production depends on a number of factors, including the demand for and supply of natural gas and oil and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells for the lack of a market or because of inadequacy, unavailability or the pricing associated with natural gas pipelines, gathering system capacity or processing facilities. If that were to occur, we would be unable to realize revenue from those wells until we made production arrangements to deliver the product to market. Thus, our profitability would be adversely affected. +Our derivative activities could result in financial losses or reduced income from failure to perform by our counterparties or from changes in prices. +We use derivatives for a portion of our natural gas and oil production from our own wells, our partnerships and for natural gas purchases and sales by our marketing subsidiary to achieve a more predictable cash flow, to reduce exposure to adverse fluctuations in the prices of natural gas and oil, and to allow our natural gas marketing company to offer pricing options to natural gas sellers and purchasers. These arrangements expose us to the risk of financial loss in some circumstances, including when purchases or sales are different than expected, the counter-party to the derivative contract defaults on its contract obligations, or when there is a change in the expected differential between the underlying price in the derivative agreement and actual prices that we receive. +In addition, derivative arrangements may limit the benefit from changes in the prices for natural gas and oil and may require the use of our resources to meet cash margin requirements. Since we do not designate our derivatives as hedges, we do not currently qualify for use of hedge accounting; therefore, changes in the fair value of derivatives are recorded in our income statements, and our net income is subject to greater volatility than if our derivative instruments qualified for hedge accounting. For instance, if natural gas and oil prices rise significantly, it could result in significant non-cash charges each quarter, which could have a material negative effect on our net income. +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 natural gas and oil sales or joint interest billings to a small number of third parties in the energy industry. This concentration of customers and joint interest owners may affect our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, our natural gas and oil derivatives as well as the derivatives used by our marketing subsidiary expose us to credit risk in the event of nonperformance by counterparties. +22 +Table of Contents +Terrorist attacks or similar hostilities may adversely affect our results of operations. +Increasing terrorist attacks around the world have created many economic and political uncertainties, some of which may materially adversely affect our business. Uncertainty surrounding military strikes or a sustained military campaign may affect our operations in unpredictable ways, including disruptions of fuel supplies and markets, particularly oil, and the possibility that infrastructure facilities, including pipelines, production facilities, processing plants and refineries, could be direct targets of, or indirect casualties of, an act of terror or war. The continuation of these attacks may subject our operations to increased risks and, depending on their ultimate magnitude, could have a material adverse effect on our business, results of operations, financial condition and prospects. +Our insurance coverage may not be sufficient to cover some liabilities or losses that we may incur. +The occurrence of a significant accident or other event not fully covered by insurance could have a material adverse effect on our operations and financial condition. Insurance does not protect us against all operational risks. We do not carry business interruption insurance at levels that would provide enough funds for us to continue operating without access to other funds. For some risks, such as drilling blow-out insurance, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks that we are subject to are generally not fully insurable. +We may not be able to keep pace with technological developments in our industry. +The industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement those new technologies at substantial cost. In addition, other natural gas and oil companies 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. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we were unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected. +Competition in the industry is intense, which may adversely affect our ability to succeed. +The industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce natural gas and oil, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive natural gas and oil properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than we can. In addition, these companies may have a greater ability to continue exploration activities during periods of low natural gas and oil market prices. Larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which can adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because many companies in our industry have greater financial and human resources, we may be at a disadvantage in bidding for exploratory prospects and producing natural gas and oil properties. These factors could adversely affect the success of our operations and our profitability. +The current trend is to increase regulation of our operations and industry. We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business. +Our exploration, development, production and marketing operations are regulated extensively at the federal, state and local levels. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon natural gas and oil wells. Under these laws and regulations, we could also be liable for personal injuries, property damage and other damages. Failure to comply with these laws and regulations may result in the suspension or termination of operations and subject us to administrative, civil and criminal penalties. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects. +23 +Table of Contents +Part of the regulatory environment includes federal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing exploration and production activities. In addition, our activities are subject to the regulation of conservation practices and protection of correlative rights by state governments. These regulations affect our operations, increase our costs of exploration and production and limit the quantity of natural gas and oil that we can produce and market. A major risk inherent in our drilling plans is the need to obtain drilling permits from state and local authorities. Delays in obtaining regulatory approvals, drilling permits, 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. Additionally, the natural gas and oil regulatory environment could change in ways that might substantially increase our financial and managerial costs to comply with the requirements of these laws and regulations and, consequently, adversely affect our profitability. Furthermore, these additional costs may put us at a competitive disadvantage compared to larger companies in the industry which can spread such additional costs over a greater number of wells and larger operating staff. +Illustrative of this trend are the regulations implemented in 2009 by the State of Colorado, which focus on the industry. These multi-faceted regulations significantly enhance requirements regarding natural gas and oil permitting, environmental requirements and wildlife protection. Permitting delays and increased costs could result from these final regulations. +Other potential laws and regulations affecting us include the following: +· +State and federal initiatives to further regulate hydraulic fracturing, including the so-called “Frac Act,” which would amend the Federal Drinking Water Act, if adopted, would require disclosure of chemicals used in fracturing as well as other restrictions, which could lead to operational delays and increased costs. +· +The 2011 federal budget, as initially proposed, contains several provisions harmful to the oil and gas industry; most importantly it would limit our ability to deduct intangible drilling costs in the year incurred, as provided under current law. This could have an adverse financial effect on us and on the economic viability of any future drilling. +· +Several bills in Congress, if passed, would establish a "cap and trade" system regarding greenhouse gas emissions. Companies would be assigned emission "allowances" under these bills which would decline each year. In addition, new EPA greenhouse gas monitoring and reporting regulations may affect us and the third parties that process our oil and natural gas. +· +Several federal regulatory proposals, if they became law, would limit the use of over-the-counter (OTC) derivatives, including the oil and gas price hedging we currently use. Limits on the use of OTC instruments could impair our use of these derivatives and could limit our ability to protect our cash flows and reduce oil and gas price risk. +· +New or increased severance taxes have been proposed in several states, including Pennsylvania. This could adversely affect the existing operations in these states and the economic viability of future drilling. +Litigation has been commenced against us pertaining to our royalty practices and payments; the cost of our defending these lawsuits, and any future similar lawsuit, could be significant and any resulting judgments against us could have a material adverse effect upon our financial condition. +In recent years, litigation has commenced against us and several other companies in our industry regarding royalty practices and payments in jurisdictions where we conduct business. For more information on the suits that currently relate to us, see Note 11, Commitments and Contingencies , to our consolidated financial statements included in this report. We intend to defend ourselves vigorously in these cases. Even if the ultimate outcome of this litigation resulted in our dismissal, defense costs could be significant. These costs would be reflected in terms of dollar outlay as well as the amount of time, attention and other resources that our management would have to appropriate to the defense. Although we cannot predict an eventual outcome of this litigation, a judgment in favor of a plaintiff could have a material adverse effect on our financial condition or profitability. +Any future failure to maintain effective internal control over financial reporting and/or effective disclosure controls and procedures could have a material adverse effect on the reliability of our financial statements and our ability to file public reports on time, raise capital and meet our debt obligations. +Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2008 and 2009, and pursuant to those assessments, concluded that we did maintain effective internal control over financial reporting as of December 31, 2008 and 2009. However, as of December 31, 2007, management’s assessment of the effectiveness of our internal control over financial reporting identified two material weaknesses as disclosed in our Annual Report on Form 10-K for the year then ended and filed with the SEC on March 20, 2008. The existence of a material weakness means there is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. +24 +Table of Contents +Any future failure to maintain effective internal control over financial reporting and/or effective disclosure controls and procedures could prevent us from being able to prevent fraud and/or provide reliable financial statements and other public reports. Such circumstances could harm our business and operating results, cause investors to lose confidence in the accuracy and completeness of our financial statements and reports, and have a material adverse effect on the trading price of our debt and equity securities and our ability to raise capital necessary for our operations. These failures may also adversely affect our ability to file our periodic reports with the SEC on time. Being late in filing our periodic reports with the SEC may result in the delisting of our common stock from the NASDAQ Stock Market or a default under our senior credit agreement, the indenture governing our outstanding 12% senior notes due 2018, and any other instruments governing debt that we may incur in the future. Ultimately, such defaults could lead to the acceleration of our debt obligations, and if an acceleration of our debt obligations were to occur, we may not have sufficient funds to repay those obligations immediately, and we would be forced to seek alternative repayment arrangements either through a bankruptcy or an out of court debt restructuring. Consequently, a future material weakness could lead to significant and negative changes to our financial condition and the value of our equity and debt securities. +Risks Associated with Our Indebtedness +Our credit facility has substantial restrictions and financial covenants and we may have difficulty obtaining additional credit, which could adversely affect our operations. Our lenders can unilaterally reduce our borrowing availability based on anticipated sustained natural gas and oil prices. +We depend on our revolving credit facility for future capital needs. The terms of the borrowing agreement require us to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flows from operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants under the revolving credit facility or other debt financing could result in a default under those facilities, which could cause all of our existing indebtedness to be immediately due and payable. +The revolving credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion based upon projected revenues from the natural gas and oil properties securing their loan. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the revolving credit facility. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other natural gas and oil properties as additional collateral. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under the revolving credit facility. Our inability to borrow additional funds under our credit facility could adversely affect our operations and our financial results. +The indenture governing our outstanding senior notes and our senior credit agreement impose (and we anticipate that the indentures governing any other debt securities we may issue will also impose) restrictions on us that may limit the discretion of management in operating our business. That, in turn, could impair our ability to meet our obligations. +The indenture governing our outstanding senior notes and our senior credit agreement contain (and we anticipate that the indentures governing any other debt securities we may issue will also contain) various restrictive covenants that limit management’s discretion in operating our business. In particular, these covenants limit our ability to, among other things: +• incur additional debt; +• make certain investments or pay dividends or distributions on our capital stock, or purchase, redeem or retire capital stock; +• sell assets, including capital stock of our restricted subsidiaries; +• restrict dividends or other payments by restricted subsidiaries; +• create liens; +• enter into transactions with affiliates; and +• merge or consolidate with another company. +These covenants could materially and adversely affect our ability to finance our future operations or capital needs. Furthermore, they may restrict our ability to expand, to pursue our business strategies and otherwise conduct our business. Our ability to comply with these covenants may be affected by circumstances and events beyond our control, such as prevailing economic conditions and changes in regulations, and we cannot assure you that we will be able to comply with them. A breach of any of these covenants could result in a default under the indenture governing our outstanding senior notes and any other debt securities we may issue in the future and/or our senior credit agreement. If there were an event of default under our indenture and/or the senior credit agreement, the affected creditors could cause all amounts borrowed under these instruments to be due and payable immediately. Additionally, if we fail to repay indebtedness under our senior credit agreement when it becomes due, the lenders under the senior credit agreement could proceed against the assets which we have pledged to them as security. Our assets and cash flow might not be sufficient to repay our outstanding debt in the event of a default. The occurrence of such an event would adversely affect our operations and profitability. +25 +Table of Contents +Our senior credit agreement also requires us to maintain specified financial ratios and satisfy certain financial tests. Our ability to maintain or meet such financial ratios and tests may be affected by events beyond our control, including changes in general economic and business conditions, and we cannot assure you that we will maintain or meet such ratios and tests, or that the lenders under the senior credit agreement will waive any failure to meet such ratios or tests. +In addition, upon a change in control, we are required to offer to buy each senior note for 101% of the principal amount, plus unpaid interest. A change in control is defined to include: (i) when a majority of the Board of Directors are not continuing directors; (ii) when one person (or group of related persons) holds direct or indirect ownership of over 50% of our voting stock; or (iii) upon sale, transfer or lease of substantially all of our assets. +We may incur additional indebtedness to facilitate our acquisition of additional properties, which would increase our leverage and could negatively affect our business or financial condition. +Our business strategy includes the acquisition of additional properties that we believe would have a positive effect on our current business and operations. We expect to continue to pursue acquisitions of such properties and may incur additional indebtedness to finance the acquisitions. Our incurrence of additional indebtedness would increase our leverage and our interest expense, which could have a negative effect on our business or financial condition. +If we fail to obtain additional financing, we may be unable to refinance our existing debt, expand our current operations or acquire new businesses. This could result in our failure to grow in accordance with our plans, or could result in defaults in our obligations under our senior credit agreement or the indenture relating to our outstanding senior notes. +In order to refinance indebtedness, expand existing operations and acquire additional businesses or properties, we will require substantial amounts of capital. There can be no assurance that financing, whether from equity or debt financings or other sources, will be available or, if available, will be on terms satisfactory to us. If we are unable to obtain such financing, we will be unable to acquire additional businesses or properties and may be unable to meet our obligations under our senior credit agreement and the indenture relating to our outstanding senior notes or any other debt securities we may issue in the future. Such an event would adversely affect our operations and profitability. +Risks Associated with Our Joint Venture +The PDC Mountaineer LLC joint venture is dependent upon our equity partner (the “Investor”) and poses exit-related risks for us. +The board of managers of the joint venture consists of three representatives appointed by us and three representatives appointed by the Investor, each with equal voting power. The joint venture agreement generally requires the affirmative vote of a majority of the members of the board to approve an action, and we and the Investor may not always agree on the best course of action for the joint venture. If such a disagreement were to occur, we would not be able to cause the joint venture to take action that we believed to be in the best interests of the joint venture. Consequently, our best interests may not be advanced and our investment in the joint venture could be adversely affected. If there is a disagreement about a development plan and budget for the joint venture, the Investor is entitled to unilaterally suspend substantially all of the operations of the joint venture, which could have a material adverse impact on the results of operations of the joint venture and our investment. Such a suspension could last for up to two years, at which point either party could elect to dissolve the joint venture or to sell their ownership interests to a third party. The Investor is entitled to a preference with respect to liquidating distributions and proceeds from significant sales of ownership interests up to the amount of its contributed capital, which would diminish our returns if the value of the joint venture had declined at the time of the liquidation or sale. +After a “restricted period” which generally lasts for the four year years following the closing of the joint venture, the Investor can seek to sell its interest in the joint venture to a third party, subject to rights of first offer and refusal in favor of us. If we do not exercise those rights in a sale involving all of the Investor’s ownership interests, the Investor can exercise “drag-along” rights and compel us to sell all of our interests in the proposed transaction. Accordingly, if we possessed insufficient funds and were unable to obtain financing necessary to purchase the Investor’s interest under the rights of first offer and refusal, we may be required to sell our interest in the joint venture at a time when we may not wish to do so. Under these circumstances, our investment in the joint venture could be adversely affected. +IT EM 1B. UNRESOLVED STAFF COMMENTS +None. +26 +Table of Contents +IT EM 2. PROPERTIES +Information regarding our wells, production, proved reserves and acreage are included in Item 1 – Business and in Note 2, Summary of Significant Accounting Policies , to our consolidated financial statements included in this report. +Substantially all of our natural gas and oil properties, exclusive of our joint venture properties, have been mortgaged or pledged as security for our credit facility. Substantially all of our joint venture properties have, however, been pledged as collateral for the joint venture's derivative instruments. See Note 4, Derivative Financial Instruments , and Note 8, Long Term Debt , to our consolidated financial statements included in this report. +Facilities +We lease 26,480 square feet in downtown Denver, Colorado, which serves as our corporate offices, through September 2015. We own a 32,000 square feet administrative office building located in Bridgeport, West Virginia where we also lease approximately 5,000 and 17,700 square feet of office space in two additional buildings through March 2010 and October 2011, respectively. +We own or lease field operating facilities in the following locations: +· +West Virginia: Bridgeport and Glenville +· +Michigan: Ossineke +· +Colorado: Evans, Parachute and Wray +· +Pennsylvania: Indiana and Mahaffey +IT EM 3. LEGAL PROCEEDINGS +Information regarding our legal proceedings can be found in Note 11, Commitments and Contingencies – Litigation, to our consolidated financial statements included in this report. +IT EM 4. [RESERVED] +PART II +IT EM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDERS MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES +Our authorized capital stock consists of 100,000,000 shares of common stock, par value $0.01 per share. Our common stock is traded on the NASDAQ Global Select Market under the ticker symbol PETD. The following table presents the range of high and low sales prices for our common stock for each of the periods presented. +Price Range +High +Low +January 1 - March 31, 2008 +$ +73.92 +$ +50.75 +April 1 - June 30, 2008 +79.09 +66.37 +July 1 - September 30, 2008 +68.76 +34.15 +October 1 - December 31, 2008 +44.75 +11.50 +January 1 - March 31, 2009 +27.91 +9.39 +April 1 - June 30, 2009 +20.63 +11.21 +July 1 - September 30, 2009 +19.14 +12.50 +October 1 - December 31, 2009 +21.87 +16.06 +As of February 16, 2010, we had approximately 1,076 shareholders of record. +We have not paid any dividends on our common stock and currently intend to retain earnings for use in our business. We do not expect to declare cash dividends in the foreseeable future. +27 +Table of Contents +The following table presents information about our purchases of our common stock during the three months ended December 31, 2009. +Period +Total Number +of Shares +Purchased (1) +Average Price +Paid per Share +Total Number +of Shares +Purchased as +Part of Publicly +Announced Plans +or Programs +Maximum Number +of Shares that May +Yet Be Purchased +Under the Plans +or Programs +October 1 - 31, 2009 +796 +$ +17.59 +- +- +November 1-30, 2009 +2,029 +18.06 +- +- +December 1-31, 2009 +329 +18.21 +- +- +Total fourth quarter purchases +3,154 +17.95 +(1) +Purchases represent shares purchased pursuant to our stock-based compensation plans for payment of tax liabilities related to the vesting of securities and shares purchased pursuant to our non-employee director deferred compensation plan. +SHAREHOLDER PERFORMANCE GRAPH +The performance graph below compares the cumulative total return of our common stock over the five-year period ended December 31, 2009, with the cumulative total returns for the same period for the Standard Industrial Code ("SIC") Index, and the Standard and Poor's ("S&P") 500 Index. The SIC Index is a weighted composite of 386 crude petroleum and natural gas companies. The cumulative total shareholder return assumes that $100 was invested, including reinvestment of dividends, if any, in our common stock on December 31, 2004, and in the S&P 500 Index and the SIC Index on the same date. The results shown in the graph below are not necessarily indicative of future performance. +Year Ended December 31, +2004 +2005 +2006 +2007 +2008 +2009 +Petroleum Development Corporation +$ +100.00 +$ +86.44 +$ +111.62 +$ +153.31 +$ +62.41 +$ +47.21 +S&P 500 Index +100.00 +104.91 +121.48 +128.16 +80.74 +102.11 +SIC Index +100.00 +143.67 +186.81 +262.61 +153.66 +206.42 +28 +Table of Contents +IT EM 6. SELECTED FINANCIAL DATA +Year Ended December 31, +2009 +2008 +2007 +2006 +2005 +(in thousands, except per share data) +Revenues: +Natural gas and oil sales +$ +179,093 +$ +321,877 +$ +175,187 +$ +115,189 +$ +102,559 +Sales from natural gas marketing +64,635 +140,263 +103,624 +131,325 +121,104 +Commodity price risk management gain (loss), net (1) +(10,053 +) +127,838 +2,756 +9,147 +(9,368 +) +Well operations, pipeline income and other +11,043 +11,767 +10,170 +11,576 +9,198 +Total revenues +244,718 +601,745 +291,737 +267,237 +223,493 +Costs and expenses: +Natural gas and oil production and well operations costs +64,746 +79,354 +49,833 +29,981 +21,090 +Cost of natural gas marketing +62,534 +139,234 +100,584 +130,150 +119,644 +Exploration expense and impairment of natural gas and oil properties +22,887 +45,105 +23,551 +8,131 +11,115 +General and administrative expense +53,985 +37,715 +30,968 +19,047 +6,960 +Depreciation, depletion and amortization +131,004 +104,640 +70,885 +33,735 +21,116 +Total costs and expenses +335,156 +406,048 +275,821 +221,044 +179,925 +Gain on sale of leaseholds (2) +470 +- +33,291 +328,000 +7,669 +Income (loss) from operations +(89,968 +) +195,697 +49,207 +374,193 +51,237 +Interest income +254 +591 +2,662 +8,050 +898 +Interest expense +(37,208 +) +(28,132 +) +(9,279 +) +(2,443 +) +(217 +) +Income (loss) from continuing operations before income taxes +(126,922 +) +168,156 +42,590 +379,800 +51,918 +Provision (benefit) for income taxes +(45,716 +) +59,089 +16,505 +146,698 +19,373 +Income (loss) from continuing operations +(81,206 +) +109,067 +26,085 +233,102 +32,545 +Income from discontinued operations, net of tax (3) +113 +4,177 +7,083 +4,670 +8,907 +Net income (loss) +(81,093 +) +113,244 +33,168 +237,772 +41,452 +Less: net loss attributable to noncontrolling interests +(1,816 +) +(65 +) +(41 +) +- +- +Net income (loss) attributable to shareholders +$ +(79,277 +) +$ +113,309 +$ +33,209 +$ +237,772 +$ +41,452 +Amounts attributable to Petroleum Development Corporation shareholders: +Income (loss) from continuing operations +$ +(79,390 +) +$ +109,132 +$ +26,126 +$ +233,102 +$ +32,545 +Income from discontinued operations, net of tax +113 +4,177 +7,083 +4,670 +8,907 +Net income (loss) attributable to shareholders +$ +(79,277 +) +$ +113,309 +$ +33,209 +$ +237,772 +$ +41,452 +Earnings (loss) per share attributable to shareholders: +Basic +Income (loss) from continuing operations +$ +(4.83 +) +$ +7.41 +$ +1.77 +$ +14.88 +$ +1.99 +Income from discontinued operations +0.01 +0.28 +0.48 +0.30 +0.54 +Net income (loss) attributable to shareholders +$ +(4.82 +) +$ +7.69 +$ +2.25 +$ +15.18 +$ +2.53 +Diluted +Income (loss) from continuing operations +$ +(4.83 +) +$ +7.35 +$ +1.76 +$ +14.81 +$ +1.98 +Income from discontinued operations +0.01 +0.28 +0.48 +0.30 +0.54 +Net income (loss) attributable to shareholders +$ +(4.82 +) +$ +7.63 +$ +2.24 +$ +15.11 +$ +2.52 +As of December 31, +2009 +2008 +2007 +2006 +2005 +(in thousands) +Total assets +$ +1,250,327 +$ +1,402,704 +$ +1,050,479 +$ +884,287 +$ +444,361 +Working capital (deficit) +$ +32,936 +$ +31,266 +$ +(50,212 +) +$ +29,180 +$ +(16,763 +) +Long-term debt +$ +280,657 +$ +394,867 +$ +235,000 +$ +117,000 +$ +24,000 +Equity +$ +538,593 +$ +512,275 +$ +396,285 +$ +360,144 +$ +188,265 +______________ +(1) +See Note 4, Derivative Financial Instruments, to our consolidated financial statements included in this report. +(2) +In July 2006, we sold a portion of our undeveloped leasehold located in Grand Valley Field, Garfield County, Colorado. See Note 17, Sale of Natural Gas and Oil Properties, to our consolidated financial statements included in this report. +(3) +See Note 16, Discontinued Operations, to our consolidated financial statements included in this report. +29 +Table of Contents +IT EM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +The following discussion and analysis, as well as other sections in this report, should be read in conjunction with our consolidated financial statements and related notes to consolidated financial statements included in this report. Further, we encourage you to revisit Special Note Regarding Forward-Looking Statements on page 1 of this report. +Non-GAAP Financial Measures +We use "adjusted cash flow from operations," "adjusted net income (loss) attributable to shareholders" and "adjusted EBITDA," non-GAAP financial measures, for internal managerial purposes, when evaluating period-to-period comparisons and providing public guidance on possible future results. These measures are not measures of financial performance under GAAP and should be considered in addition to, not as a substitute for, cash flows from operations, investing, or financing activities, nor as a liquidity measure or indicator of cash flows reported in accordance with U.S. GAAP. The non-GAAP financial measures that we use may not be comparable to similarly titled measures reported by other companies. Also, in the future, we may disclose different non-GAAP financial measures in order to help our investors more meaningfully evaluate and compare our future results of operations to our previously reported results of operations. We strongly encourage investors to review our financial statements and publicly filed reports in their entirety and to not rely on any single financial measure. See Reconciliation of Non-GAAP Financial Measures below for a detailed description of these measures as well as a reconciliation of each to the nearest GAAP measure. +2009 Overview +Even with natural gas prices rebounding somewhat in the last two months of 2009 from earlier in the year, overall we experienced depressed natural gas prices during 2009 compared to 2008. As our production increased to 43.3 Bcfe for 2009 compared to 38.7 Bcfe for 2008, an increase of 11.8%, primarily due to drilling programs in 2007 and 2008, our average sales price declined 50.1% or $4.22 per Mcfe. While the significant changes in commodity prices have impacted our results of operations, we believe that we were successful in managing our operations to reduce the negative impacts through our derivative positions. Our realized derivative gains for 2009 of $107.3 million added an average of $2.48 per Mcfe produced during 2009. +These realized derivative gains were the key component in our ability to increase our operating cash flow by $4.8 million to $143.9 million for 2009 as compared to 2008. With our strong operating cash flows, proceeds from our equity offering, and the formation of our joint venture, which allowed us to monetize a portion of our Appalachian Basin assets, we were able to pay down our debt and improve our liquidity position during the global recession of 2009. This allows us flexibility and stability as we enter 2010. +30 +Table of Contents +Results of Operations +Summary Operating Results +The following table presents selected information regarding our results of operations. +Year Ended December 31, +Change +2009 +2008 +2007 +2009-2008 +2008-2007 +(dollars in thousands, except per unit data) +Production (1) +Natural gas (Mcf) +35,536,092 +31,759,792 +22,513,306 +11.9 +% +41.1 +% +Oil (Bbls) +1,291,488 +1,160,408 +910,052 +11.3 +% +27.5 +% +Natural gas equivalent (Mcfe) (2) +43,285,020 +38,722,240 +27,973,618 +11.8 +% +38.4 +% +Mcfe per day +118,589 +106,088 +76,640 +Natural Gas and Oil Sales +Natural gas +$ +110,735 +$ +221,734 +$ +119,991 +-50.1 +% +84.8 +% +Oil +71,064 +104,168 +55,196 +-31.8 +% +88.7 +% +Provision for underpayment of natural gas sales +(2,706 +) +(4,025 +) +- +32.8 +% +* +Total oil and natural gas sales +$ +179,093 +$ +321,877 +$ +175,187 +-44.4 +% +83.7 +% +Realized Gain on Derivatives, net (3) +Natural gas +$ +89,464 +$ +12,632 +$ +7,350 +* +71.9 +% +Oil +17,881 +(3,145 +) +(177 +) +* +* +Total realized gain on derivatives, net +$ +107,345 +$ +9,487 +$ +7,173 +* +32.3 +% +Average Sales Price (excluding gain/loss on derivatives) +Natural gas (per Mcf) +$ +3.12 +$ +6.98 +$ +5.33 +-55.3 +% +31.0 +% +Oil (per Bbl) +$ +55.03 +$ +89.77 +$ +60.65 +-38.7 +% +48.0 +% +Natural gas equivalent (per Mcfe) +$ +4.20 +$ +8.42 +$ +6.26 +-50.1 +% +34.5 +% +Average Sales Price (including gain/loss on derivatives) +Natural gas (per Mcf) +$ +5.63 +$ +7.38 +$ +5.66 +-23.7 +% +30.5 +% +Oil (per Bbl) +$ +68.87 +$ +87.06 +$ +60.46 +-20.9 +% +44.0 +% +Natural gas equivalent (per Mcfe) +$ +6.68 +$ +8.66 +$ +6.52 +-22.9 +% +32.9 +% +Average Lifting Cost (per Mcfe) (4) +$ +0.83 +$ +1.07 +$ +0.90 +-22.4 +% +18.9 +% +Natural Gas Marketing (5) +$ +2,101 +$ +1,029 +$ +3,040 +104.2 +% +-66.2 +% +Other Costs and Expenses +Exploration expense and impairment of natural gas and oil properties +$ +22,887 +$ +45,105 +$ +23,551 +-49.3 +% +91.5 +% +General and administrative expense +$ +53,985 +$ +37,715 +$ +30,968 +43.1 +% +21.8 +% +Depreciation, depletion and amortization +$ +131,004 +$ +104,640 +$ +70,885 +25.2 +% +47.6 +% +Interest Expense +$ +37,208 +$ +28,132 +$ +9,279 +32.3 +% +203.2 +% +* Percentage change not meaningful or equal to or greater than 250% +(1) +Production is net and determined by multiplying the gross production volume of properties in which we have an interest by the percentage of the leasehold or other property interest we own. +(2) +A ratio of energy content of natural gas and oil (six Mcf of natural gas equals one Bbl of oil) was used to obtain a conversion factor to convert oil production into equivalent Mcf of natural gas. +(3) +We utilize commodity based derivative instruments to manage a portion of our exposure to price volatility of our natural gas and oil sales. These amounts represent realized derivative gains and losses related to natural gas and oil sales, which do not include realized derivative gains and losses related to natural gas marketing. +(4) +Lifting costs represent natural gas and oil lease operating expenses, exclusive of production taxes, on a per unit basis. +(5) +Represents sales from natural gas marketing, net of costs of natural gas marketing. +31 +Table of Contents +Natural Gas and Oil Sales +The following tables present natural gas and oil production and average sales price by area. +Year Ended December 31, +Change +2009 +2008 +2007 +2009-2008 +2008-2007 +Production +Natural gas (Mcf) +Rocky Mountain Region +29,987,465 +26,136,487 +18,123,851 +14.7 +% +44.2 +% +Appalachian Basin +4,010,511 +3,902,183 +2,711,300 +2.8 +% +43.9 +% +Other +1,538,116 +1,721,122 +1,678,155 +-10.6 +% +2.6 +% +Total +35,536,092 +31,759,792 +22,513,306 +11.9 +% +41.1 +% +Oil (Bbls) +Rocky Mountain Region +1,277,887 +1,149,071 +900,261 +11.2 +% +27.6 +% +Appalachian Basin +9,589 +6,623 +5,490 +44.8 +% +20.6 +% +Other +4,012 +4,714 +4,301 +-14.9 +% +9.6 +% +Total +1,291,488 +1,160,408 +910,052 +11.3 +% +27.5 +% +Natural gas equivalent (Mcfe) +Rocky Mountain Region +37,654,787 +33,030,913 +23,525,417 +14.0 +% +40.4 +% +Appalachian Basin +4,068,045 +3,941,921 +2,744,240 +3.2 +% +43.6 +% +Other +1,562,188 +1,749,406 +1,703,961 +-10.7 +% +2.7 +% +Total +43,285,020 +38,722,240 +27,973,618 +11.8 +% +38.4 +% +Year Ended December 31, +Change +2009 +2008 +2007 +2009-2008 +2008-2007 +Average Sales Price (excluding gain/loss on derivatives) +Natural gas (per Mcf) +Rocky Mountain Region +$ +2.98 +$ +6.57 +$ +5.01 +-54.6 +% +31.1 +% +Appalachian Basin +4.00 +9.21 +6.99 +-56.6 +% +31.8 +% +Other +3.47 +8.41 +6.12 +-58.7 +% +37.4 +% +Weighted average price +3.12 +6.98 +5.33 +-55.3 +% +31.0 +% +Oil (per Bbl) +Rocky Mountain Region +$ +55.01 +$ +89.73 +$ +60.62 +-38.7 +% +48.0 +% +Appalachian Basin +57.24 +88.80 +59.08 +-35.5 +% +50.3 +% +Other +55.36 +100.79 +68.31 +-45.1 +% +47.5 +% +Weighted average price +55.03 +89.77 +60.65 +-38.7 +% +48.0 +% +Natural gas equivalent (per Mcfe) +Rocky Mountain Region +$ +4.24 +$ +8.32 +$ +6.18 +-49.0 +% +34.6 +% +Appalachian Basin +4.05 +9.24 +7.02 +-56.2 +% +31.6 +% +Other +3.53 +8.52 +6.20 +-58.6 +% +37.4 +% +Weighted average price +4.20 +8.42 +6.26 +-50.1 +% +34.5 +% +Although production increased in 2009, natural gas and oil sales revenue, excluding the provision for underpayment of gas sales, decreased $144.1 million compared to 2008. Contributing to this decrease was $163.3 million related to decreased natural gas and oil pricing in 2009 as compared to 2008, which was partially offset by a $19.2 million increase in production. The production increase of 11.8% for 2009, compared to 2008, was primarily due to our significant capital investment in 2008. Directly attributable to our decision to reduce our capital expenditures for new wells drilled, our production exit rate of 107 MMcfe/day at December 31, 2009, was lower than the 122 MMcfe/day at December 31, 2008. The effects of the decrease in natural gas and oil sales revenue was significantly reduced by realized derivative gains for 2009 of $107.3 million. See Commodity Price Risk Management, Net discussion below. +The increase in natural gas and oil sales revenue of $150.7 from 2007 to 2008, excluding the provision for underpayment of gas sales, was a result of a 38.4% increase in production and a 34.5% increase in average commodity sales prices. The increase in production which contributed $90.5 million of the increase was a result of the significant number of wells drilled in 2008 along with an October 2007 acquisition of oil and gas properties. The increase in average commodity sales prices contributed $60.2 million to the increase in natural gas and oil sales revenues from 2007 to 2008. +32 +Table of Contents +Natural Gas and Oil Pricing. Our results of operations depend upon many factors, particularly the price of natural gas and oil and our ability to market our production effectively. Natural gas and oil prices are among the most volatile of all commodity prices. These price variations have a material impact on our financial results. Natural gas prices vary by region and locality, depending upon the distance to markets, and the supply and demand relationships in that region or locality. This can be especially true in the Rocky Mountain Region. The combination of increased drilling activity and the lack of local markets has resulted in a local market oversupply situation from time to time. Like most producers in the region, we rely on major interstate pipeline companies to construct these pipelines to increase capacity, rendering the timing and availability of these facilities beyond our control. Oil pricing is driven predominantly by global supply and demand relationships. +The price we receive for our natural gas produced in the Rocky Mountain Region is based on a market basket of prices, which generally includes gas sold at CIG prices as well as gas sold at Mid-Continent or other nearby region prices. The CIG Index, and other indices for production delivered to other Rocky Mountain pipelines, has historically been less than the price received for natural gas produced in the eastern regions, which is NYMEX-based. This negative differential has narrowed in recent months and for two out of the last four months become a slight positive differential, which contradicts historical variances. +The table below presents the pricing basis or market for our natural gas and oil sales based on production for 2009. The pricing basis is the index that most closely relates to the price under which our natural gas and oil is sold. +Energy Market Exposure +as of December 31, 2009 +Area +Pricing Basis +Commodity +Percent of +Oil and Gas +Sales +Piceance/Wattenberg +CIG +Gas +41% +Colorado/North Dakota +NYMEX +Oil +18% +Piceance +San Juan Basin/Southern California +Gas +15% +Appalachian +NYMEX +Gas +10% +NECO +Mid Continent (Panhandle Eastern) +Gas +7% +Michigan +Mich-Con/NYMEX +Gas +4% +Wattenberg +Colorado Liquids +Gas +4% +Other +Other +Gas/Oil +1% +100% +Natural Gas and Oil Production and Well Operations Costs . Natural gas and oil production and well operations costs include our lease operating expenses, production taxes, the cost to operate wells and pipelines for our affiliated partnerships and other third parties (whose income is included in well operations, pipeline income, and other) and certain production and engineering staff related overhead costs. +Year Ended December 31, +2009 +2008 +2007 +(in thousands) +Lease operating expense +$ +35,965 +$ +41,351 +$ +25,210 +Production taxes +9,262 +18,740 +12,252 +Costs of well operations and pipeline income +6,923 +5,694 +5,126 +Overhead and other production expenses +12,596 +13,569 +7,245 +Total natural gas and oil production and well operations costs +$ +64,746 +$ +79,354 +$ +49,833 +Lease Operating Expense . Lifting costs per Mcfe decreased 22.4% to $0.83 per Mcfe for 2009 from $1.07 per Mcfe for 2008. The decrease per Mcfe is primarily due to lower third party costs from service providers as a result of pressure by us to reduce costs as natural gas and oil prices deteriorated, our own cost reduction initiatives, and increased production, which allows us to spread the fixed portion of our production costs over the increased volume. Lifting cost per Mcfe increased 18.9% in 2008 from $0.90 per Mcfe in 2007. The increase was primarily due to general oil field services and wage inflation pressures in the high commodity sales pricing environment during 2008. +33 +Table of Contents +Production Taxes. Production taxes decreased $9.5 million or 50.6% to $9.3 million in 2009 compared to 2008. Production taxes fluctuate with natural gas and oil sales. The decrease in 2009 is the result of the 44.4% decrease in natural gas and oil sales from 2008. The 2008 increase in production taxes of $6.5 million corresponds with the 83.7% increase in natural gas and oil sales from those in 2007. +Cost of well operations and pipeline income. The increases in cost of well operations and pipeline income for 2009 compared to 2008 were the result of costs related to pipeline maintenance projects offset in part by lower field services costs. +Overhead and other production expenses . Overhead and other production expenses decreased in 2009 compared to 2008 due to the lower cost of field services, including vehicles, lower rates from third parties and less work and services being performed in this low commodity price environment, offset in part by a $2.7 million accrual for firm transportation costs in the Piceance Basin based on a projected shortfall in minimum volume requirements. The increase from 2007 to 2008 of $6.3 million was due to significantly increased production, additional personnel in the production and engineering staffs, increased maintenance and operating cost of the new pipeline and compressor upgrades and improvements, increased production enhancements and workovers and significant general oil field services inflation pressures. +Commodity Price Risk Management, Net +Commodity price risk management, net includes realized gains and losses and unrealized changes in the fair value of derivative instruments related to our natural gas and oil production. Commodity price risk management, net does not include derivative transactions related to natural gas marketing, which are included in sales from and cost of natural gas marketing. See Note 3, Fair Value of Financial Instruments , and Note 4, Derivative Financial Instruments , to our consolidated financial statements included in this report for additional details of our derivative financial instruments. +The following table presents the realized and unrealized derivative gains and losses included in commodity price risk management, net. +Year Ended December 31, +2009 +2008 +2007 +(in thousands) +Commodity price risk management gain (loss), net: +Realized gains (losses): +Natural gas +$ +89,464 +$ +12,632 +$ +7,350 +Oil +17,881 +(3,145 +) +(177 +) +Total realized gains (losses), net +107,345 +9,487 +7,173 +Unrealized gains (losses): +Reclassification of realized (gains) losses included in prior periods unrealized +(84,655 +) +549 +(4,843 +) +Unrealized gains (losses) for the period +(32,743 +) +117,802 +426 +Total unrealized gains (losses), net +(117,398 +) +118,351 +(4,417 +) +Total commodity price risk management gain (loss), net +$ +(10,053 +) +$ +127,838 +$ +2,756 +Realized gains recognized in 2009 of $107.3 million are a result of lower natural gas and oil spot prices at settlement compared to the respective strike price. During 2009, we recorded unrealized losses on our CIG basis swaps of $33.9 million as the forward basis differential between NYMEX and CIG had continued to narrow along with unrealized losses of $15 million on our oil positions, offset by unrealized gains of $16.2 million on our natural gas positions. +During the first half of 2008, we experienced both realized and unrealized derivative losses as natural gas and oil prices were at or near record prices. During the second half of the year, due to the tumbling commodity prices, we had both significant realized and unrealized derivative gains. We ended the year with a net realized and unrealized derivative gain of $127.8 million. The unrealized gain includes a gain on our natural gas and oil positions of $120.5 million and an unrealized loss on our CIG basis swaps of $2.7 million. +34 +Table of Contents +Natural Gas and Oil Sales Derivative Instruments . We use various derivative instruments to manage fluctuations in natural gas and oil prices. We have in place a variety of collars, fixed-price swaps and basis swaps on a portion of our estimated natural gas and oil production. Under our collar arrangements, if the applicable index rises above the ceiling price, we pay the counterparty; however, if the index drops below the floor price, the counterparty pays us. Under our commodity swap arrangements, if the applicable index rises above the swap price, we pay the counterparty; however, if the index drops below the swap price, the counterparty pays us. Under our basis protection swaps, if the differential widens beyond the basis swap price, then the counterparty pays us; however, if the differential narrows, then we pay the counterparty. Because we sell all of our physical natural gas and oil at similar prices to the indexes inherent in our derivative instruments, we ultimately realize a price related to our collars of no less than the floor and no more than the ceiling and, for our commodity swaps, we ultimately realize the fixed price related to our swaps. +The following table presents our derivative positions (excluding the derivative positions designated to our affiliated partnerships) related to natural gas and oil sales in effect as of December 31, 2009, on our production by area. Our production volumes for the fourth quarter of 2009 were 292,190 Bbls of oil and 8.2 Bcf of natural gas. +CIG +Collars +Fixed-Price Swaps +Basis Protection Swaps +Fair Value +Weighted +Weighted +At +Quantity +Weighted Average +Quantity +Average +Quantity +Average +December 31, +(Gas-MMBtu +Contract Price +(Gas-MMBtu +Contract +(Gas-MMBtu +Contract +2009 +Commodity/Operating Area/Index +Oil-Bbls) +Floors +Ceilings +Oil-Bbls) +Price +Oil-Bbls) +Price +(in thousands) +Natural Gas +Rocky Mountain Region +CIG +1Q 2010 +2,167,137 +$ +7.50 +$ +7.50 +1,515,805 +$ +9.20 +- +$ +- +$ +10,540 +4Q 2010 +680,250 +4.75 +9.45 +- +- +- +- +122 +2011 +1,020,375 +4.75 +9.45 +959,743 +5.81 +- +- +161 +PEPL +1Q 2010 +510,000 +9.00 +14.00 +360,000 +10.91 +- +- +3,743 +2Q 2010 +300,000 +5.00 +8.90 +300,000 +6.49 +- +- +482 +3Q 2010 +300,000 +5.00 +8.90 +300,000 +6.49 +- +- +405 +4Q 2010 +360,000 +5.55 +9.38 +296,260 +6.28 +- +- +307 +2011 +390,000 +5.76 +9.56 +2,117,424 +6.18 +- +- +638 +2012 - 2013 +- +- +- +2,346,224 +6.18 +- +- +(76 +) +NYMEX +1Q 2010 +562,725 +10.00 +17.15 +375,510 +8.98 +- +- +3,706 +2Q 2010 +152,202 +5.85 +10.15 +3,055,239 +6.01 +2,636,837 +(1.88 +) +(2,277 +) +3Q 2010 +152,202 +5.85 +10.15 +2,968,502 +6.02 +2,541,588 +(1.88 +) +(2,835 +) +4Q 2010 +568,990 +5.94 +9.15 +1,757,987 +6.66 +1,793,953 +(1.88 +) +(1,295 +) +2011 +724,478 +5.96 +9.10 +7,703,191 +6.96 +7,668,501 +(1.88 +) +(4,471 +) +2012 - 2013 +8,785,102 +6.05 +8.43 +7,406,878 +7.08 +14,610,818 +(1.88 +) +(11,167 +) +Appalachia +NYMEX +1Q 2010 +21,128 +10.00 +17.15 +703,960 +5.31 +- +- +(138 +) +2Q 2010 +7,115 +5.85 +10.15 +687,401 +5.32 +- +- +(155 +) +3Q 2010 +7,115 +5.85 +10.15 +662,401 +5.32 +- +- +(278 +) +4Q 2010 +7,190 +6.45 +11.48 +648,933 +5.33 +- +- +(568 +) +2011 +8,383 +6.61 +11.60 +2,401,807 +6.35 +- +- +46 +2012 - 2013 +- +- +- +71,454 +7.24 +- +- +43 +Michigan +NYMEX +1Q 2010 +264,996 +10.00 +17.15 +49,688 +9.89 +- +- +1,366 +2Q 2010 +73,255 +5.85 +10.15 +72,886 +8.55 +- +- +276 +3Q 2010 +73,255 +5.85 +10.15 +72,886 +8.55 +- +- +261 +4Q 2010 +73,174 +6.45 +11.47 +60,169 +9.17 +- +- +253 +2011 +83,766 +6.62 +11.64 +688,549 +7.59 +- +- +970 +2012 - 2013 +427,363 +6.05 +8.43 +1,076,266 +7.17 +- +- +695 +Total Natural Gas +17,720,200 +38,659,162 +29,251,697 +754 +35 +Table of Contents +CIG +Collars +Fixed-Price Swaps +Basis Protection Swaps +Fair Value +Weighted +Weighted +At +Quantity +Weighted Average +Quantity +Average +Quantity +Average +December 31, +(Gas-MMBtu +Contract Price +(Gas-MMBtu +Contract +(Gas-MMBtu +Contract +2009 +Commodity/Operating Area/Index +Oil-Bbls) +Floors +Ceilings +Oil-Bbls) +Price +Oil-Bbls) +Price +(in thousands) +Oil +Rocky Mountain Region +NYMEX +1Q 2010 +- +- +- +187,598 +89.58 +- +- +1,768 +2Q 2010 +- +- +- +171,187 +90.42 +- +- +1,484 +3Q 2010 +- +- +- +155,178 +91.42 +- +- +1,294 +4Q 2010 +- +- +- +142,052 +92.30 +- +- +1,141 +2011 +231,452 +73.00 +99.80 +355,869 +73.89 +- +- +(4,721 +) +2012 - 2013 +686,148 +75.00 +102.63 +- +- +- +- +(1,316 +) +Total Oil +917,600 +1,011,885 +- +(350 +) +Total Natural Gas and Oil +$ +404 +Natural Gas Marketing +The decrease in sales from natural gas marketing in 2009 compared to 2008 is primarily due to a decrease in prices and increased unrealized losses on derivative instruments, offset by an increase in realized gains on derivatives. In 2009, prices on sales were 54.9% lower on average than in 2008, resulting in a $107.7 million decrease in sales. In 2009, unrealized derivative gains on sales contracts decreased $8.1 million from $4.6 million in 2008 to a loss of $3.5 million in 2009. This unrealized loss was partially offset by an increase in realized gains of $7.6 million. Volumes sold decreased by 2% in 2009 compared to 2008, resulting in a $3.7 million decrease in sales. +The decrease in sales from natural gas marketing in 2009 compared to 2008 is primarily due to a decrease in prices and increased unrealized losses on derivative instruments, offset by an increase in realized gains on derivatives. In 2009, prices on sales were 54.9% lower on average than in 2008, resulting in a $107.7 million decrease in sales. In 2009, unrealized derivative gains on sales contracts decreased $8.1 million from $4.6 million in 2008 to a loss of $3.5 million in 2009. These unrealized gains were partially offset by an increase in realized gains of $7.6 million. Volumes sold decreased by 2% in 2009 compared to 2008, resulting in a $3.7 million decrease in sales. +The decrease in costs of natural gas marketing in 2009 compared to 2008 is primarily due to a decrease in prices, increased unrealized gains, and a decrease in unrealized losses on derivative instruments. In 2009, prices on purchases were 52% lower on average than in 2008, resulting in a $99.1 million decrease in costs. The unrealized gains on cost related contracts increased by $9.7 million, and realized losses decreased by $0.8 million. Volumes purchased for resale decreased by 2% in 2009 compared to 2008, resulting in a $3.6 million decrease in costs. +The increase in sales from natural gas marketing in 2008 compared to 2007 is primarily due to an increase in prices and increased unrealized gains on derivative instruments. The increase in costs of natural gas marketing in 2008 compared to 2007 is primarily due to an increase in prices and increased unrealized losses on derivative instruments. In 2008, prices on sales and purchases were 31.8% higher on average than in 2007, resulting in a $27.8 million increase in sales and costs. The sales related unrealized gain on derivatives increased by $6.4 million and the cost of sales related unrealized loss on derivatives increased by $6.9 million. Volumes sold and purchased for resale decreased slightly by 2%. +Natural Gas Marketing Derivative Instruments . Our derivative instruments related to natural gas marketing include both physical and cash-settled derivatives. We offer fixed-price derivative contracts for the purchase or sale of physical gas and enter into cash-settled derivative positions with counterparties in order to offset those same physical positions. We do not take speculative positions on commodity prices. +36 +Table of Contents +The following table presents our derivative positions related to our natural gas marketing in effect as of December 31, 2009. +NYMEX +Collars +Fixed-Price Swaps +Basis Protection Swaps +Fair Value +Weighted +Weighted +At +Weighted Average +Average +Average +December 31, +Commodity/ +Quantity +Contract Price +Quantity +Contract +Quantity +Contract +2009 +Derivative Instrument +(Gas-MMBtu) +Floors +Ceilings +(Gas-MMBtu) +Price +(Gas-MMBtu) +Price +(in thousands) +Natural Gas +Physical Sales +1Q 2010 +- +$ +- +$ +- +206,368 +$ +5.85 +131,411 +$ +0.37 +$ +(2 +) +2Q 2010 +- +- +- +38,154 +6.76 +8,948 +0.96 +35 +3Q 2010 +- +- +- +42,415 +6.80 +2,823 +0.92 +28 +4Q 2010 +- +- +- +29,573 +6.77 +17,506 +0.78 +13 +2011 +- +- +- +- +- +30,410 +0.75 +18 +Financial Purchases +1Q 2010 +- +- +- +235,759 +6.29 +90,000 +0.17 +(152 +) +2Q 2010 +- +- +- +37,659 +5.44 +- +- +4 +3Q 2010 +- +- +- +41,938 +5.44 +- +- +13 +4Q 2010 +- +- +- +29,374 +5.41 +- +- +22 +Financial Sales +1Q 2010 +52,500 +4.53 +7.16 +604,600 +6.89 +- +- +754 +2Q 2010 +52,500 +4.53 +7.16 +603,600 +6.71 +- +- +694 +3Q 2010 +52,500 +4.53 +7.16 +603,600 +6.71 +- +- +569 +4Q 2010 +52,500 +4.53 +7.16 +517,600 +6.81 +- +- +300 +2011 +52,500 +4.53 +7.16 +454,700 +6.81 +- +- +71 +Physical Purchases +1Q 2010 +52,500 +4.53 +7.14 +575,050 +7.05 +- +- +(621 +) +2Q 2010 +52,500 +4.53 +7.14 +604,050 +6.66 +- +- +(559 +) +3Q 2010 +52,500 +4.53 +7.14 +604,050 +6.66 +- +- +(436 +) +4Q 2010 +52,500 +4.53 +7.14 +517,750 +6.78 +- +- +(175 +) +2011 +52,500 +4.53 +7.14 +454,700 +6.77 +- +- +35 +Total Natural Gas +525,000 +6,200,940 +281,098 +$ +611 +Other Costs and Expenses +Exploration Expense and Impairment of Natural Gas and Oil Properties +The following table presents the major components of exploration expense and impairment of natural gas and oil properties. +Year Ended December 31, +2009 +2008 +2007 +(in thousands) +Impairment of proved natural gas and oil properties +$ +926 +$ +12,825 +$ +- +Impairment/amortization of unproved properties +7,279 +12,798 +3,291 +Exploratory dry holes +1,059 +7,675 +4,187 +Geological and geophysical costs +1,788 +2,121 +6,299 +Operating, personnel and other +11,835 +9,686 +9,774 +Total exploration expense and impairment of natural gas and oil properties +$ +22,887 +$ +45,105 +$ +23,551 +37 +Table of Contents +During 2009, we recognized, upon the termination of an exploration agreement, an impairment related to unproved properties in North Dakota of $2.8 million and amortization of unproved properties of $2.4 million in NECO and $1.4 million in North Dakota. The majority of the geological and geophysical costs were related to seismic work in the Appalachian Basin related to our Marcellus development project. Included in operating, personnel and other is $3.7 million for demobilization of our drilling operations in the Piceance Basin during 2009. +In 2008, we recognized impairment losses on proved natural gas and oil properties of $12.8 million, consisting of $7.5 million related to our properties in the Fort Worth Basin, $3 million in our Bakken Field in North Dakota and $2.3 million in our Nesson Field, also in North Dakota. We also recognized impairment losses on unproved properties of $12.8 million, consisting primarily of $7.3 million related to our unproved properties in the Fort Worth Basin and amortization of approximately $5.5 million related to all of our other areas of operations. The $7.7 million of exploratory dry holes relates primarily to two Michigan wells, one New York well and one Colorado well. +In 2007, exploration expense and impairment of natural gas and oil properties includes $2.7 million of liquidated damages associated with the abandonment of an exploration agreement with an unaffiliated third party and $1.1 million related to the write-off of the carrying value of the related acreage, $6.3 million in geological and geophysical costs related to seismic evaluation of various exploratory prospects. +General and Administrative Expense +General and administrative expense increased from $37.7 million in 2008 to $54 million in 2009, an increase of $16.3 million. The increase is primarily related to transaction costs associated with our joint venture of $7.9 million, an increase in staffing and payroll benefits, including stock-based compensation of $3.7 million, transaction costs of $1.5 million related to an acquisition contemplated in the year prior to the adoption of new accounting rules and corporate headquarters relocation costs of $1.3 million. See Note 2, Summary of Significant Accounting Polices – Recent Accounting Standards , to our consolidated financial statements included in this report. +The $6.7 million increase in general and administrative expense in 2008 compared to 2007 was primarily due to increased payroll and payroll related expenses, which includes $4.7 million related to agreements with two former executive officers: $3.2 million related to a separation agreement with our former president and $1.5 million related to an agreement for the retirement of our former chief executive officer. This increase was partially offset by a $2 million decrease in audit fees and a decrease in various other general and administrative expenses. +Depreciation, Depletion and Amortization +Natural gas and oil properties. DD&A expense related to natural gas and oil properties is directly related to natural gas and oil reserves and production volumes. DD&A expense is primarily based upon year-end proved developed producing natural gas and oil reserves. For 2008 and 2007, these reserves were priced at the price of natural gas and oil as of December 31 for the respective year. New natural gas and reserve estimation and reporting requirements in 2009 changed the pricing measurement for reserve estimations from a December 31 single day pricing to a 12-month average of the first day of the month price for each month in the period. If prices increase, the estimated volumes of natural gas and oil reserves will increase, resulting in decreases in the rate of DD&A per unit of production. If prices decrease, as they did from December 31, 2008, to December 31, 2009, the estimated volumes of natural gas and oil reserves will decrease, resulting in increases in the rate of DD&A per unit of production. The weighted average DD&A rate for 2009 was $2.83 per Mcfe compared to $2.51 per Mcfe for 2008 and $2.37 per Mcfe for 2007. Prior to 2009, the cost to acquire acreage, drill, complete and equip new wells had risen significantly over the past five years and is a major contributing factor to the increased DD&A rates in all areas. +38 +Table of Contents +The following table presents our DD&A rate for natural gas and oil properties by area. +Year Ended December 31, +2009 +2008 +2007 +(per Mcfe) +Rocky Mountain Region: +Wattenberg Field (1) +$ +3.81 +$ +3.47 +$ +2.99 +Grand Valley +2.35 +2.04 +2.27 +NECO +1.85 +1.45 +1.45 +Appalachian Basin +2.06 +1.55 +1.32 +Weighted average +2.83 +2.51 +2.37 +(1) +Although the Wattenberg Field development costs and DD&A rates are higher than the other fields, the relative value of its oil production currently more than offsets this cost difference. The Wattenberg Field has produced volumes in excess of 89% of our total oil production in each of the years in the three-year period ended December 31, 2009. +Non natural gas and oil properties. Depreciation expense for non natural gas and oil properties was $8.1 million for 2009 compared to $7.6 million for 2008 and $4.3 million for 2007. +Gain on Sale of Leaseholds +During 2007, we had two transactions involving leasehold sales. In May 2007, we entered into a letter agreement amending a 2006 purchase and sale agreement, relieving us of our obligation, in its entirety, to either drill 16 wells or pay liquidated damages of $1.6 million per undrilled well. As a result, we recognized the remaining deferred gain of $25.6 million in the second quarter of 2007. In December 2007, we sold to the same unaffiliated party a portion of our North Dakota properties for approximately $34.7 million. The properties, located in Dunn, Williams and McKenzie Counties, North Dakota, include interests in five producing Bakken wells and approximately 72,000 net undeveloped acres. We recorded a gain on sale of leaseholds of $7.7 million in the fourth quarter of 2007. +Non-Operating Income/Expense +Interest Income . The decrease in our interest income for 2009 compared to 2008 and 2007 was the result of lower interest bearing cash balances and lower interest rates. +Interest Expense . The year-over-year increases in our interest expense were primarily due to significantly higher average outstanding balances of our credit facility offset in part by lower average interest rates in our bank credit facility. The average long-term debt in 2009 was $392 million compared to $275.9 million in 2008. Interest expense is net of capitalized interest. Interest costs capitalized in 2009, 2008 and 2007 were $0.8 million, $2.6 million and $3 million, respectively. We have historically utilized our daily cash balances to reduce our line of credit borrowings, thereby lowering our interest costs and, as discussed above, interest income. +Provision/Benefit for Income Taxes +The effective income tax rate for continuing operations ("rate") for 2009 was 36% (benefit on a loss) compared to 35.1% (provision on income) in 2008 and 38.8% (provision on income) in 2007. The 2009 rate was reduced by the tax effect of certain non-deductible expenditures and non-benefited losses associated with our new joint venture. The 2008 rate reflects a discrete tax benefit from state tax planning strategies implemented during 2008 for prior tax years. The 2007 rate approximates the combined statutory federal and state tax rates due to percentage depletion and domestic production deductions being offset by additional tax due to non-deductible penalties. +Our 2009 rate, excluding the effect of discrete items, was 36.2%. Our 2008 and 2007 rate, excluding the effect of discrete items, was 37.4% and 37%, respectively. +The federal examination of our 2005 and 2006 tax returns was completed in June 2009. Beginning with our 2010 tax year, we have been accepted into and have agreed to participate in the IRS Compliance Assurance Process Program. As part of our entrance into this program, we have agreed to an accelerated timeline for the IRS examination of our 2007, 2008 and 2009 tax years. This examination is scheduled to begin in April 2010. +39 +Table of Contents +Discontinued Operations +Since 2007, we have not had significant revenue from our well drilling activities, and in January 2008, we announced that we had no plans to sponsor new drilling partnerships in 2008. We affirmed this position in 2009 to change our business model from a partnership sponsor to that of an independent exploration and production company. As of June 30, 2009, we had concluded all partnership drilling and completion activities. An unused advance of $0.3 million was refunded to the partnerships in June 2009. +As we currently do not have any plans in the foreseeable future to sponsor a drilling partnership, we believe it was appropriate to treat our natural gas and oil well drilling activities as discontinued operations for all periods presented. Prior period financial statements have been restated to present the activities of our natural gas and oil well drilling operations as discontinued operations. +Net Income (Loss) Attributable to Shareholders/Adjusted Net Income (Loss) Attributable to Shareholders +Net loss attributable to shareholders for 2009 was $79.3 million compared to a net gain of $113.3 million for 2008 and $33.2 million for 2007. Adjusted net loss attributable to shareholders, a non-GAAP financial measure for 2009 was $2.9 million compared to an adjusted net income of $39.7 million for 2008 and $36 million for 2007. The year-over-year changes in net income (loss) attributable to shareholders are discussed above. These same reasons for change similarly impacted adjusted net income (loss) attributable to shareholders, with the exception of the unrealized derivative gains and losses on derivatives, adjusted for taxes. Adjusted net income (loss) attributable to shareholders excludes the impact of a tax adjusted unrealized derivative loss of $74.6 million for 2009, a tax adjusted unrealized gain of $76.2 million for 2008 and a tax adjusted unrealized loss of $2.8 million for 2007. See Reconciliation of Non-GAAP Financial Measures , below, for a more detailed discussion of this non-GAAP financial measure. +Financial Condition +Capital Resources and Liquidity +Our primary sources of cash in 2009 were from funds generated from the sale of natural gas and oil production, the net realized gains from our derivative positions, the sale of common stock and the formation of the joint venture, which allowed us to monetize a portion of our Appalachian Basin assets. These sources of cash were primarily used to fund our operating costs, general and administrative activities and our capital expenditures, including both our developmental and exploratory activities. Additionally, we were able to improve our liquidity position during the uncertain economic time of 2009 by reducing our borrowings through payments on our credit facility. Our primary sources of cash from operations are sales of natural gas and oil. Fluctuations in our operating cash flow are substantially driven by commodity prices and change in our production volumes. Commodity prices have historically been volatile and we manage this volatility through our derivative program. Therefore, the primary source of our cash flow from operations becomes the net activity between our natural gas and oil sales and realized derivative gains and losses. However, we do not hold economic hedges for more than 80% of our expected future production from producing wells and therefore may still have significant fluctuations in our cash flows from operations. Additionally, these fluctuations may result in an increase or decrease in our expected developmental and exploratory activities in the future. See Results of Operations for further discussion of the impact of prices and volumes on sales from operations and the impact of derivative activities on our revenues. +We entered 2010 with cash and cash equivalents of $31.9 million and availability under our credit facility of $206.3 million for a total liquidity position of $238.2 million compared to $231.5 million at the beginning of 2009. The increase in liquidity of $6.7 million or 2.9% was achieved despite the $70 million reduction in our total borrowing base, a new letter of credit on a pipeline commitment of $18.7 million and the general downturn in the financial markets and global economy. From time to time, our working capital will reflect a surplus, while at other times it will reflect a deficit. The primary factors affecting our working capital are our current unrealized derivative position, the timing of our payments to reduce our credit facility and the other variables discussed above. Our working capital surplus remained relatively unchanged from $31.3 million at December 31, 2008, to $32.9 million at December 31, 2009. The recent financial and credit crisis has reduced credit availability and liquidity for some companies; however, we believe we have adequate liquidity available to meet our working capital requirements. With our current liquidity position, including our working capital surplus and expected cash flow from operations, we believe that we have sufficient liquidity available to us for our planned uses of capital. +The key components impacting our cash flow from operations are commodity prices, production volumes, realized gains and losses from our derivative positions, operating costs and general and administrative expenses. Cash provided by operating activities was $143.9 million for 2009 compared to $139.1 million for 2008. The $4.8 million increase in 2009 was primarily due to the increase in realized gains from derivatives of $106.2 million, decrease in natural gas and oil production and well operations costs of $14.6 million offset by decrease in natural gas and oil sales of $142.8 million and an increase in general and administrative costs from operating activities of $16.3 million. The remaining change in our operating cash flow was primarily due to changes in our assets and liabilities related to the timing of cash payments and receipts. The key components for the changes in our cash flows from operations are described in more detail in our Results of Operations above. +40 +Table of Contents +Adjusted cash flows from operations were $170.2 million for 2009 compared to $199.9 million for 2008. Adjusted EBITBA was $159.7 million for 2009 compared to $189.4 million for 2008. These decreases were primarily due to the same factors mentioned above for changes in cash provided by operating activities without regard to timing of cash payments and receipts of our assets and liabilities. See Reconciliation of Non-GAAP Financial Measures , below, for a more detailed discussion of these non-GAAP financial measures. +Cash flows used in investing activities, primarily drilling capital expenditures, decreased $180.7 million, or 55.9%, from $323 million for 2008 to $142.3 million for 2009. We reduced our planned 2009 capital expenditure program to preserve our liquidity position throughout 2009. We focused our drilling on our oil-rich section of our Wattenberg Field, where we drilled approximately 82% of our 2009 wells. Additionally, our other significant capital spend was drilling eight Marcellus wells in the Appalachian Basin. See Part I, Operations - Drilling Activities , for additional details on our 2009 drilling activity. +Cash flows provided from financing activities decreased $170.7 million from a $150.1 million source of cash for 2008 to a $20.6 million use of cash for 2009. The decrease was due to the shift from net borrowings of $159.6 million in 2008 to a net payment on borrowings of $114.5 million in 2009. This $274.1 million shift was offset by the proceeds from our equity offering of $48.5 million and our joint venture investor partner’s investment contribution of $55 million, of which, at closing, we withdrew $45 million as a return of capital and used the proceeds to reduce debt. See Note 8, Long-Term Debt , and Note 13, Noncontrolling Interest in Subsidiaries , to our consolidated financial statements included in this report for further discussion on our equity offering and joint venture. +Our primary use of funds is for capital expenditures. Our planned 2010 capital expenditures of $149.9 million, for non joint venture related projects, represent an approximate 37% increase from our 2009 capital expenditures. We estimate our 2010 production to be 35.7 Bcfe, which includes our proportionate share of the joint venture, a decrease of approximately 17.6% over 2009 due to our reduced 2009 drilling program from that of 2008 and the contribution of a portion of our producing Appalachian properties to the joint venture. We believe, based on the current commodity price environment, our cash flows from operations will fund the majority of our 2010 capital spending program. In order to grow our production, unlike in 2009, we would need to commit greater amounts of capital in 2011 and beyond. If capital is not available or is constrained in the future, we will be limited to our cash flows from operations and liquidity under our credit facility as the sources of funding for our capital expenditures. Because natural gas and oil produced from our existing properties declines rapidly in the first two years of production, we cannot maintain our current level of natural gas and oil production and cash flows from operations if capital markets and commodity prices remain in their current depressed state for a prolonged period beyond 2009, which could have a material negative impact on our operations in 2010 and beyond. +We considered the possibility of reduced available liquidity in planning our 2010 drilling program and believe we will have adequate cash flows from operations during the year to execute our planned capital expenditures. Currently, we operate approximately 92.7% of our properties, allowing us to direct the pace of substantially all of our planned capital expenditures. Consequently, we may elect to defer a substantial portion of our planned capital expenditures for 2010 and beyond if market conditions worsen. +We have experienced no impediments in our ability to access borrowings under our current bank credit facility or the capital markets, as demonstrated by our August 2009 sale of equity. We continue to monitor market events and circumstances and their potential impacts on each of the 13 lenders that comprise our bank credit facility. Our $305 million bank credit facility borrowing base is subject to size redeterminations each May and November based upon a quantification of our proved reserves at each December 31st and June 30th, respectively. A commodity price deck reflective of the current and future commodity pricing environment is utilized by our lenders to quantify our reserve reports and determine the underlying borrowing base. +While we have continued to add producing reserves through our drilling operations since our last redetermination, we believe a significant decrease in commodity prices and turmoil in the credit markets could have a negative impact on our May 2010 borrowing base redetermination. +In August 2009, we issued a $18.7 million irrevocable standby letter of credit in favor of a third party transportation service provider to secure the construction of certain additions and/or replacements to its facilities to provide firm transportation of the natural gas produced by us and others for whom we market their production in the West Virginia and Southwestern Pennsylvania area. The letter of credit, even if undrawn, reduces the amount of available funds under our credit facility by an equal amount. We pay a fronting fee of 0.25% per annum and an additional quarterly maintenance fee equivalent to the spread over Eurodollar loans (2.5% as of December 31, 2009) for the period the letter of credit remains outstanding. The letter of credit expires on May 22, 2012. +41 +Table of Contents +We are subject to quarterly financial debt covenants on our bank credit facility. Currently, our key credit facility debt covenants require that we maintain: 1) total debt of less than 4.25 times earnings before interest, taxes, DD&A expense and capital expenditures ("EBITDAX") and 2) an adjusted working capital ratio of at least 1.0 to 1.0. Our adjusted working capital ratio is calculated by reducing our current assets and liabilities by any impact of recording the fair value of our natural gas and oil derivative instruments and adding our available borrowings on our bank credit facility to our current assets. In addition, the impact of any current portion of our debt is eliminated from the current liabilities. Therefore, any change in our available borrowings under our credit facility impacts our working capital ratio. We were in compliance with all debt covenants at December 31, 2009. +The indenture governing our senior notes contains customary representations and warranties as well as typical restrictive covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: (a) incur additional debt, (b) make certain investments or pay dividends or distributions on our capital stock or purchase or redeem or retire capital stock, (c) sell assets, including capital stock of our restricted subsidiaries, (d) pay dividends or other payments by restricted subsidiaries, (e) create liens that secure debt, (f) enter into transactions with affiliates, and (g) merge or consolidate with another company. Additionally, we are subject to two incurrence covenants: 1) EBITDAX of at least two times interest expense and 2) total debt of less than 4.0 times EBITDAX. We were in compliance with all covenants as of December 31, 2009. +We believe we have sufficient liquidity and capital resources to conduct our business and remain compliant with our debt covenants throughout the next year based upon our 2010 cash flow projections, anticipated capital requirements, the discretionary nature of our capital expenditures and available capacity under our bank credit facility. However, we cannot predict with any certainty the impact to our future business of any continued uncertainty or further deterioration in the financial or commodity markets. We will continue to closely monitor our liquidity and the credit markets and may choose to access them opportunistically should conditions and capital market liquidity improve. +We filed a shelf registration statement on Form S-3 with the SEC on November 26, 2008. The shelf provides for an aggregate of $500 million, through the potential sale of debt securities, common stock or preferred stock, either separately or represented by depository shares, warrants and purchase contracts, as well as units that may include any of these securities or securities of other entities. The shelf registration statement is intended to allow us to be proactive in our ability to raise capital should the need arise, and to have the flexibility to raise such funds in one or more offerings should we perceive the market conditions to be favorable. This shelf registration statement was declared effective by the SEC on January 30, 2009. Following our equity offering in August 2009, we now have available $448.2 million of our shelf from which we may utilize to raise capital. +See Part II, Item 7A, Quantitative and Qualitative Disclosures about Market Risk , for our discussion of credit risk. +Contractual Obligations and Contingent Commitments +The table below presents our contractual obligations and contingent commitments as of December 31, 2009. +Payments due by period +Less than +1-3 +3-5 +More than +Contractual Obligations and Contingent Commitments +Total +1 year +years +years +5 years +(in thousands) +Long-term liabilities reflected on the consolidated balance sheets (1) +Long-term debt +$ +280,657 +$ +- +$ +80,000 +$ +- +$ +200,657 +Asset retirement obligations +29,564 +250 +500 +1,000 +27,814 +Derivative contracts (2) +65,844 +17,065 +36,179 +12,600 +- +Derivative contracts - partnerships (3) +6,660 +665 +4,355 +1,640 +- +Production tax liability +36,100 +21,542 +14,558 +- +- +Other liabilities (4) +10,336 +352 +3,515 +770 +5,699 +429,161 +39,874 +139,107 +16,010 +234,170 +Commitments, contingencies and other arrangements (5) +Interest on long-term debt (6) +206,892 +28,105 +53,942 +48,720 +76,125 +Operating leases +6,817 +2,001 +2,422 +1,749 +645 +Drilling commitment (7) +1,800 +- +- +- +1,800 +Firm transportation and processing agreements (8) +179,884 +18,483 +38,025 +41,989 +81,387 +Other +750 +125 +250 +250 +125 +396,143 +48,714 +94,639 +92,708 +160,082 +Total +$ +825,304 +$ +88,588 +$ +233,746 +$ +108,718 +$ +394,252 +42 +Table of Contents +(1) +Table does not include deferred income tax liability to taxing authorities of $178 million as of December 31, 2009, due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations. +(2) +Represents our gross liability related to the fair value of derivative positions, including the fair value of derivative contracts we entered into on behalf of our affiliated partnerships as the managing general partner. We have a related receivable from the partnerships of $21 million as of December 31, 2009. +(3) +Represents our affiliated partnerships’ designated portion of the fair value of our gross derivative assets as of December 31, 2009. +(4) +Includes funds held from revenue distribution to third party investors for plugging liabilities related to wells we operate and deferred officer compensation. +(5) +Table does not include maximum annual repurchase obligations to investing partners of $9.4 million as of December 31, 2009, due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations. +(6) +Amounts presented for long term debt consist of amounts related to our 12% senior notes and our outstanding credit facility. The interest on long-term debt includes $197.9 million payable to the holders of our 12% senior notes and $8.5 million related to our outstanding balance of $80 million on our credit facility as of December 31, 2009, including interest of $0.5 million related to our letter of credit, based on an imputed interest rate of 4.7%. +(7) +See Note 11, Commitments and Contingencies – Drilling and Development Agreements, to our consolidated financial statements included in this report. +(8) +Represents our gross commitment, including amounts for volumes transported or sold on behalf of our affiliated partnerships and other working interest owners. We will recognize in our financial statements our proportionate share based on our working interest. See Note 11, Commitments and Contingencies – Firm Transportation Agreements, to our consolidated financial statements included in this report. +As managing general partner of 33 partnerships ( see Item 1 . Business – Drilling and Development Conducted for Company Sponsored Partnerships) , we have liability for potential casualty losses in excess of the partnership assets and insurance. We believe that the casualty insurance coverage we and our subcontractors carry is adequate to meet this potential liability. +For information regarding our legal proceedings, see Note 11, Commitments and Contingencies – Litigation, to our consolidated financial statements included in this report. From time to time we are a party to various other legal proceedings in the ordinary course of business. We are not currently a party to any litigation that we believe would have a materially adverse affect on our business, financial condition, results of operations, or liquidity. +Critical Accounting Policies and Estimates +We have identified the following policies as critical to business operations and the understanding of our results of operations. This is not a comprehensive list of all of the accounting policies. In many cases, the accounting treatment of a particular transaction is specifically dictated by accounting principles generally accepted in the U.S., with no need for our judgment in the application. There are also areas in which our judgment in selecting any available alternative would not produce a materially different result. However, certain of our accounting policies are particularly important to the portrayal of our financial position and results of operations and we may use significant judgment in the application; as a result, they are subject to an inherent degree of uncertainty. In applying those policies, we use our judgment to determine the appropriate assumptions to be used in the determination of certain estimates. Those estimates are based on historical experience, observation of trends in the industry, and information available from other outside sources, as appropriate. For a more detailed discussion on the application of these and other accounting policies, see Note 2, Summary of Significant Accounting Policies , to our consolidated financial statements included in this report. Our critical accounting policies and estimates are as follows: +Revenue Recognition +Natural gas and oil sales . Sales of oil are recognized when persuasive evidence of a sales arrangement exists, the oil is verified as produced and is delivered to a purchaser, collection of revenue from the sale is reasonably assured and the sales price is determinable. We are currently able to sell all the oil that we can produce under existing sales contracts with petroleum refiners and marketers. We do not refine any of our oil production. Our crude oil production is sold to purchasers at or near our wells under short-term purchase contracts at prices and in accordance with arrangements that are customary in the industry. +Sales of natural gas are recognized when natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Natural gas is sold by us under contracts with terms ranging from one month to three years. Virtually all of our contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. As a result, our revenues from the sale of natural gas will suffer if market prices decline and benefit if they increase. We believe that the pricing provisions of our natural gas contracts are customary in the industry. +43 +Table of Contents +We currently use the "net-back" method of accounting for transportation arrangements of natural gas sales. We sell gas at the wellhead and collect a price and recognize revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by our customers and reflected in the wellhead price. +Natural gas marketing . Natural gas marketing is reported on the gross accounting method, based on the nature of the agreements between RNG, our suppliers and our customers. RNG, our marketing subsidiary, purchases gas from PDC and other small producers and bundles the gas together to sell in larger amounts to purchasers of natural gas for a price advantage. RNG has latitude in establishing price and discretion in supplier and purchaser selection. Natural gas marketing revenues and expenses reflect the full cost and revenue of those transactions because RNG takes title to the gas it purchases from the various producers and bears the risks and rewards of that ownership. Both the realized and unrealized gains and losses of the RNG commodity-based derivative transactions for natural gas marketing are included in sales from natural gas marketing or cost of natural gas marketing, as applicable. +Well operations and pipeline income . Well operations and pipeline income are recognized when persuasive evidence of an arrangement exists, services have been rendered, collection of revenues is reasonably assured and the sales price is fixed or determinable. We are paid a monthly operating fee for each well we operate for outside owners including the limited partnerships we sponsor. The fee covers monthly operating and accounting costs, insurance and other recurring costs. We may also receive additional compensation for special non-recurring activities, such as workovers and recompletions. +Fair Value of Financial Instruments +Determination of Fair Value. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as: +Level 1 – Quoted prices (unadjusted) in active markets for identical assets or liabilities. Included in Level 1 are our commodity derivative instruments for NYMEX-based natural gas swaps. +Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including (i) quoted prices for similar assets or liabilities in active markets, (ii) quoted prices for identical or similar assets or liabilities in inactive markets, (iii) inputs other than quoted prices that are observable for the asset or liability and (iv) inputs that are derived from observable market data by correlation or other means. +Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Included in Level 3 are our commodity derivative instruments for CIG and PEPL-based natural gas swaps, oil swaps, natural gas and oil collars, and physical sales and purchases and our natural gas basis protection derivative instruments. +Derivative Financial Instruments . We measure fair value of our derivatives based upon quoted market prices, where available. Our valuation determination includes: (1) identification of the inputs to the fair value methodology through the review of counterparty statements and other supporting documentation, (2) determination of the validity of the source of the inputs, (3) corroboration of the original source of inputs through access to multiple quotes, if available, or other information and (4) monitoring changes in valuation methods and assumptions. The methods described above may produce a fair value calculation that may not be indicative of future fair values. Our valuation determination also gives consideration to our nonperformance risk on our own liabilities as well as the credit standing of our counterparties. We primarily use two investment grade financial institutions as our counterparties to our derivative contracts. We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the impact of the nonperformance of our counterparties on the fair value of our derivative instruments is insignificant. As of December 31, 2009, no valuation allowance was recorded. Furthermore, while we believe these valuation methods are appropriate and consistent with that used by other market participants, the use of different methodologies, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value. +44 +Table of Contents +Non-Derivative Financial Assets and Liabilities. The carrying values of the financial instruments comprising cash and cash equivalents and restricted cash approximate fair value due to the short-term maturities of these instruments. +The portion of our long-term debt related to our credit facility, approximates fair value due to the variable nature of its related interest rate. We estimate the fair value of the portion of our long-term debt related to our senior notes to be approximately $210.1 million or approximately 103.5% of par value as of December 31, 2009. We determined this valuation based upon measurements of trading activity. +Natural Gas and Oil Properties +We account for our natural gas and oil properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and development dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing natural gas and oil reserves . Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved natural gas and oil reserves. +Annually, we engage independent petroleum engineers to prepare reserve and economic evaluations of all our properties on a well-by-well basis as of December 31. Additionally, we adjust our natural gas and oil reserves for major acquisitions, new drilling and divestitures during the year as needed. The process of estimating and evaluating natural gas and oil reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent our most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates over time. Because estimates of reserves significantly affect our DD&A expense, a change in our estimated reserves could have an effect on our net income. +Exploration costs, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized but charged to expense if the well is determined to be nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as the well has found a sufficient quantity of reserves to justify our completion as a producing well and we are making sufficient progress assessing our reserves and economic and operating viability. If an in-progress exploratory well is found to be unsuccessful prior to the issuance of the financial statements, the costs incurred, including costs for plugging, prior to the end of the reporting period are expensed to exploration expense and impairment of natural gas and oil properties. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the well is classified as "suspended well costs" until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time when we are able to make a final determination of a well’s productive status, the well is removed from the suspended well status and the proper accounting treatment is applied. +The acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense when expired, impaired or amortized. Unproved natural gas and oil properties with individually significant acquisition costs are periodically assessed, and any impairment in value is charged to exploration expense and impairment of natural gas and oil properties. The amount of impairment recognized on unproved properties which are not individually significant is determined by amortizing the costs of such properties within appropriate fields based on our historical experience, acquisition dates and average lease terms. The valuation of unproved properties is subjective and requires us to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual realizable values. +We assess our natural gas and oil properties for possible impairment by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which we reasonably estimate the commodity to be sold. The estimates of future prices may differ from current market prices of natural gas and oil. Any downward revisions in estimates to our reserve quantities, expectations of falling commodity prices or rising operating costs could result in a reduction in undiscounted future net cash flows and an impairment of our natural gas and oil properties. Although our cash flow estimates are based on the relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results. +45 +Table of Contents +Deferred Income Tax Asset Valuation Allowance +Deferred income tax assets are recognized for deductible temporary differences, net operating loss carry-forwards and credit carry-forwards if it is more likely than not that the tax benefits will be realized. To the extent a deferred tax asset is not expected to be realized under the preceding criteria, a valuation allowance is established. The factors which we consider in assessing whether we will realize the value of deferred income tax assets involve judgments and estimates of both amount and timing, which could differ from actual results, achieved in future periods. +The judgments used in applying the above policies are based on our evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results may differ from those estimates. +Accounting for Acquisitions Using Purchase Accounting +We utilize the purchase method to account for acquisitions. Pursuant to purchase method accounting, the acquiring company must allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. The purchase price allocations are based on appraisals, discounted cash flows, quoted market prices and estimates by management. In addition, when appropriate, we review comparable purchases and sales of natural gas and oil properties within the same regions, and use that data as a basis for fair market value; for example, the amount a willing buyer and seller would enter into an exchange for such properties. +In estimating the fair values of assets acquired and liabilities assumed we made various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing , proved undeveloped, unproved natural gas and oil properties and other non natural gas and oil properties. To estimate the fair values of these properties, we prepared estimates of natural gas and oil reserves. We estimated future prices to apply to the estimated reserve quantities acquired, and estimated future operating and development costs, to arrive at estimates of future net revenues. For estimated proved reserves, the future net revenues were discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted average cost of capital rate was subjected to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved properties, the discounted future net revenues of probable and possible reserves were reduced by additional risk-weighting factors. +Deferred taxes must be recorded for any differences between the assigned values and tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. +Recent Accounting Standards +See Note 2, Summary of Significant Accounting Policies - Recent Accounting Standards , to our consolidated financial statements included in this report. +Reconciliation of Non-GAAP Financial Measures +Adjusted cash flow from operations . We define adjusted cash flow from operations as the cash flow earned or incurred from operating activities without regard to the collection or payment of associated receivables or payables. We believe it is important to consider adjusted cash flow from operations as well as cash flow from operations, as we believe it often provides more transparency into what drives the changes in our operating trends, such as production, prices, operating costs, and related operational factors, without regard to whether the earned or incurred item was collected or paid during the period. We also use this measure because the collection of our receivables or payment of our obligations has not been a significant issue for our business, but merely a timing issue from one period to the next, with fluctuations generally caused by significant changes in commodity prices. See the Consolidated Statements of Cash Flows in this report. +Adjusted net income (loss) attributable to shareholders . We define adjusted net income (loss) attributable to shareholders as net income (loss) attributable to shareholders plus unrealized derivative losses, provisions for underpayment of gas sales, minus unrealized derivative gains, each adjusted for tax effect. We believe it is important to consider adjusted net income (loss) attributable to shareholders as well as net income (loss) attributable to shareholders. We believe it often provides more transparency into our operating trends, such as production, prices, operating costs, realized gains and losses from derivatives and related factors, without regard to changes in our net income (loss) attributable to shareholders from our mark-to-market adjustments resulting from unrealized gains and losses from derivatives. Additionally, other items, such as the provision for underpayment of gas sales, which are not indicative of future results, may be excluded to clearly identify operational trends. +46 +Table of Contents +Adjusted EBITDA . We define adjusted EBITDA as net income (loss) plus unrealized derivative loss, interest expense, net of interest income, income taxes, and depreciation, depletion and amortization for the period minus unrealized derivative gain. We believe adjusted EBITDA is relevant because it is a measure of cash available to fund our capital expenditures and service our debt and is a widely used industry metric which allows comparability of our results with our peers. +The following table presents a reconciliation of each of our non-GAAP financial measures to its nearest GAAP measure. +Year Ended December 31, +2009 +2008 +2007 +(in thousands, except share and per share data) +Adjusted cash flow from operations: +Net cash provided by operating activities +$ +143,895 +$ +139,101 +$ +60,304 +Total changes in current assets and liabilities +26,319 +60,818 +35,322 +Adjusted cash flow from operations +$ +170,214 +$ +199,919 +$ +95,626 +Adjusted net income (loss) attributable to shareholders: +Net income (loss) attributable to shareholders +$ +(79,277 +) +$ +113,309 +$ +33,209 +Unrealized loss (gain) on derivatives, net +116,623 +(117,536 +) +4,642 +Provision for underpayment of gas sales +2,706 +4,025 +- +Tax effect of above adjustments +(42,981 +) +39,887 +(1,801 +) +Adjusted net income (loss) attributable to shareholders +$ +(2,929 +) +$ +39,685 +$ +36,050 +Adjusted EBITDA: +Net income (loss) attributable to shareholders +$ +(79,277 +) +$ +113,309 +$ +33,209 +Unrealized loss (gain) on derivatives, net +116,623 +(117,536 +) +4,642 +Interest expense, net +36,954 +27,541 +6,617 +Income tax expense (benefit) +(45,636 +) +61,459 +20,981 +Depreciation, depletion and amortization +131,004 +104,640 +70,885 +Adjusted EBITDA +$ +159,668 +$ +189,413 +$ +136,334 +IT EM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK +Market-Sensitive Instruments and Risk Management +We are exposed to market risks associated with interest rates, commodity prices and credit exposure. Management has established risk management processes to monitor and manage these market risks. +Interest Rate Risk +Changes in interest rates affect the amount of interest we earn on our cash, cash equivalents and restricted cash and the interest we pay on borrowings under our bank credit facility. Our 12% senior notes are fixed rate and, therefore, do not expose us to the cash flow loss due to changes in market interest rate. However, changes in interest rates do affect the fair value of our senior notes. +We are exposed to risk resulting from changes in interest rates primarily as it relates to interest we earn on our deposit accounts, including cash, cash equivalents and designated cash, current and noncurrent, and interest we pay on borrowings under our revolving credit facility. Our interest-bearing deposit accounts include money market accounts, certificates of deposit and checking and savings accounts with various banks. The amount of our interest-bearing cash and cash equivalents as of December 31, 2009, is $31.8 million with an average interest rate of 0.9%. +Based on a sensitivity analysis of the credit facility borrowings as of December 31, 2009, it was estimated that if market interest rates were to average 1% higher (lower) in 2010 than in 2009, our interest expense, net of tax, would increase (decrease) by approximately $2.8 million. +47 +Table of Contents +Commodity Price Risk +We are exposed to the effect of market fluctuations in the prices of natural gas and oil. Price risk represents the potential risk of loss from adverse changes in the market price of natural gas and oil commodities. We employ established policies and procedures to manage the risks associated with these market fluctuations using derivative instruments. Our policy prohibits the use of natural gas and oil derivative instruments for speculative purposes. +See Note 3, Fair Value of Financial Instruments , and Note 4, Derivative Financial Instruments , to our consolidated financial statements included in this report for a discussion of how we determine and account for our derivative contracts at fair value. +The following table presents monthly average NYMEX and CIG closing prices for natural gas and oil for the years ended December 31, 2009, and 2008, as well as average sales prices we realized for the respective commodities. +Year Ended December 31, +2009 +2008 +Average Index Closing Price +Natural Gas (per MMBtu) +CIG +$ +3.07 +$ +6.22 +NYMEX +3.99 +9.04 +Oil (per Barrel) +NYMEX +58.36 +104.42 +Average Sales Price +Natural Gas +3.12 +6.98 +Oil +55.03 +89.77 +Based on a sensitivity analysis as of December 31, 2009, it was estimated that a 10% increase or decrease in natural gas and oil prices, inclusive of basis, over the entire period for which we have derivatives then in place would result in a decrease or increase, respectively, in fair value of $55.5 million. +See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Results of Operations, Commodity Price Risk Management, Net and Natural Gas Marketing , for a detailed discussion of open derivative positions related to our natural gas and oil sales activities and our natural gas marketing. See Note 4, Derivative Financial Instruments , to our consolidated financial statements included in this report for a summary of our open derivative positions as of December 31, 2009. +Credit Risk +Credit risk represents the loss that we would incur if a counterparty fails to perform under its contractual obligations. We attempt to reduce credit risk by diversifying our counterparty exposure and entering into transactions with high-quality counterparties. When exposed to credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis. +With regard to our natural gas and oil sales segment, inherent to our industry is the concentration of natural gas and oil sales to a few customers. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions. As for our natural gas marketing segment, our receivables are from a diverse group of companies, including major energy companies, both upstream and mid-stream, financial institutions and end-users in various industries. We monitor their creditworthiness through credit reports and rating agency reports. To date, we have had no counterparty default losses in either of our natural gas and oil sales segment or natural gas marketing segment. See Note 5, Concentration of Risk , to our consolidated financial statements included in this report. +Our derivative financial instruments expose us to the credit risk of nonperformance by the counterparty to the contracts. We primarily use financial institutions, which are also major lenders in our credit facility, as counterparties to our derivative contracts. We have evaluated the credit risk of the counterparties holding our derivative assets using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the impact of the nonperformance of our counterparties on the fair value of our derivative instruments is insignificant. As of December 31, 2009, no adjustment for credit risk was recorded. +48 +Table of Contents +The recent disruption in the credit market has had a significant adverse impact on a number of financial institutions. We monitor the creditworthiness of the financial institutions with which we transact, giving consideration to the reports of credit agencies and their related ratings. While we believe that our monitoring procedures are sufficient and customary, no amount of analysis can guarantee performance in these uncertain times. +Disclosure of Limitations +Because the information above included only those exposures that exist at December 31, 2009, it does not consider those exposures or positions which could arise after that date. As a result, our ultimate realized gain or loss with respect to interest rate and commodity price fluctuations will depend on the exposures that arise during the period, our hedging strategies at the time, and interest rates and commodity prices at the time. +IT EM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +The response to this Item is set forth herein in a separate section of this report, beginning on Page F-1. +IT EM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +None. +IT EM 9A. CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +As of December 31, 2009, we carried out an evaluation under the supervision and with the participation of 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 pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e), and based on the results of this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2009. +Changes in Internal Control over Financial Reporting +During the fourth quarter of 2009, we made no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) that have materially affected or are reasonably likely to materially affect our internal control over financial reporting. +IT EM 9B. OTHER INFORMATION +None. +PART III +IT EM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +The information called for by this Item is incorporated by reference from information under the captions entitled Corporate Governance , Section 16(a) Beneficial Ownership Reporting Compliance , Election of Directors and Executive Compensation and other relevant portions of our definitive proxy statement to be filed pursuant to Regulation 14A no later than 120 days after the close of our fiscal year. +IT EM 11. EXECUTIVE COMPENSATION +The information called for by this Item is incorporated by reference from information under the caption entitled Executive Compensation and other relevant portions of our definitive proxy statement to be filed pursuant to Regulation 14A no later than 120 days after the close of our fiscal year. +49 +Table of Contents +IT EM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +The information called for by this Item is incorporated by reference from information under the caption entitled Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters and other relevant portions of our definitive proxy statement to be filed pursuant to Regulation 14A no later than 120 days after the close of our fiscal year. +IT EM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE +The information called for by this Item is incorporated by reference from information under the captions entitled Certain Relationships and Related Transactions and Director Independence in our definitive proxy statement to be filed pursuant to Regulation 14A no later than 120 days after the close of our fiscal year. +IT EM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES +The information called for by this Item is incorporated by reference from information under the caption entitled Principal Accountant Fees and Services and other relevant portions of our definitive proxy statement to be filed pursuant to Regulation 14A no later than 120 days after the close of our fiscal year. +PART IV +IT EM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES +(a) +(1) +Financial Statements: +See Index to Financial Statements and Schedules on page F-1. +(2) +Financial Statement Schedules: +See Index to Financial Statements and Schedules on page F-1. +Schedules and Financial Statements Omitted +All other financial statement schedules are omitted because they are not required, inapplicable, or the information is included in the Financial Statements or Notes thereto. +(3) +Exhibits: +See Exhibits Index on page 54. +50 +Table of Contents +SI GNATURES +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. +PETROLEUM DEVELOPMENT CORPORATION +By /s/ Richard W. McCullough +Richard W. McCullough, +Chairman, Chief Executive Officer, and President +March 4, 2010 +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/ Richard W. McCullough +Chairman, Chief Executive Officer, and President +March 4, 2010 +Richard W. McCullough +(principal executive officer) +/s/ Gysle R. Shellum +Chief Financial Officer +March 4, 2010 +Gysle R. Shellum +(principal financial officer) +/s/ R. Scott Meyers +Chief Accounting Officer +March 4, 2010 +R. Scott Meyers +(principal accounting officer) +/s/ Daniel W. Amidon +General Counsel, Corporate Secretary +March 4, 2010 +Daniel W. Amidon +/s/ Jeffrey C. Swoveland +Director +March 4, 2010 +Jeffrey C. Swoveland +/s/ Vincent F. D'Annunzio +Director +March 4, 2010 +Vincent F. D'Annunzio +/s/ Kimberly Luff Wakim +Director +March 4, 2010 +Kimberly Luff Wakim +/s/ David C. Parke +Director +March 4, 2010 +David C. Parke +/s/ Anthony J. Crisafio +Director +March 4, 2010 +Anthony J. Crisafio +/s/ Joseph E. Casabona +Director +March 4, 2010 +Joseph E. Casabona +/s/ Larry F. Mazza +Director +March 4, 2010 +Larry F. Mazza +/s/ James M. Trimble +Director +March 4, 2010 +James M. Trimble +51 +Table of Contents +GL OSSARY OF NATURAL GAS AND OIL TERMS +The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report. +CIG - Colorado Interstate Gas. +Completion - The installation of permanent equipment for the production of oil or gas. +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 hydrocarbons in sufficient quantities to justify completion as an oil or gas well. +Exit rate - Natural gas equivalent produced as of the date specified. +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 gas in another reservoir. +Extensions and discoveries - As to any period, the increases to proved reserves from all sources other than the acquisition of proved properties or revisions of previous estimates. +Farm-out - Transfer of all or part of the operating rights from a working interest owner to an assignee, who assumes all or some of the burden of development in return for an interest in the property. The assignor usually retains an overriding royalty but may retain any type of interest. +Gross acres or wells - Refers to the total acres or wells in which we have a working interest. +Horizontal drilling - A drilling technique that permits the operator to contact and intersect a larger portion of the producing horizon than conventional vertical drilling techniques and may, depending on the horizon, result in increased production rates and greater ultimate recoveries of hydrocarbons. +Joint Interest Billing or JIB - Process of distributing the costs related to well completions and operations among working interest partners. +Natural Gas Liquids or NGLs - Hydrocarbons which can be extracted from wet natural gas and become liquid under various combinations of increasing pressure and lower temperature. NGLs consist primarily of ethane, propane, butane, and natural gasolines. +Net acres or wells - Refers to gross acres or wells multiplied, in each case, by the percentage working interest we own. +Net production - Natural gas and oil production that we own, less royalties and production due others. +NYMEX - New York Mercantile Exchange. +Operator - The individual or company responsible for the exploration, development and/or production of an oil or gas well or lease. +PEPL - Panhandle Eastern Pipeline. +Present value of proved reserves - The present value of estimated future revenues, discounted at 10% annually, to be generated from the production of proved reserves determined in accordance with Securities and Exchange Commission guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment, (ii) non-property related expenses such as general and administrative expenses, debt service and future income tax expense, or (iii) DD&A expense. +Proved developed non-producing reserves - Reserves that consist of (i) proved reserves from wells which have been completed and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and (ii) proved reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the wells. +Proved developed producing reserves - Proved reserves that can be expected to be recovered from currently producing zones under the continuation of present operating methods. +52 +Table of Contents +Proved developed reserves - The combination of proved developed producing and proved developed non-producing reserves. +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 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 reasonable certain, regardless of whether deterministic or probabilistic methods are used for the estimation. +Proved undeveloped reserves or PUD - Proved 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 - A recompletion occurs when we reenter a well to complete (i.e., perforate) a new formation different from that in which a well has previously been completed. +Refrac or refracture - A refrac is when we stimulate the present producing zone of a well to increase production, using hydraulic, acid, gravel, etc. fracture techniques. +Reserve replacement - Calculated by dividing the sum of reserve additions from all sources (revisions, extensions, discoveries and other additions and acquisitions) by the actual production for the corresponding period. The values used for reserve additions are derived directly from the proved reserves table located in Supplemental Information - Natural Gas and Oil Operations to our consolidated financial statements included in this report. We use the reserve replacement ratio as an indicator of our ability to replenish annual production volumes and grow our reserves, thereby providing some information on the sources of future production. It should be noted that the reserve replacement ratio is a statistical indicator that has limitations. As an annual measure, the ratio is limited because it typically varies widely based on the extent and timing of new discoveries and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not imbed the cost or timing of future production of new reserves, it cannot be used as a measure of value creation. +Reserves - Estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substance to market, and all permits and financing required to implement the project. +Royalty - An interest in an natural gas and oil lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner. +Standardized measure of discounted future net cash flows - Present value of proved reserves, as adjusted to give effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment, and (ii) estimated future income taxes. +Trunk Line - A pipeline for the transportation of oil or natural gas from producing areas to refineries or terminals. +Undeveloped acreage - Leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil, regardless of whether such acreage contains proved reserves. +Wellbore - A physical hole that makes up the well, and can be cased, open or a combination of both. +Working interest - An interest in an natural gas and oil lease that gives the owner of the interest the right to drill for and produce natural gas and oil on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest is entitled will be smaller than the share of costs that the working interest owner is required to bear to the extent of any royalty burden. +Workover - Operations on a producing well to restore or increase production. +53 +Table of Contents +Exhibits Index +Incorporated by Reference +Exhibit Number +Exhibit Description +Form +SEC File +Number +Exhibit +Filing Date +Filed +Herewith +3.1 +Second Amended and Restated Certificate of Incorporation of Petroleum Development Corporation. +8-K +000-07246 +3.1 +7/23/2008 +3.2 +Bylaws of Petroleum Development Corporation, amended and restated, effective October 11, 2007. +8-K +000-07246 +3.2 +10/17/2007 +4.1 +Rights Agreement by and between Petroleum Development Corporation and Transfer Online, Inc., as Rights Agent, dated as of September 11, 2007, including the forms of Rights Certificates and Summary of Stockholder Rights Plan attached thereto as Exhibits A and B. +8-K +000-07246 +4.1 +9/14/2007 +4.2 +Indenture dated as of February 8, 2008, by and among Petroleum Development Corporation and The Bank of New York. +8-K +000-07246 +4.1 +2/12/2008 +4.3 +First Supplemental Indenture dated as of February 8, 2008, by and among Petroleum Development Corporation and the Bank of New York. +8-K +000-07246 +4.2 +2/12/2008 +4.4 +Form of 12% Senior Note due 2018. +8-K +000-07246 +4.3 +2/12/2008 +10.1 +Purchase Agreement dated as of February 1, 2008, by and among Petroleum Development Corporation and the Initial Purchasers of 12% senior notes due 2018 named therein. +8-K +000-07246 +10.1 +2/7/2008 +10.2 +Registration Rights Agreement dated as of February 8, 2008, by and among Petroleum Development Corporation and the Initial Purchasers of 12% senior notes due 2018 named therein. +8-K +000-07246 +10.1 +2/12/2008 +10.3 +Amended and Restated Credit Agreement dated as of November 4, 2005, Petroleum Development Corporation, as borrower and JPMorgan Chase Bank, N.A and BNP Paribas, as lenders. +8-K +000-07246 +10.1 +11/4/2005 +10.4 +First Amendment to Amended and Restated Credit Agreement, dated as of August 9, 2007, by and among Petroleum Development Corporation, certain of its subsidiaries, JPMorgan Chase Bank, N.A., BNP Paribas and Wachovia Bank, N.A. +8-K +000-07246 +10.1 +8/15/2007 +10.5 +Second Amendment to Amended and Restated Credit Agreement, dated as of October 16, 2007, by and among Petroleum Development Corporation, certain of its subsidiaries, JPMorgan Chase Bank, N.A., and various other banks. +8-K +000-07246 +10.1 +10/22/2007 +54 +Table of Contents +Incorporated by Reference +Exhibit Number +Exhibit Description +Form +SEC File +Number +Exhibit +Filing Date +Filed +Herewith +10.6 +Third Amendment to Amended and Restated Credit Agreement dated as of July 15, 2008, by and among Petroleum Development Corporation, certain of its subsidiaries, JP Morgan Chase Bank, N.A., and various other banks. +8-K +000-07246 +10.1 +7/21/2008 +10.7 +Fourth Amendment to Amended and Restated Credit Agreement dated as of July 18, 2008, by and among the Company, certain of its subsidiaries, JP Morgan Chase Bank, N.A., and various other banks. +8-K +000-07246 +10.2 +7/21/2008 +10.8 +Fifth Amendment to Amended and Restated Credit Agreement dated as of November 12, 2008, by and among the Company, certain of its subsidiaries, JP Morgan Chase Bank, N.A., and various other banks. +8-K +000-07246 +10.1 +11/19/2008 +10.9 +Sixth Amendment to Amended and Restated Credit Agreement dated as of May 22, 2009, by and among the Company, certain of its subsidiaries, JPMorgan Chase Bank, N.A., and various other banks. +8-K +000-07246 +10.1 +5/29/2009 +10.10 +Seventh Amendment to Amended and Restated Credit Agreement entered into as of October 29, 2009, by and among Petroleum Development Corporation, certain of its subsidiaries, JPMorgan Chase Bank, N.A. and various other banks. +8-K +000-07246 +10.2 +11/4/2009 +10.11 +Eighth Amendment to Amended and Restated Credit Agreement entered into as of December 18, 2009, by and among Petroleum Development Corporation, certain of its subsidiaries, JPMorgan Chase Bank, N.A. and various other banks. +X +10.12 +Underwriting Agreement dated August 11, 2009 among the Company and J.P. Morgan Securities Inc., as representative of the several Underwriters named therein. +8-K +000-07246 +1.1 +8/11/2009 +10.13* +2009 Short-Term Incentive Compensation Terms for Executive Officers. +8-K +000-07246 +4/6/2009 +10.14* +2009 Long-Term Incentive Program (as amended for 2009) for Executive Officers. +8-K +000-07246 +10.1 +3/5/2009 +10.15* +Non-Employee Director Compensation for the 2009-2010 Term. +8-K +000-07246 +3/5/2009 +10.16* +2009 Base Salary Program for Executive Officers. +8-K +000-07246 +1/7/2009 +10.17* +2006 Long-Term Equity Compensation Grants to Executive Officers. +8-K +000-07246 +10.20 +4/10/2007 +10.18* +Employment agreement with R. Scott Meyers, Chief Accounting Officer. +8-K +000-07246 +4/8/2009 +10.19* +Indemnification Agreement with Directors. +10-Q +000-07246 +10.1 +8/9/2007 +55 +Table of Contents +Incorporated by Reference +Exhibit Number +Exhibit Description +Form +SEC File +Number +Exhibit +Filing Date +Filed +Herewith +10.20* +The Petroleum Development Corporation 401(k) & Profit Sharing Plan. +S-8 +333-137836 +4.1 +10/5/2006 +10.21* +2005 Non-Employee Director Restricted Stock Plan, amended and restated as of March 8, 2008. +S-8 +000-07246 +10.1 +2/26/2009 +10.22* +Separation Agreement of Steven R. Williams, former Director. +8-K +000-07246 +4/29/2009 +10.23* +Resignation of Eric R. Stearns, Executive Vice President. +8-K +000-07246 +5/22/2009 +10.24 +Contribution Agreement by and among PDC Mountaineer, LLC, as the Company, Petroleum Development Corporation, as the Contributor, and LR-Mountaineer Holdings, L.P., as the Investor, dated October 29, 2009. +8-K +000-07246 +2.1 +11/4/2009 +10.25 +Limited Liability Company Agreement of PDC Mountaineer, LLC, dated October 29, 2009. +8-K +000-07246 +10.1 +11/4/2009 +12.1 +Computation of Ratio of Earnings to Fixed Charges. +X +14.1 +Code of Business Conduct and Ethics. +10-Q +000-07246 +14.1 +8/10/2009 +21.1 +Subsidiaries. +X +23.1 +Consent of PricewaterhouseCoopers LLP. +X +23.2 +Consent of Wright & Company, Inc., Petroleum Consultants. +X +23.3 +Consent of Ryder Scott Company, L.P., Petroleum Consultants. +X +31.1 +Certification by Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. +X +31.2 +Certification by Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. +X +32.1 +Certifications by Chief Executive Officer and Chief Financial Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002. +X +99.1 +Report of Independent Petroleum Consultants - Wright & Company, Inc. +X +99.2 +Report of Independent Petroleum Consultants - Ryder Scott Company, L.P. +X +*Management contract or compensatory plan or arrangement. +56 +Table of Contents +Index to Consolidated Financial Statements and Financial Statement Schedule +Management's Report on Internal Control Over Financial Reporting +F-2 +Financial Statements: +Report of Independent Registered Public Accounting Firm +F-3 +Consolidated Balance Sheets - December 31, 2009 and 2008 +F-4 +Consolidated Statements of Operations - Years Ended December 31, 2009, 2008 and 2007 +F-5 +Consolidated Statements of Cash Flows - Years Ended December 31, 2009, 2008 and 2007 +F-6 +Consolidated Statements of Equity - Years Ended December 31, 2009, 2008 and 2007 +F-7 +Notes to Consolidated Financial Statements +Note 1 – Nature of Operations and Basis of Presentation +F-8 +Note 2 – Summary of Significant Accounting Policies +F-8 +Note 3 – Fair Value of Financial Instruments +F-17 +Note 4 – Derivative Financial Instruments +F-19 +Note 5 – Concentration of Credit Risk +F-21 +Note 6 – Properties and Equipment +F-23 +Note 7 – Income Taxes +F-24 +Note 8 – Long-Term Debt +F-26 +Note 9 – Asset Retirement Obligations +F-29 +Note 10 – Employee Benefit Plans +F-29 +Note 11 – Commitments and Contingencies +F-29 +Note 12 – Common Stock +F-33 +Note 13 – Noncontrolling Interest in Subsidiaries +F-37 +Note 14 – Business Segments +F-38 +Note 15 – Transactions with Affiliates +F-39 +Note 16 – Discontinued Operations +F-40 +Note 17 – Sale of Natural Gas and Oil Properties +F-41 +Note 18 – Acquisitions +F-41 +Supplemental Information – Unaudited +Natural Gas and Oil Operations +F-43 +Quarterly Financial Data +F-48 +Financial Statement Schedule: +Schedule II – Valuation and Qualifying Accounts and Reserves +F-50 +F-1 +Table of Contents +Ma nagement's Report on Internal Control Over Financial Reporting +Management is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. 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. 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 policies or procedures may deteriorate. +Management has assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2009, based upon the criteria established in "Internal Control – Integrated Framework" issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). Based on this evaluation, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2009. +The effectiveness of Petroleum Development Corporation's internal control over financial reporting as of December 31, 2009, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein. +PETROLEUM DEVELOPMENT CORPORATION +/s/ Richard W. McCullough +Richard W. McCullough +Chairman and Chief Executive Officer +/s/ Gysle R. Shellum +Gysle R. Shellum +Chief Financial Officer +/s/ R. Scott Meyers +R. Scott Meyers +Chief Accounting Officer +F-2 +Table of Contents +Re port of Independent Registered Public Accounting Firm +To the Board of Directors and Shareholders of Petroleum Development Corporation: +In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, equity, and cash flows present fairly, in all material respects, the financial position of Petroleum Development Corporation and its subsidiaries at 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. In addition, in our opinion, the financial statement schedule appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting 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 (COSO). The Company's management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated 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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. +As discussed in Note 7 to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain tax positions in 2007. +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 (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 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. +/s/ PricewaterhouseCoopers LLP +Pittsburgh, Pennsylvania +March 4, 2010 +F-3 +Table of Contents +Pe troleum Development Corporation +Consolidated Balance Sheets +(in thousands, except share and per share data) +December 31, +2009 +2008 +Assets +Current assets: +Cash and cash equivalents +$ +31,944 +$ +50,950 +Restricted cash +2,490 +19,030 +Accounts receivable, net +56,491 +69,688 +Accounts receivable affiliates +7,956 +16,742 +Fair value of derivatives +42,223 +116,881 +Income tax receivable +27,728 +- +Prepaid expenses and other current assets +8,538 +19,146 +Total current assets +177,370 +292,437 +Properties and equipment, net +1,008,193 +1,033,078 +Fair value of derivatives +20,228 +47,155 +Accounts receivable affiliates +15,473 +1,605 +Other assets +29,063 +28,429 +Total Assets +$ +1,250,327 +$ +1,402,704 +Liabilities and Equity +Liabilities +Current liabilities: +Accounts payable +$ +36,845 +$ +90,532 +Accounts payable affiliates +13,015 +40,540 +Production tax liability +24,849 +18,226 +Fair value of derivatives +20,208 +4,766 +Funds held for distribution +28,256 +50,361 +Deferred income taxes +- +28,355 +Other accrued expenses +21,261 +28,391 +Total current liabilities +144,434 +261,171 +Long-term debt +280,657 +394,867 +Deferred income taxes +178,012 +162,593 +Asset retirement obligation +29,314 +23,036 +Fair value of derivatives +48,779 +5,720 +Accounts payable affiliates +5,996 +10,136 +Other liabilities +24,542 +32,906 +Total liabilities +711,734 +890,429 +COMMITMENTS AND CONTINGENT LIABILITIES +Equity +Shareholders' equity: +Preferred shares, par value $.01 per share; authorized 50,000,000 shares; issued: none +- +- +Common shares, par value $.01 per share; authorized 100,000,000 shares; issued: 19,242,219 in 2009 and 14,871,870 in 2008 +192 +149 +Additional paid-in capital +64,406 +5,818 +Retained earnings +426,629 +505,906 +Treasury shares, at cost: 8,273 shares in 2009 and 7,066 in 2008 +(312 +) +(292 +) +Total shareholders' equity +490,915 +511,581 +Noncontrolling interest in subsidiaries +47,678 +694 +Total equity +538,593 +512,275 +Total Liabilities and Equity +$ +1,250,327 +$ +1,402,704 +See accompanying Notes to Consolidated Financial Statements. +F-4 +Table of Contents +Pe troleum Development Corporation +Consolidated Statements of Operations +(in thousands, except per share data) +Year Ended December 31, +2009 +2008 +2007 +Revenues: +Natural gas and oil sales +$ +179,093 +$ +321,877 +$ +175,187 +Sales from natural gas marketing +64,635 +140,263 +103,624 +Commodity price risk management gain (loss), net +(10,053 +) +127,838 +2,756 +Well operations, pipeline income and other +11,043 +11,767 +10,170 +Total revenues +244,718 +601,745 +291,737 +Costs and expenses: +Natural gas and oil production and well operations costs +64,746 +79,354 +49,833 +Cost of natural gas marketing +62,534 +139,234 +100,584 +Exploration expense and impairment of natural gas and oil properties +22,887 +45,105 +23,551 +General and administrative expense +53,985 +37,715 +30,968 +Depreciation, depletion, and amortization +131,004 +104,640 +70,885 +Total costs and expenses +335,156 +406,048 +275,821 +Gain on sale of leaseholds +470 +- +33,291 +Income (loss) from operations +(89,968 +) +195,697 +49,207 +Interest income +254 +591 +2,662 +Interest expense +(37,208 +) +(28,132 +) +(9,279 +) +Income (loss) from continuing operations before income taxes +(126,922 +) +168,156 +42,590 +Provision (benefit) for income taxes +(45,716 +) +59,089 +16,505 +Income (loss) from continuing operations +(81,206 +) +109,067 +26,085 +Income from discontinued operations, net of tax +113 +4,177 +7,083 +Net income (loss) +(81,093 +) +113,244 +33,168 +Less: net loss attributable to noncontrolling interests +(1,816 +) +(65 +) +(41 +) +Net income (loss) attributable to shareholders +$ +(79,277 +) +$ +113,309 +$ +33,209 +Amounts attributable to Petroleum Development Corporation shareholders: +Income (loss) from continuing operations +$ +(79,390 +) +$ +109,132 +$ +26,126 +Income from discontinued operations, net of tax +113 +4,177 +7,083 +Net income (loss) attributable to shareholders +$ +(79,277 +) +$ +113,309 +$ +33,209 +Earnings (loss) per share attributable to shareholders: +Basic +Income (loss) from continuing operations +$ +(4.83 +) +$ +7.41 +$ +1.77 +Income from discontinued operations +0.01 +0.28 +0.48 +Net income (loss) attributable to shareholders +$ +(4.82 +) +$ +7.69 +$ +2.25 +Diluted +Income (loss) from continuing operations +$ +(4.83 +) +$ +7.35 +$ +1.76 +Income from discontinued operations +0.01 +0.28 +0.48 +Net income (loss) attributable to shareholders +$ +(4.82 +) +$ +7.63 +$ +2.24 +Weighted average common shares outstanding +Basic +16,448 +14,736 +14,744 +Diluted +16,448 +14,848 +14,841 +See accompanying Notes to Consolidated Financial Statements. +F-5 +Table of Contents +Pe troleum Development Corporation +Consolidated Statements of Cash Flows +(in thousands) +Year Ended December 31, +2009 +2008 +2007 +Cash flows from operating activities: +Net income (loss) +$ +(81,093 +) +$ +113,244 +$ +33,168 +Adjustments to net income (loss) to reconcile to net cash provided by operating activities: +Unrealized (gain) loss on derivatives, net +116,623 +(117,536 +) +4,642 +Depreciation, depletion and amortization +131,004 +104,640 +70,885 +Impairment of natural gas and oil properties +926 +22,091 +1,485 +Expired and abandoned leases +7,279 +3,633 +1,786 +Exploratory dry hole costs +1,059 +6,504 +1,775 +Accretion of asset retirement obligation +1,368 +1,230 +999 +Stock-based compensation +5,935 +6,702 +2,286 +Excess tax benefits from stock-based compensation +- +(1,031 +) +(673 +) +Loss (gain) from sale of leaseholds/assets +(105 +) +19 +(33,322 +) +Amortization of debt issuance costs +5,302 +1,344 +394 +Deferred income taxes +(18,084 +) +59,079 +12,201 +Changes in current assets and liabilities: +Decrease (increase) in restricted cash +15,564 +(4,257 +) +(14,254 +) +Decrease (increase) in accounts receivable +13,197 +(9,664 +) +(16,456 +) +Decrease (increase) in accounts receivable - affiliates +14,282 +(7,631 +) +(2,302 +) +Increase (decrease) in income taxes receivable +(27,728 +) +- +- +Decrease (increase) in other current assets +16,478 +(7,855 +) +6,124 +Increase (decrease) in production tax liability +(4,541 +) +9,857 +10,802 +Increase (decrease) in accounts payable and accrued expenses +(22,482 +) +2,790 +(10,869 +) +Increase (decrease) in accounts payable - affiliates +(7,566 +) +10,282 +(3,099 +) +Increase (decrease) in advances for future drilling contracts +(1,675 +) +(66,742 +) +13,645 +Increase (decrease) in funds held for future distribution +(22,105 +) +10,538 +7,488 +Other +257 +1,864 +(26,401 +) +Total changes in current assets and liabilities +(26,319 +) +(60,818 +) +(35,322 +) +Net cash provided by operating activities +143,895 +139,101 +60,304 +Cash flows from investing activities: +Capital expenditures +(143,033 +) +(323,153 +) +(238,988 +) +Acquisition of oil and gas properties, net of cash acquired +- +- +(255,661 +) +Decrease (increase) in restricted cash +- +(874 +) +191,156 +Proceeds from sale of leases to partnerships +- +448 +1,371 +Proceeds from sale of leaseholds/assets +755 +538 +34,701 +Net cash used in investing activities +(142,278 +) +(323,041 +) +(267,421 +) +Cash flows from financing activities: +Proceeds from credit facility +285,086 +419,000 +352,000 +Proceeds from senior notes +- +200,101 +- +Payment of credit facility +(399,586 +) +(459,500 +) +(254,000 +) +Payment of debt issuance costs +(9,249 +) +(5,571 +) +(1,468 +) +Proceeds from sale of equity, net of issuance costs +48,490 +- +- +Proceeds from exercise of stock options +- +627 +183 +Excess tax benefits from stock-based compensation +- +1,031 +673 +Contribution from noncontrolling interest +55,000 +- +800 +Purchase of treasury stock +(364 +) +(5,549 +) +(646 +) +Net cash provided by (used in) financing activities +(20,623 +) +150,139 +97,542 +Net decrease in cash and cash equivalents +(19,006 +) +(33,801 +) +(109,575 +) +Cash and cash equivalents, beginning of year +50,950 +84,751 +194,326 +Cash and cash equivalents, end of year +$ +31,944 +$ +50,950 +$ +84,751 +Supplemental cash flow information: +Cash payments for: +Interest, net of capitalized interest +$ +32,014 +$ +19,200 +$ +9,535 +Income taxes, net of refunds +(3,355 +) +(530 +) +43,785 +Non-cash investing activities: +Change in accounts payable related to purchases of properties and equipment +(36,765 +) +8,197 +32,820 +Change in accounts payable - affiliates related to acquisition of partnerships +- +- +668 +Change in accounts payable - affiliates related to investment in drilling partnership +- +- +18,712 +Change in deferred tax liability resulting from reallocation of acquisition purchase price +- +- +4,188 +Change in asset retirement obligation, with a corresponding increase to oil and gas properties, net of disposals +5,110 +1,153 +7,850 +See accompanying Notes to Consolidated Financial Statements. +F-6 +Table of Contents +Pe troleum Development Corporation +Consolidated Statements of Equity +(in thousands, except share and per share data) +Year Ended December 31, +2009 +2008 +2007 +Common shares, par value $.01 per share - shares issued: +Shares at beginning of year +14,871,870 +14,907,679 +14,834,871 +Adjust prior conversion of predecessor shares +- +100 +- +Shares issued pursuant to sale of equity +4,312,500 +- +- +Exercise of stock options +- +25,699 +38,000 +Issuance of stock awards, net of forfeitures +79,246 +21,863 +46,828 +Retirement of treasury shares +(21,397 +) +(83,471 +) +(12,020 +) +Shares at end of year +19,242,219 +14,871,870 +14,907,679 +Treasury shares: +Shares at beginning of year +(7,066 +) +(5,894 +) +(4,706 +) +Purchase of treasury shares +(21,397 +) +(83,471 +) +(12,020 +) +Retirement of treasury shares +21,397 +83,471 +12,020 +Non-employee directors' deferred compensation plan +(1,207 +) +(1,172 +) +(1,188 +) +Shares at end of year +(8,273 +) +(7,066 +) +(5,894 +) +Common shares outstanding +19,233,946 +14,864,804 +14,901,785 +Equity: +Shareholders' equity +Preferred shares, $.01 par: +Balance at beginning and end of year +$ +- +$ +- +$ +- +Common shares +Balance at beginning of year +149 +149 +148 +Shares issued pursuant to sale of equity +43 +- +- +Issuance of stock awards, net of forfeitures +- +- +1 +Balance at end of year +192 +149 +149 +Additional paid-in capital: +Balance at beginning of year +5,818 +2,559 +64 +Proceeds from sale of equity +48,447 +- +- +Issuance of stock awards, net of forfeitures +- +- +(1 +) +Exercise of stock options +- +627 +183 +Stock-based compensation expense +5,935 +6,702 +2,286 +Retirement of treasury shares +(364 +) +(5,101 +) +(646 +) +Tax benefit (detriment) of stock-based compensation +(1,630 +) +1,031 +673 +Contribution from noncontrolling interest +55,000 +- +- +Reclass of noncontrolling interest in PDC Mountaineer, LLC +(48,800 +) +- +- +Balance at end of year +64,406 +5,818 +2,559 +Retained earnings: +Balance at beginning of year +505,906 +393,044 +360,102 +Retirement of treasury shares +- +(447 +) +- +Adoption of new uncertain tax position rule +- +- +(267 +) +Net income (loss) attributable to shareholders +(79,277 +) +113,309 +33,209 +Balance at end of year +426,629 +505,906 +393,044 +Treasury shares, at cost: +Balance at beginning of year +(292 +) +(226 +) +(170 +) +Purchase of treasury shares +(364 +) +(5,549 +) +(646 +) +Retirement of treasury shares +364 +5,549 +646 +Non-employee directors' deferred compensation plan +(20 +) +(66 +) +(56 +) +Balance at end of year +(312 +) +(292 +) +(226 +) +Total shareholders' equity +490,915 +511,581 +395,526 +Noncontrolling interests in subsidiary +Balance at beginning of year +694 +759 +- +Noncontrolling interest in PDC Mountaineer, LLC +48,800 +- +800 +Net loss attributed to noncontrolling interest in subsidiary +(1,816 +) +(65 +) +(41 +) +Balance at end of year +47,678 +694 +759 +Total noncontrolling interests in subsidiary +47,678 +694 +759 +Total Equity +$ +538,593 +$ +512,275 +$ +396,285 +See accompanying Notes to Consolidated Financial Statements +F-7 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NO TE 1 – NATURE OF OPERATIONS AND BASIS OF PRESENTATION +Petroleum Development Corporation ("PDC," "we," "us" or "the Company") is a domestic independent natural gas and oil company engaged in the exploration for and the acquisition, development, production and marketing of natural gas and oil. As of December 31, 2009, we owned an interest in and operated approximately 5,000 gross wells located primarily in the Rocky Mountain Region and Appalachian Basin. We are engaged in two primary business segments: (1) natural gas and oil sales and (2) natural gas marketing. +The consolidated financial statements include the accounts of all wholly-owned subsidiaries and all entities in which we have a controlling financial interest, including a variable interest entity, and our proportionate share of our affiliated partnerships. All material intercompany accounts and transactions have been eliminated in consolidation, including our proportionate share of all significant transactions between us and the limited partnerships. +We determine whether we have a controlling financial interest in an entity by first evaluating whether the entity is a variable interest entity ("VIE") or a voting interest entity. VIEs are entities in which (i) the total equity investment at risk is insufficient to enable the entity to finance itself independently, (ii) the equity holders lack the obligation to absorb expected losses or the right to receive residual returns or (iii) the equity holders have voting rights that are not proportionate to their economic interests. The entity that absorbs the majority of the VIE's losses or receives the majority of the residual returns is considered the primary beneficiary and consolidates the VIE. See Note 13, Noncontrolling Interest in Subsidiaries . +We account for our interests in natural gas and oil limited partnerships under the proportionate consolidation method. Under this method, our consolidated financial statements include our investments in the partnerships recorded by our working interest in each well, thereby accumulating our pro rata share of assets, liabilities, revenues and expenses of the limited partnerships in which we participate. +The preparation of our consolidated financial statements in accordance with generally accepted accounting principles in the United States of America ("U.S.") requires us to make estimates and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to our consolidated financial statements include estimates of natural gas and oil sales revenue, natural gas and oil reserves, future cash flows from natural gas and oil properties, valuation of derivative instruments and valuation of deferred income tax assets. +Certain reclassifications have been made to prior period financial statements to conform to the current year presentation, specifically: +· +the noncontrolling interest portion of pre-tax expense incurred by and belonging to the minority interest holders of WWWV, LLC was reclassified from depreciation, depletion and amortization ("DD&A") expense to loss attributable to noncontrolling interest (see Note 13, Noncontrolling Interest in Subsidiaries ), and +· +oil and gas well drilling revenues and costs were reclassified to discontinued operations (see Note 16, Discontinued Operations ). +NO TE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Cash Equivalents +We consider all highly liquid investments with original maturities of three months or less to be cash equivalents. +Restricted Cash +Litigation Settlement . Pursuant to a preliminary court approved litigation settlement agreement reached in October 2008, we funded an escrow account in November 2008 in the amount of $8.2 million, of which $5.8 million represented the Company’s share of the settlement and the remainder represented the share of our affiliated partnerships for which we serve as the managing general partner. Settlement distribution checks were mailed in July 2009 and as of December 31, 2009, the remaining escrow balance was immaterial. As of December 31, 2008, the current portion of restricted cash included $8.2 million and accounts receivable from our affiliated partnerships included $2.4 million related to this settlement. +F-8 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Production Tax Liability Over Withheld . Originating in 2001 and continuing through September 2006, we over withheld estimated production taxes from oil and gas production proceeds. In June 2007, we funded an escrow account in the amount of $14.1 million for amounts due to the limited partners of our sponsored drilling partnerships for this over withholding. In October 2008, as part of a pre-filing agreement, we paid the Internal Revenue Service ("IRS") on behalf of the limited partners an estimated tax payment of $4.2 million. In September 2009, we refunded to the limited partners of our sponsored partnerships their share of this over withholding. As of December 31, 2009 and 2008, the current portion of restricted cash included $2.2 million and $10.5 million, respectively, including interest, related to this settlement. The remaining balance is for final payment to state taxing authorities and other working interest owners outside of our affiliated partnerships. +Other . We are required by certain government agencies or agreements to maintain bonds or cash accounts for various operating activities. As of December 31, 2009 and 2008, we had collateral in the form of certificates of deposit and cash totaling $3.1 million and $2.2 million, respectively, which are reflected in other assets. +Inventory +Inventory consists of oil, stated at the lower of cost to produce or market, and other production supplies intended to be used in our natural gas and oil operations. As of December 31, 2009 and 2008, inventory of $0.8 million and $4.3 million, respectively, is included in prepaid expense and other current assets on the balance sheets. +Derivative Financial Instruments +We are exposed to the effect of market fluctuations in the prices of natural gas and oil. Price risk represents the potential risk of loss from adverse changes in the market price of natural gas and oil commodities. We employ established policies and procedures to manage the risks associated with these market fluctuations using commodity derivative instruments. Our policy prohibits the use of natural gas and oil derivative instruments for speculative purposes. +All derivative assets and liabilities are recorded on the balance sheets at fair value. We have elected not to designate any of our derivative instruments as hedges. Classification of realized and unrealized gains and losses resulting from maturities and changes in fair value of open derivatives depends on the purpose for issuing or holding the derivative. Accordingly, changes in the fair value of our derivative instruments are recorded in the statements of operations, with the exception of changes in fair value related to those derivatives we designated to our affiliated partnerships. Changes in the fair value of derivative instruments related to our natural gas and oil sales are recorded in commodity price risk management, net. Changes in the fair value of derivative instruments related to our natural gas marketing segment are recorded in sales from and cost of natural gas marketing. Changes in the fair value of the derivative instruments designated to our affiliated partnerships are recorded on the balance sheets in accounts payable affiliates and accounts receivable affiliates. As positions designated to our affiliated partnerships settle, the realized gains and losses are netted for distribution. Net realized gains are paid to the partnerships and net realized losses are deducted from the partnerships’ cash distributions from production. The affiliated partnerships bear their designated share of counterparty risk. +Validation of a contract’s fair value is performed internally and while we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. See Note 3, Fair Value of Financial Instruments , and Note 4, Derivative Financial Instruments , for a discussion of our derivative fair value measurements and a summary fair value table of our open positions as of December 31, 2009 and 2008, respectively. +Properties and Equipment +Natural Gas and Oil Properties +We account for our natural gas and oil properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and development dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing natural gas and oil reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved natural gas and oil reserves. +F-9 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Our estimates of proved reserves are based on those quantities of natural gas and oil, which, by analysis of geoscience and engineering data, are estimated with reasonable certainty to be economically producible in the future from known reservoirs, under existing conditions, operating methods, and government regulations. Annually, we engage independent petroleum engineers to prepare reserve and economic evaluations of all our properties on a well-by-well basis as of December 31. Additionally, we adjust our natural gas and oil reserves for major acquisitions, new drilling and divestitures during the year as needed. The process of estimating and evaluating natural gas and oil reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent our most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. Because estimates of reserves significantly affect our DD&A expense, a change in our estimated reserves could have an effect on our net income. +Exploration costs, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized but charged to expense if the well is determined to be nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as the well has found a sufficient quantity of reserves to justify our completion as a producing well and we are making sufficient progress assessing our reserves and economic and operating viability. If an in-progress exploratory well is found to be unsuccessful prior to the issuance of the financial statements, the costs incurred, including costs for plugging, prior to the end of the reporting period are expensed to exploration expense and impairment of natural gas and oil properties. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the costs associated with the well are classified as "suspended well costs" until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time we are able to make a final determination of a well’s productive status, the same well is removed from the suspended well status and the proper accounting treatment is recorded. See Note 6, Properties and Equipment, for disclosure related to changes in our capitalized exploratory well costs from January 1, 2007, to December 31, 2009. +The acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense when expired, impaired or amortized. Unproved natural gas and oil properties with individually significant acquisition costs are periodically assessed, and any impairment in value is charged to exploratory expense. The amount of impairment recognized on unproved properties which are not individually significant is determined by amortizing the costs of such properties within appropriate fields based on our historical experience, acquisition dates and average lease terms. Impairment charges are recorded in the statements of operations as a component of exploration expense and impairment of natural gas and oil properties. +The following table presents expiration, impairment and amortization charges recorded for unproved properties. +2009 +2008 +2007 +(in thousands) +Individually significant unproved properties (1) +$ +3,831 +$ +9,165 +$ +1,484 +Insignificant unproved properties +3,448 +3,633 +1,786 +Total +$ +7,279 +$ +12,798 +$ +3,270 +__________ +(1) +2008 includes an impairment of $7.5 million related to our properties in the Fort Worth Basin. +The valuation of unproved properties is subjective and requires us to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual realizable values. +F-10 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +We assess our producing natural gas and oil properties for possible impairment, upon a triggering event, by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which we reasonably estimate the commodity to be sold. The estimates of future prices may differ from current market prices of natural gas and oil. Certain events, including but not limited to, downward revisions in estimates to our reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event and, therefore, a possible impairment of our natural gas and oil properties. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis and is measured by the amount by which the net capitalized costs exceed their fair value. +Upon sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is credited or charged to income. Upon sale of individual wells, the proceeds are credited to accumulated DD&A. +Other Property and Equipment +The following table presents the estimated useful lives of our other property and equipment. +Pipelines and related facilities +10 - 17 years +Transportation and other equipment +3 - 20 years +Buildings +30 - 40 years +Pipelines, Transportation Equipment and Other Equipment . Pipelines, transportation equipment and other equipment are carried at cost. Depreciation is provided principally on the straight-line method over the assets estimated useful lives. We review these long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds our estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. During 2009, we recognized an impairment of $0.3 million. No impairments were recorded in 2008 or 2007. +Buildings. Buildings are carried at cost and depreciated on the straight-line method over their estimated useful lives. +Maintenance and repairs on other property and equipment are charged to expense as incurred. Major renewals and improvements are capitalized. Upon the sale or other disposition of assets, the cost and related accumulated DD&A are removed from the accounts, the proceeds are applied thereto and any resulting gain or loss is reflected in income. Total depreciation expense related to other property and equipment was $8.1 million, $7.6 million and $4.3 million in 2009, 2008 and 2007, respectively. +Capitalized Interest +Interest costs are capitalized as part of the historical cost of acquiring assets. Natural gas and oil investments in unproved properties and major development projects, on which DD&A is not currently recorded and on which exploration or development activities are in progress, qualify for capitalization of interest. Major construction projects also qualify for interest capitalization until the asset is ready for service. Capitalized interest is calculated by multiplying our weighted-average interest rate on our debt outstanding by the qualifying costs. Interest capitalized may not exceed gross interest expense for the period. As the qualifying asset is moved to the DD&A pool, the related capitalized interest is also transferred and is amortized over the useful life of the asset. Interest costs of $0.8 million, $2.6 million and $3 million were capitalized in 2009, 2008 and 2007, respectively. +Production Tax Liability +Production tax liability represents estimated taxes, primarily severance, ad valorem and property, to be paid to the states and counties in which we produce natural gas and oil, including the production of our affiliated partnerships. Our share of these taxes is expensed to natural gas and oil production and well operations costs; the partnerships' share is recognized as a receivable in accounts receivable affiliates on the balance sheets. +F-11 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Income Taxes +We account for income taxes under the asset and liability method. We recognize deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. If we determine that it is more likely than not that some portion or all of the deferred tax assets will not be realized, we record a valuation allowance thereby reducing the deferred tax assets to what we consider realizable. As of December 31, 2009, we had recorded a valuation allowance of $0.7 million. No valuation allowance was recorded at December 31, 2008. +Asset Retirement Obligations +We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the well is completely drilled. Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the long-lived asset by the same amount as the liability. Over time, the liabilities are accreted for the change in their present value, through charges to natural gas and oil production and well operations costs. The initial capitalized costs are depleted over the useful lives of the related assets, through charges to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, escalating retirement costs and changes in the estimated timing of settling asset retirement obligations. See Note 9, Asset Retirement Obligations for a reconciliation of the changes in our asset retirement obligation from January 1, 2008, to December 31, 2009. +Retirement of Treasury Shares +We have historically retired all treasury share purchases, with the exception of shares purchased in accordance with our non-employee deferred compensation plan for non-employee directors; see Note 12, Common Stock . As treasury shares are retired, we charge any excess of cost over the par value entirely to additional paid-in-capital, to the extent we have amounts in additional paid-in-capital, with any remaining excess cost being charged to retained earnings. +Revenue Recognition +Natural gas and oil sales . Natural gas and oil sales include the sale of our natural gas and oil produced. +Sales of natural gas are recognized when natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Natural gas is sold by us under contracts with terms ranging from one month to three years. Virtually all of our contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. As a result, our revenues from the sale of natural gas will suffer if market prices decline and benefit if they increase. We believe that the pricing provisions of our natural gas contracts are customary in the industry. +We currently use the "net-back" method of accounting for transportation arrangements of our natural gas sales. We sell gas at the wellhead and collect a price and recognize revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by the customers and reflected in the wellhead price. +Sales of oil are recognized when persuasive evidence of a sales arrangement exists, the oil is verified as produced and is delivered to a purchaser, collection of revenue from the sale is reasonably assured and the sales price is determinable. We are currently able to sell all the oil that we can produce under existing sales contracts with petroleum refiners and marketers. We do not refine any of our oil production. Our crude oil production is sold to purchasers at or near our wells under short-term purchase contracts at prices and in accordance with arrangements that are customary in the industry. +F-12 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Natural gas marketing . Natural gas marketing is reported on the gross method of accounting, based on the nature of the agreements between Riley Natural Gas ("RNG"), our suppliers and our customers. RNG, our marketing subsidiary, purchases gas from many small producers and bundles the gas together to sell in larger amounts to purchasers of natural gas for a price advantage. RNG has latitude in establishing price and discretion in supplier and purchaser selection. Natural gas marketing revenues and expenses reflect the full cost and revenue of those transactions because RNG takes title to the gas it purchases from the various producers and bears the risks and rewards of that ownership. Both the realized and unrealized gains and losses of the RNG commodity-based derivative transactions for natural gas marketing are included in sales from natural gas marketing or cost of natural gas marketing, as applicable. +Well operations and pipeline income. Well operations and pipeline income are recognized when persuasive evidence of an arrangement exists, services have been rendered, collection of revenues is reasonably assured and the sales price is fixed or determinable. We are paid a monthly operating fee for each well we operate and natural gas transported for outside owners including the limited partnerships we sponsored. The fee covers monthly operating and accounting costs, insurance and other recurring costs. We may also receive additional compensation for special non-recurring activities, such as workovers and recompletions. +Stock-Based Compensation +Stock-based compensation is recognized in our financial statements based on the fair value, on the date of grant or modification, of the equity instrument awarded. Stock-based compensation expense is recognized in the financial statements on a straight-line basis over the vesting period for the entire award. To the extent compensation cost relates to employees directly involved in natural gas and oil acquisitions, exploration and development activities, such amounts may be capitalized to properties and equipment. Amounts not capitalized to properties and equipment are recognized in the related cost and expense line item in the statement of operations. No amounts for stock-based compensation were capitalized in 2009, 2008 or 2007. +Earnings Per Share +Basic earnings (loss) per common share ("EPS") is computed by dividing net income (loss), the numerator, by the weighted-average number of common shares outstanding for the period, the denominator. Diluted EPS is similarly computed except that the denominator includes the effect, using the treasury stock method, of our outstanding stock options, unamortized portion of restricted stock and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive. +The following table presents a reconciliation of the weighted average diluted shares outstanding. +2009 +2008 +2007 +(in thousands) +Weighted average common shares outstanding - basic +16,448 +14,736 +14,744 +Dilutive effect of share-based compensation: +Unamortized portion of restricted stock +- +71 +44 +Stock options +- +35 +48 +Non employee director deferred compensation +- +6 +5 +Weighted average common and common share equivalents outstanding - diluted +16,448 +14,848 +14,841 +F-13 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +For 2009, the weighted average common shares outstanding for both basic and diluted were the same, as the effect of dilutive securities were anti-dilutive due to our net loss. The following table presents the weighted average common share equivalents excluded from the calculation of diluted earnings (loss) per share due to their anti-dilutive effect. +2009 +2008 +2007 +(in thousands) +Weighted average common share equivalents excluded from diluted earnings per share due to their anti-dilutive affect: +Unamortized portion of restricted stock +284 +73 +18 +Stock options +10 +- +- +Non employee director deferred compensation +8 +- +- +Total anti-dilutive common share equivalents +302 +73 +18 +Recent Accounting Standards +Recently Adopted Accounting Standards +Accounting Standards Codification +In June 2009, the Financial Accounting Standards Board ("FASB") issued the FASB Accounting Standards Codification™ (the "Codification") thereby establishing the Codification as the source of authoritative accounting principles recognized by the FASB to be applied by nongovernmental entities in the preparation of financial statements in conformity with accounting principles generally accepted in the United States of America ("GAAP"). Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for Securities and Exchange Commission ("SEC") registrants. The FASB will no longer issue new standards in the form of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts; instead, the FASB will issue Accounting Standards Updates. Accounting Standards Updates will not be authoritative in their own right as they will only serve to update the Codification. Effective July 1, 2009, we adopted the Codification. Other than the manner in which new accounting guidance is referenced, the adoption of the Codification did not have a material impact on our financial statements. +Subsequent Events +In May 2009, the FASB issued changes regarding subsequent events, which establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued. Specifically, the guidance sets forth the period after the balance sheet date during which our management should evaluate events or transactions that may occur for potential recognition or disclosure in our financial statements, the circumstances under which we should recognize events or transactions occurring after the balance sheet date in our financial statements, and the disclosures that we should make about events or transactions that occurred after our balance sheet date. We adopted the guidance as of June 30, 2009. See Subsequent Events below. +Business Combinations +In December 2007, the FASB issued changes regarding the accounting for business combinations. The changes require: +· +an acquirer to recognize the assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their acquisition-date fair values; +· +disclosure of the information necessary for investors and other users to evaluate and understand the nature and financial effect of the business combination; and +· +acquisition-related costs to be expensed as incurred. +The changes also amend the accounting for income taxes to require the acquirer to recognize changes in the amount of its deferred tax benefits recognizable due to a business combination either in income from continuing operations in the period of the combination or directly in contributed capital, depending on the circumstances. Further, the changes amend the accounting for income taxes to require, subsequent to a prescribed measurement period, changes to acquisition-date income tax uncertainties to be reported in income from continuing operations and changes to acquisition-date acquiree deferred tax benefits to be reported in income from continuing operations or directly in contributed capital, depending on the circumstances. +F-14 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +In April 2009, the FASB issued additional changes to the accounting for business combinations. These changes apply to all assets acquired and liabilities assumed in a business combination that arises from contingencies and require: +· +an acquirer to recognize at fair value, at the acquisition date, an asset acquired or liability assumed in a business combination that arises from a contingency if the acquisition-date fair value of that asset or liability can be determined during the measurement period; otherwise, the asset or liability should be recognized at the acquisition date if certain defined criteria are met; +· +contingent consideration arrangements of an acquiree assumed by the acquirer in a business combination be recognized initially at fair value; +· +subsequent measurements of assets and liabilities arising from contingencies be based on a systematic and rational method depending on their nature and contingent consideration arrangements be measured subsequently; and +· +disclosures of the amounts and measurements basis of such assets and liabilities and the nature of the contingencies. +The changes above became effective for acquisitions completed on or after January 1, 2009; however, the income tax changes became effective as of that date for all acquisitions, regardless of the acquisition date. We adopted these changes effective January 1, 2009, for which they will be applied prospectively in our accounting for future acquisitions, if any. Upon adoption, we recorded a charge of $1.5 million to general and administrative expense related to acquisition costs deferred at December 31, 2008. +Consolidation – Noncontrolling Interest in a Subsidiary +In December 2007, the FASB issued changes regarding the nature and classification of the noncontrolling interest in a subsidiary in the consolidated financial statements. The changes require the accounting and reporting for minority interests be recharacterized as noncontrolling interests and classified as a component of equity. Additionally, the changes establish reporting requirements that provide sufficient disclosures which clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. We adopted these changes effective January 1, 2009. Upon adoption, we reclassified our noncontrolling interest in WWWV, LLC from the mezzanine section, between liabilities and equity, of the balance sheets, to a component of equity, separate from our shareholders’ equity. +Fair Value Measurements and Disclosures +In August 2009, the FASB issued changes regarding fair value measurements and disclosures to reduce potential ambiguity in financial reporting when measuring the fair value of liabilities. These changes clarify existing guidance that in circumstances in which a quoted price in an active market for the identical liability is not available, an entity is required to measure fair value using either a valuation technique that uses a quoted price of either a similar liability or a quoted price of an identical or similar liability when traded as an asset, or another valuation technique that is consistent with the principles of fair value measurements, such as an income approach (e.g., present value technique). This guidance also states that both a quoted price in an active market for the identical liability and a quoted price for the identical liability when traded as an asset in an active market when no adjustments to the quoted price of the asset are required are Level 1 fair value measurements. We adopted these changes on October 1, 2009. The adoption did not have a material impact on our financial statements. +In February 2008, the FASB delayed by one year (to January 1, 2009) the fair value measurements and disclosure requirements for nonfinancial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). The January 1, 2009, adoption of the fair value measurements and disclosure requirements for our nonfinancial assets and liabilities did not have a material impact on our financial statements. See Note 3, Fair Value of Financial Instruments . +Derivatives and Hedging Disclosures +In March 2008, the FASB issued changes regarding the disclosure requirements for derivative instruments and hedging activities. Pursuant to the changes, enhanced disclosures are required to provide information about (a) how and why we use derivative instruments, (b) how we account for our derivative instruments and related hedged items and (c) how derivative instruments and related hedged items affect our financial position, financial performance and cash flows. We adopted these changes effective January 1, 2009. The adoption did not have a material impact on our financial statements. See Note 4, Derivative Financial Instruments . +F-15 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Oil and Gas Reserve Estimation and Reporting +In January 2009, the SEC published its final rule regarding the modernization of oil and gas reporting, which modifies the SEC’s reporting and disclosure rules for oil and gas reserves. The most notable changes of the final rule include the replacement of the single day period-end pricing to value natural gas and oil reserves to a 12-month average of the first day of the month price for each month within the reporting period. The final rule also permits voluntary disclosure of probable and possible reserves, disclosure previously prohibited by SEC rules. The revised reporting and disclosure requirements were effective for us as of December 31, 2009. Early adoption was not permitted. +In January 2010, the FASB issued changes in its oil and gas reserve estimation and disclosure requirements to align them with the SEC's final rule discussed above. These changes were also effective for us as of December 31, 2009. +We applied the above changes to our financial statements as of and for the year ended December 31, 2009. As a result, our fourth quarter DD&A calculation was based on proved reserves that were calculated using the new SEC reserve reporting guidelines; whereas, DD&A calculations for the first three quarters of 2009 were based on the prior methodology. The impact of using the 12-month average pricing methodology specified under the new SEC reporting rules resulted in an increase of our fourth quarter DD&A expense of approximately $2.9 million. +Recently Issued Accounting Standards +Consolidation – Variable Interest Entities +In June 2009, the FASB issued changes regarding an entity’s analysis to determine whether any of its variable interests constitute controlling financial interests in a variable interest entity. This analysis identifies the primary beneficiary of a variable interest entity as the enterprise that has both of the following characteristics: +· +the power to direct the activities of a variable interest entity that most significantly impact the entity’s economic performance; and +· +the obligation to absorb losses of the entity that could potentially be significant to the variable interest entity or the right to receive benefits from the entity that could potentially be significant to the variable interest entity. +Additionally, the entity is required to assess whether it has an implicit financial responsibility to ensure that a variable interest entity operates as designed when determining whether it has the power to direct the activities of the variable interest entity that most significantly impact the entity’s economic performance. The guidance also requires ongoing reassessments of whether an enterprise is the primary beneficiary of a variable interest entity. These changes are effective for our financial statements issued for fiscal years beginning after November 15, 2009, with earlier adoption prohibited. We have evaluated the impact that the adoption of these changes will have on our joint venture, consolidated financial statements, related disclosure and management’s discussion and analysis. We anticipate that the adoption of these changes will result in deconsolidation of the joint venture on January 1, 2010. Based on the current interpretation of the new guidance, as power over the activities that significantly impact the joint venture is equally shared with our investment partner, we will no longer be considered the primary beneficiary and, hence, will deconsolidate. See Note 13, Noncontrolling Interest in Subsidiaries . +Fair Value Measurements and Disclosures +In January 2010, the FASB issued changes clarifying existing disclosure requirements and requiring gross presentation of activities within the Level 3 roll forward, whereby entities must present separately information about purchases, sales, issuances and settlements. The update also added a new requirement to disclose fair value transfers in and out of Levels 1 and 2 and describe the reasons for the transfers. These changes will be effective for our financial statements issued for the first interim or annual reporting period beginning after December 15, 2009, except for gross presentation of the Level 3 roll forward, which will become effective for annual reporting periods beginning after December 15, 2010. +Subsequent Events +We have evaluated our activities subsequent to December 31, 2009, and have concluded that no material subsequent events have occurred that would require recognition in the financial statements or disclosure in the notes to the financial statements. +F-16 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NO TE 3 – FAIR VALUE OF FINANCIAL INSTRUMENTS +Derivative Financial Instruments +Determination of fair value . Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as: +Level 1 – Quoted prices (unadjusted) in active markets for identical assets or liabilities. Included in Level 1 are our commodity derivative instruments for NYMEX-based natural gas swaps. +Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including (i) quoted prices for similar assets or liabilities in active markets, (ii) quoted prices for identical or similar assets or liabilities in inactive markets, (iii) inputs other than quoted prices that are observable for the asset or liability and (iv) inputs that are derived from observable market data by correlation or other means. +Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Included in Level 3 are our commodity derivative instruments for CIG and PEPL-based natural gas swaps, oil swaps, natural gas and oil collars, physical sales and purchases and our natural gas basis protection derivative instruments. +Derivative Financial Instruments. We measure the fair value of our derivative instruments based upon quoted market prices, where available. Our valuation determination includes: (1) identification of the inputs to the fair value methodology through the review of counterparty statements and other supporting documentation, (2) determination of the validity of the source of the inputs, (3) corroboration of the original source of inputs through access to multiple quotes, if available, or other information and (4) monitoring changes in valuation methods and assumptions. The methods described above may produce a fair value calculation that may not be indicative of future fair values. Our valuation determination also gives consideration to nonperformance risk on our own liabilities as well as the credit standing of our counterparties. We primarily use financial institutions, who are also major lenders in our credit facility agreement, as counterparties to our derivative contracts. We have evaluated the credit risk of the counterparties holding our derivative assets using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the impact of the nonperformance of our counterparties on the fair value of our derivative instruments is insignificant; therefore, as of December 31, 2009, no adjustment for credit risk was recorded. Validation of our contracts’ fair value is performed internally and while we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. While we believe these valuation methods are appropriate and consistent with those used by other market participants, the use of different methodologies, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value. +F-17 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents, for each hierarchy level, our assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis as of December 31, 2009 and 2008. +Level 1 +Level 3 +Total +(in thousands) +As of December 31, 2009 +Assets: +Commodity based derivatives +$ +25,598 +$ +36,796 +$ +62,394 +Basis protection derivative contracts +- +57 +57 +Total assets +25,598 +36,853 +62,451 +Liabilities: +Commodity based derivatives +(3,140 +) +(9,932 +) +(13,072 +) +Basis protection derivative contracts +- +(55,915 +) +(55,915 +) +Total liabilities +(3,140 +) +(65,847 +) +(68,987 +) +Net asset (liability) +$ +22,458 +$ +(28,994 +) +$ +(6,536 +) +As of December 31, 2008 +Assets: +Commodity based derivatives +$ +19,359 +$ +144,644 +$ +164,003 +Basis protection derivative contracts +- +33 +33 +Total assets +19,359 +144,677 +164,036 +Liabilities: +Commodity based derivatives +(658 +) +(5,490 +) +(6,148 +) +Basis protection derivative contracts +- +(4,338 +) +(4,338 +) +Total liabilities +(658 +) +(9,828 +) +(10,486 +) +Net asset +$ +18,701 +$ +134,849 +$ +153,550 +The following table presents a reconciliation of our Level 3 fair value measurements. +December 31, +2009 +2008 +(in thousands) +Fair value, net asset (liability) beginning of year +$ +134,849 +$ +(2,368 +) +Changes in fair value included in statement of operations line item: +Commodity price risk management gain (loss), net +(23,243 +) +117,243 +Sales from natural gas marketing +(380 +) +257 +Cost of natural gas marketing +3,718 +(5,017 +) +Changes in fair value included in balance sheet line item: +Accounts receivable affiliates +(18,960 +) +821 +Accounts payable affiliates +(29,292 +) +35,338 +Settlements +Natural gas and oil sales +(95,678 +) +(11,479 +) +Natural gas marketing +(8 +) +54 +Fair value, net asset (liability) end of year +$ +(28,994 +) +$ +134,849 +Changes in unrealized gains (losses) relating to assets (liabilities) still held as of December 31, 2009, included in statement of operations line item: +Commodity price risk management gain (loss), net +$ +(38,634 +) +$ +- +Sales from natural gas marketing +29 +2 +Cost of natural gas marketing +(1,083 +) +(1,081 +) +$ +(39,688 +) +$ +(1,079 +) +F-18 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +See Note 4, Derivative Financial Instruments , for additional disclosure related to our derivative financial instruments. +Non-Derivative Financial Assets and Liabilities +The carrying values of the financial instruments comprising current assets and current liabilities approximate fair value due to the short-term maturities of these instruments. +The portion of our long-term debt related to our credit facility approximates fair value due to the variable nature of its related interest rate. We have not elected to account for the portion of our long-term debt related to our senior notes under the fair value option; however, we estimate the fair value of this portion of our long-term debt to be $210.1 million or 103.5% of par value as of December 31, 2009. We determined this valuation based upon measurements of trading activity. +See Note 2 – Summary of Significant Accounting Policies - Property and Equipment, Natural Gas and Oil Properties and - Asset Retirement Obligations for a discussion of how we determined fair value on these obligations. +NO TE 4 – DERIVATIVE FINANCIAL INSTRUMENTS +Our results of operations and operating cash flows are affected by changes in market prices for natural gas and oil. To mitigate a portion of our exposure to adverse market changes, we utilize the following economic hedging strategies for each of our business segments. +· +For natural gas and oil sales, we enter into derivative contracts to protect against price declines in future periods. While we structure these derivatives to reduce our exposure to changes in price associated with the derivative commodity, they also limit the benefit we might otherwise have received from price increases in the physical market. +· +For natural gas marketing, we enter into fixed-price physical purchase and sale agreements that qualify as derivative contracts. In order to offset the fixed-price physical derivatives in our natural gas marketing, we enter into financial derivative instruments that have the effect of locking in the prices we will receive or pay for the same volumes and period, offsetting the physical derivative. +We believe our derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. As of December 31, 2009, we had derivative instruments in place for a portion of our anticipated production through 2013 for a total of 56,379,362 MMbtu of natural gas and 1,929,485 Bbls of oil. +As of December 31, 2009, our derivative instruments were comprised of commodity collars and swaps, basis protection swaps and physical sales and purchases. +· +Collars contain a fixed floor price (put) and ceiling price (call). If the index price falls below the fixed put strike price, we receive the market price from the purchaser and receive the difference between the put strike price and index price from the counterparty. If the index price exceeds the fixed call strike price, we receive the market price from the purchaser and pay the difference between the call strike price and index price to the counterparty. If the index price is between the put and call strike price, no payments are due to or from the counterparty. +· +Swaps are arrangements that guarantee a fixed price. If the index price is below the fixed contract price, we receive the market price from the purchaser and receive the difference between the index price and the fixed contract price from the counterparty. If the index price is above the fixed contract price, we receive the market price from the purchaser and pay the difference between the index price and the fixed contract price to the counterparty. If the index price and contract price are the same, no payment is due to or from the counterparty. +· +Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point. For CIG-basis protection swaps, which have negative differentials to NYMEX, we receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract. If the market price and contract price are the same, no payment is due to or from the counterparty. +F-19 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +· +Physical sales and purchases are derivatives for fixed-priced physical transactions where we sell or purchase third party supply at fixed rates. These physical derivatives are offset by financial swaps: for a physical sale the offset is a swap purchase and for a physical purchase the offset is a swap sale. +The following table presents the location and fair value amounts of our derivative instruments on the balance sheets as of December 31, 2009 and 2008. +Fair Value +Derivatives instruments not designated as hedges (1) : +Balance sheet line item +December 31, +2009 +December 31, +2008 +(in thousands) +Derivative Assets: (2) +Current +Commodity contracts +Related to natural gas and oil sales +Fair value of derivatives +$ +39,107 +$ +112,036 +Related to natural gas marketing +Fair value of derivatives +3,077 +4,820 +Basis protection contracts +Related to natural gas marketing +Fair value of derivatives +39 +25 +42,223 +116,881 +Non Current +Commodity contracts +Related to natural gas and oil sales +Fair value of derivatives +19,680 +45,971 +Related to natural gas marketing +Fair value of derivatives +530 +1,176 +Basis protection contracts +Related to natural gas marketing +Fair value of derivatives +18 +8 +20,228 +47,155 +Total Derivative Assets +$ +62,451 +$ +164,036 +Derivative Liabilities: (3) +Current +Commodity contracts +Related to natural gas and oil sales +Fair value of derivatives +$ +(2,451 +) +$ +- +Related to natural gas marketing +Fair value of derivatives +(2,626 +) +(4,720 +) +Basis protection contracts +Related to natural gas and oil sales +Fair value of derivatives +(15,127 +) +- +Related to natural gas marketing +Fair value of derivatives +(4 +) +(46 +) +(20,208 +) +(4,766 +) +Non Current +Commodity contracts +Related to natural gas and oil sales +Fair value of derivatives +(7,572 +) +- +Related to natural gas marketing +Fair value of derivatives +(423 +) +(1,428 +) +Basis protection contracts +Related to natural gas and oil sales +Fair value of derivatives +(40,784 +) +(4,292 +) +(48,779 +) +(5,720 +) +Total Derivative Liabilities +$ +(68,987 +) +$ +(10,486 +) +(1) +As of December 31, 2009 and 2008, none of our derivative instruments were designated as hedges. +(2) +Includes derivative positions that have been designated to our affiliated partnerships; accordingly, our balance sheets include a corresponding payable to our affiliated partnerships of $13.4 million and $37.5 million as of December 31, 2009 and 2008, respectively. Further, December 31, 2009, includes derivative positions owned by our joint venture of $0.2 million. +(3) +Includes derivative positions that have been designated to our affiliated partnerships; accordingly, our balance sheets include a corresponding receivable from our affiliated partnerships of $21 million and $1.6 million as of December 31, 2009 and 2008, respectively. Further, December 31, 2009, includes derivative positions owned by our joint venture of $(1.6) million. +F-20 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the impact of our derivative instruments on our statements of operations. +2009 +2008 +2007 +Statement of operations line item +Reclassification +of Realized +Gains (Losses) +Included in Prior +Periods +Unrealized +Realized and +Unrealized +Gains +(Losses) For +the +Current +Period +Total +Reclassification +of Realized +Gains (Losses) +Included in Prior +Periods +Unrealized +Realized and +Unrealized +Gains +(Losses) For +the +Current +Period +Total +Reclassification +of Realized +Gains (Losses) +Included in Prior +Periods +Unrealized +Realized and +Unrealized +Gains +(Losses) For +the +Current +Period +Total +(in thousands) +2009: +Commodity price risk management gain (loss), net +Realized gains (losses) +$ +84,655 +$ +22,690 +$ +107,345 +$ +(549 +) +$ +10,036 +$ +9,487 +$ +4,843 +$ +2,330 +$ +7,173 +Unrealized gains (losses) +(84,655 +) +(32,743 +) +(117,398 +) +549 +117,802 +118,351 +(4,843 +) +426 +(4,417 +) +Total commodity price risk management gain (loss), net (1) +$ +- +$ +(10,053 +) +$ +(10,053 +) +$ +- +$ +127,838 +$ +127,838 +$ +- +$ +2,756 +$ +2,756 +Sales from natural gas marketing +Realized gains (losses) +$ +4,798 +$ +2,724 +$ +7,522 +$ +1,447 +$ +(3,329 +) +$ +(1,882 +) +$ +2,926 +$ +944 +$ +3,870 +Unrealized gains (losses) +(4,798 +) +1,295 +(3,503 +) +(1,447 +) +6,061 +4,614 +(2,926 +) +1,190 +(1,736 +) +Total sales from natural gas marketing (2) +$ +- +$ +4,019 +$ +4,019 +$ +- +$ +2,732 +$ +2,732 +$ +- +$ +2,134 +$ +2,134 +Cost of natural gas marketing +Realized gains (losses) +$ +(4,719 +) +$ +3,699 +$ +(1,020 +) +$ +(898 +) +$ +930 +$ +32 +$ +(2,282 +) +$ +1,800 +$ +(482 +) +Unrealized gains (losses) +4,719 +(441 +) +4,278 +898 +(6,327 +) +(5,429 +) +2,282 +(771 +) +1,511 +Total cost of natural gas marketing (2) +$ +- +$ +3,258 +$ +3,258 +$ +- +$ +(5,397 +) +$ +(5,397 +) +$ +- +$ +1,029 +$ +1,029 +(1) Represents realized and unrealized gains and losses on derivative instruments related to our natural gas and oil sales. +(2) Represents realized and unrealized gains and losses on derivative instruments related to our natural gas marketing. +NO TE 5 – CONCENTRATION OF RISK +Accounts Receivable. The following table presents the components of accounts receivable, net. +December 31, +2009 +2008 +(in thousands) +Natural gas and oil sales +$ +19,527 +$ +23,302 +Derivative counterparties +12,887 +15,083 +Joint interest billings +10,260 +14,352 +Natural gas marketing +9,297 +16,125 +Other +5,068 +1,363 +Allowance for doubtful accounts +(548 +) +(537 +) +Total accounts receivable, net +$ +56,491 +$ +69,688 +Our accounts receivable are primarily from purchasers of our natural gas and oil production, derivative counterparties and other third parties which own working interests in the properties that we operate. Inherent to our industry is the concentration of natural gas and oil sales to a few customers. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions. We record an allowance for doubtful accounts for receivables that we estimate to be uncollectible. In making our estimate, we consider, among other things, our historical write-offs and overall creditworthiness of our customers. Further, consideration is given to well production data for receivables related to well operations. It is reasonably possible that our estimate of uncollectible amounts will change periodically. As of December 31, 2009, we had no customers representing 10% or more of our existing accounts receivable balance. +F-21 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Major Customers . The following table presents the individual customers constituting 10% or more of total revenues. +Total Revenues +Year Ended December 31, +Customer +2009 +2008 +2007 +Suncor Energy Marketing, Inc. +18.6 +% +0.2 +% +0.0 +% +Williams Production RMT Company +16.1 +% +12.4 +% +12.9 +% +DCP Midstream, LP +11.9 +% +6.6 +% +7.1 +% +Tepco Crude Oil, LLC +2.1 +% +10.8 +% +13.5 +% +Derivative Counterparties . A significant portion of our liquidity is concentrated in derivative instruments that enable us to manage a portion of our exposure to price volatility from producing natural gas and oil. These arrangements expose us to credit risk of nonperformance by our counterparties. We primarily use financial institutions, who are also major lenders in our credit facility agreement, as counterparties to our derivative contracts. To date, we have had no counterparty default losses. We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the impact of the nonperformance of our counterparties on the fair value of our derivative instruments is insignificant. As of December 31, 2009 and 2008, no valuation allowance was recorded. +The following table presents the counterparties that expose us to credit risk as of December 31, 2009, with regard to our derivative assets. +Counterparty Name +Fair Value +of +Derivatives +(in thousands) +JPMorgan Chase Bank, N.A. (1) +$ +28,462 +BNP Paribas (1) +23,360 +Various (2) +10,629 +Total +$ +62,451 +________________________ +(1) Major lender in our credit facility, see Note 8, Long-Term Debt. +(2) Represents a total of 51 counterparties, includes 5 lenders in our credit facility. +F-22 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NO TE 6 – PROPERTIES AND EQUIPMENT +December 31, +2009 +2008 +(in thousands) +Properties and equipment, net: +Natural gas and oil properties (successful efforts method of accounting) +Proved +$ +1,329,666 +$ +1,169,969 +Unproved +38,626 +32,768 +Total natural gas and oil properties +1,368,292 +1,202,737 +Pipelines and related facilities +38,202 +33,165 +Transportation and other equipment +33,624 +31,565 +Land and buildings +14,699 +14,359 +Construction in progress +9,131 +76,863 +1,463,948 +1,358,689 +Accumulated DD&A +(455,755 +) +(325,611 +) +$ +1,008,193 +$ +1,033,078 +Suspended Well Costs +The following table presents the capitalized exploratory well costs pending determination of proved reserves and included in properties and equipment on the balance sheets. +2009 +2008 +2007 +(in thousands, except for number of wells) +Beginning balance at January 1 +$ +1,180 +$ +2,300 +$ +765 +Additions to capitalized exploratory well costs pending the determination of proved reserves +10,226 +15,644 +3,953 +Reclassifications to wells, facilities and equipment based on the determination of proved reserves +(9,914 +) +(10,259 +) +(878 +) +Capitalized exploratory well costs charged to expense +(318 +) +(6,505 +) +(1,540 +) +Ending balance at December 31 +$ +1,174 +$ +1,180 +$ +2,300 +Number of wells pending determination at December 31 +2 +6 +3 +As of December 31, 2009, neither of the two suspended wells awaiting the determination of proved reserves have been capitalized for a period greater than one year after the completion of drilling. +F-23 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NO TE 7 - INCOME TAXES +The table below presents the components of our tax expense from continuing operations for the years presented. +2009 +2008 +2007 +(in thousands) +Current: +Federal +$ +(27,985 +) +$ +3,907 +$ +3,533 +State +353 +(3,897 +) +771 +Total current income taxes +(27,632 +) +10 +4,304 +Deferred: +Federal +(13,252 +) +55,500 +11,074 +State +(4,832 +) +3,579 +1,127 +Total deferred income taxes +(18,084 +) +59,079 +12,201 +Total income tax provision (benefit) +$ +(45,716 +) +$ +59,089 +$ +16,505 +For the years ended December 31, 2009, 2008 and 2007, we utilized income tax elections to currently expense approximately $80 million, $30 million and $44 million, respectively, of intangible drilling costs ("IDC"). This election substantially reduced our current tax expense, resulting in a correspondingly higher deferred tax expense. The 2009 IDC deduction resulted in a taxable net operating loss ("NOL"). The Worker, Homeownership, and Business Assistance Act of 2009 increased the statutory NOL carry-back period for losses incurred in 2008 and 2009 tax years for up to five years. This enabled us to utilize our current year NOL to generate an estimated $26 million refund of federal tax from our 2005 and 2006 tax years. +The following table presents a reconciliation of the statutory rate to our effective tax rate. +2009 +2008 +2007 +Statutory tax rate +35.0 +% +35.0 +% +35.0 +% +State income tax, net +3.3 +% +3.1 +% +3.5 +% +Percentage depletion +0.5 +% +-0.7 +% +-1.5 +% +Domestic production activities deduction +- +-0.1 +% +-0.8 +% +Other, including discrete items (1) +-2.8 +% +-2.2 +% +2.6 +% +36.0 +% +35.1 +% +38.8 +% +(1) +2009 consists primarily of non-deductible expenditures related to the joint venture; 2008 consists primarily of a discrete tax benefit realized upon the implementation of state tax strategies during the first half of 2008; and 2007 consists primarily of non-deductible penalties. +The Domestic Production Activities Deduction under Section 199 of the Internal Revenue Code, which provides for a phased-in deduction related to qualifying production activities, was provided for the first time under the American Jobs Creation Act of 2004. We recorded an income tax benefit for certain qualifying production activities of approximately $0.2 million in 2008 and $0.4 million in 2007. Due to our taxable loss position in 2009 and the resulting NOL carry-back, no Section 199 benefit was recorded in 2009 and our 2005 benefit of $0.4 million was reversed. The reversal of the prior year’s Section 199 deduction was a detriment to the 2009 effective tax rate and was recorded as a discrete item and is included in "Other" in the above table. +F-24 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2009 and 2008, are presented below. +2009 +2008 +(in thousands) +Deferred tax assets: +Allowance for lease impairment +$ +5,751 +$ +4,910 +Provision for underpayment of natural gas sales +1,130 +- +Deferred revenue related to cash withheld for future plugging cost +715 +1,043 +Deferred compensation +3,277 +2,846 +Asset retirement obligations +5,189 +8,519 +Employee benefits +537 +547 +State NOL, tax credits and deduction carryforward, net +4,664 +309 +Percentage depletion - carryforward +811 +- +Other +405 +289 +Total gross deferred tax assets +22,479 +18,463 +Less valuation allowance +(747 +) +- +Deferred tax assets +21,732 +18,463 +Deferred tax liabilities: +Properties and equipment +(170,161 +) +(165,212 +) +Investment in PDC Mountaineer, LLC +(23,935 +) +- +Unrealized gains - derivatives +(230 +) +(44,199 +) +Future state liabilities +(270 +) +- +Total gross deferred tax liabilities +(194,596 +) +(209,411 +) +Net deferred tax liability +$ +(172,864 +) +$ +(190,948 +) +Classification in the Consolidated Balance Sheets: +Prepaid expenses and other current assets +$ +5,148 +$ +(28,355 +) +Deferred income taxes +(178,012 +) +(162,593 +) +Net deferred tax liability +$ +(172,864 +) +$ +(190,948 +) +Deferred tax liabilities for properties and equipment increased in 2009 and 2008, primarily as a result of our election to expense $80 million and $30 million, respectively, of IDC for income tax purposes. The 2009 increase was partially offset by the contribution of natural gas and oil properties to our joint venture. In total, deferred tax liabilities decreased in 2009 due to the substantial reduction in unrealized gains on derivatives. +Included in deferred tax assets at December 31, 2009, were unutilized net tax benefits totaling $4.7 million related to state NOL, state tax credit and state deduction carry-forwards. Approximately half of this deferred tax asset will expire through December 2021, and the remaining amount will expire through 2029. +In assessing whether a valuation allowance for the deferred tax assets should be recorded, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible or tax credits become utilizable. Based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible or utilizable, we have recorded a $0.7 million valuation allowance related to certain state tax benefit carry-forwards. The amount of the remaining deferred tax asset considered realizable, however, could be reduced in the near term if estimates of future taxable income during the carry-forward period are reduced. +F-25 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +In 2007, upon the adoption of accounting guidance related to uncertain tax positions, we reduced retained earnings by $0.3 million, deferred income taxes payable by $0.9 million, increased current income taxes payable by $0.2 million and the liability for unrecognized tax benefit by $1 million. +The following table presents a reconciliation of the total amounts of unrecognized tax benefits. +December 31, +2009 +2008 +2007 +(in thousands) +Balance beginning of year +$ +1,271 +$ +888 +$ +952 +Additions for tax positions of prior years +43 +216 +819 +Additions for tax positions of current year +7 +167 +- +Reductions for tax positions of prior years +- +- +(883 +) +Reductions due to settlements +(406 +) +- +- +Reductions due to lapse of statute of limitations +(349 +) +- +- +Balance end of year +$ +566 +$ +1,271 +$ +888 +Interest and penalties related to uncertain tax positions are recognized in income tax expense. Accrued interest and penalties related to uncertain tax positions were immaterial for each of the years in the three-year period ended December 31, 2009. The total amount of unrecognized tax benefits that would affect the effective tax rate, if recognized, is $0.6 million as of December 31, 2009 and $0.9 million as of December 31, 2008. As of December 31, 2009, it is reasonably possible that the total amount of unrecognized tax benefit could decrease up to $0.6 million in the next twelve months due to the conclusion of the current IRS examination and the lapse of an applicable statute of limitation. +For federal tax purposes, the statute of limitations is open for tax years 2005 and forward. The statute of limitation for most of our state tax jurisdictions is open from 2004 forward. +NO TE 8 - LONG-TERM DEBT +Long-term debt consists of the following: +December 31, +2009 +2008 +(in thousands) +Credit facility +$ +80,000 +$ +194,500 +12% Senior notes due 2018, net of discount of $2.3 million +200,657 +200,367 +Total long-term debt +$ +280,657 +$ +394,867 +F-26 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Credit facility +We have a credit facility co-arranged by JPMorgan Chase Bank, N.A. ("JPMorgan") and BNP Paribas, dated as of November 4, 2005, as amended last on December 18, 2009 ("the Eighth Amendment"), with an aggregate revolving commitment of $305 million. The credit facility, through the series of amendments, includes commitments from: Bank of America, N.A.; Calyon New York Branch; Bank of Montreal; The Royal Bank of Scotland plc; The Bank of Nova Scotia; Wachovia Bank, N.A.; Guaranty Bank, FSB; Texas Capital Bank; Bank of Oklahoma; U.S. Bank National Association; and Compass Bank. The maximum allowable commitment under the current credit facility is $500 million. The credit facility is subject to and collateralized by our natural gas and oil reserves, exclusive of the joint ventures natural gas and oil reserves. The credit facility requires an aggregated security of a value no less than 80% of the value of the direct interests included in the borrowing base properties. Our credit facility borrowing base is subject to size redeterminations each May and November based upon a quantification of our reserves at December 31st and June 30th, respectively; additionally, we or our lenders may request a redetermination upon the occurrence of certain events. A commodity price deck reflective of the current and future commodity pricing environment, as determined by our lenders, is utilized to quantify our reserves used in the borrowing base calculation and thus determines the underlying borrowing base. As of December 31, 2009, our aggregate revolving commitment was secured by substantially all of our natural gas and oil properties. +We are required to pay a commitment fee of 0.5% per annum on the unused portion of the activated credit facility. Interest accrues at an alternative base rate ("ABR") or adjusted LIBOR at our discretion. The ABR is the greater of JP Morgan's prime rate, a secondary market rate of a three-month certificate of deposit plus 1%, one month LIBOR plus 1% or the federal funds effective rate plus 0.5%. ABR and adjusted LIBOR borrowings are assessed an additional margin spread based upon the outstanding balance as a percentage of the available balance. ABR borrowings are assessed an additional margin of 1.375% to 2.375%. Adjusted LIBOR borrowings are assessed an additional margin spread of 2.25% to 3.25%. Any debt issuance costs are capitalized and amortized using the effective interest rate method over the remaining term of the credit facility. As a result of our 2009 redeterminations, we expensed $2 million of debt issuance cost as a result of reductions in our borrowing base and changes in lenders. As of December 31, 2009, we had $6.2 million in debt issuance costs being amortized at a rate of $0.7 million per quarter. No principal payments are required until the credit agreement expires on May 22, 2012, or in the event that the borrowing base would fall below the outstanding balance. +The credit facility contains covenants customary for agreements of this type, including, but not limited to, limitations on our ability to: (a) incur additional indebtedness and guarantees, (b) create liens and other encumbrances on our assets, (c) consolidate, merge or sell assets, (d) pay dividends and other distributions, (e) make certain investments, loans and advances, (f) enter into sale/leaseback transactions, and (g) engage in hedging activities unless certain requirements are satisfied. The credit facility also requires us to execute and deliver specified mortgages and other evidences of security and to deliver specified opinions of counsel and other evidences of title. Further, we are required to comply with certain financial tests and maintain certain financial ratios on a quarterly basis. The financial tests and ratios include requirements to: (a) maintain a minimum current ratio, as defined per credit facility, of 1.00 to 1.00 and (b) not to exceed a maximum leverage ratio of 4.25 to 1.00 through December 31, 2010, 4.00 to 1.00 through June 30, 2011, and 3.75 to 1.00 thereafter. +In August 2009, we issued a $18.7 million irrevocable standby letter of credit in favor of a third party transportation service provider to secure the construction of certain additions and/or replacements to its facilities to provide firm transportation of the natural gas produced by us and others for whom we market their production in the West Virginia and Southwestern Pennsylvania areas. The letter of credit reduces the amount of available funds under our credit facility by an equal amount. We pay a fronting fee of 0.25% per annum and an additional quarterly maintenance fee equivalent to the spread over Eurodollar loans (2.5% as of December 31, 2009) for the period the letter of credit remains outstanding. The letter of credit expires on May 22, 2012. +In October 2009, our credit facility was amended to, among other things, permit the contribution of certain natural gas and oil properties in the Appalachian Basin, to the joint venture, facilitate other aspects of the joint venture and permit us to make additional investments in the joint venture so long as certain conditions are satisfied. Until our investor partner earns a 50% interest in the joint venture, such additional investments are limited to $40 million. Concurrently with our contribution of certain natural gas and oil properties to the joint venture, our borrowing base under the credit facility was reduced from $350 million to $305 million upon the execution of the joint venture agreement and the contribution of our natural gas and oil properties in the Appalachian Basin to the joint venture. Our November 2009 redetermination, which reaffirmed our borrowing base at $305 million, was completed in December 2009. See Note 13, Noncontrolling Interest in Subsidiaries . +F-27 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +As of December 31, 2009, we had drawn $80 million from our credit facility compared to $194.5 million as of December 31, 2008. The borrowing rate on the outstanding balance was 4.7% as of December 31, 2009, compared to 4.6% as of December 31, 2008. As of December 31, 2009, the available funds under our credit facility were $206.3 million. We were in compliance with all covenants at December 31, 2009, and expect to remain in compliance throughout the next year. +12% Senior Notes Due 2018 +In February 2008, we issued 12% senior notes with a total principal amount of $203 million payable at maturity on February 15, 2018. Interest is payable in cash semi-annually in arrears on each February 15 and August 15. The senior notes were issued at a discount, 98.572% of the principal amount. We incurred $5.4 million in costs associated with the issuance of the debt which was capitalized as a deferred loan cost. The original discount and the deferred note costs are being amortized to interest expense over the term of the debt using the effective interest method. +The indenture governing the notes contains customary representations and warranties as well as typical restrictive covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: (a) incur additional debt, (b) make certain investments or pay dividends or distributions on our capital stock or purchase or redeem or retire capital stock, (c) sell assets, including capital stock of our restricted subsidiaries, (d) pay dividends or other payments by restricted subsidiaries, (e) create liens that secure debt, (f) enter into transactions with affiliates, and (g) merge or consolidate with another company. Additionally, we are subject to two incurrence covenants: 1) earnings before interest, taxes, DD&A expense and capital expenditures ("EBITDAX") of at least two times interest expense and 2) total debt of less than 4.0 times EBITDAX. We were in compliance with all covenants as of December 31, 2009, and expect to remain in compliance throughout the next year. +The notes are senior unsecured obligations and rank, in right of payment, equally with all of our existing and future senior unsecured indebtedness and senior to any of our existing and future subordinated indebtedness. The notes are effectively subordinated to any of our existing or future secured indebtedness to the extent of the assets securing such indebtedness. +The notes are not initially guaranteed by any of our subsidiaries. However, subsidiaries may be obligated to guarantee the notes if: +• +a subsidiary is a guarantor under our senior credit facility; and +• +the subsidiary has consolidated tangible assets that constitute 10% or more of our consolidated tangible assets. +Subject to specified exceptions, any subsidiary guarantor will be restricted from entering into certain transactions including the disposition of all or substantially all of its assets or merging with or into another entity. Subsidiary guarantors may be released from a guarantee under circumstances specified in the indenture. As of December 31, 2009, none of our subsidiaries were obligated as guarantors of our senior notes. +The indenture provides that at any time, which may be more than once, before February 15, 2011, we may redeem up to 35% of the outstanding notes with proceeds from one or more equity offerings at a redemption price of 112% of the principal amount of the notes redeemed, plus accrued and unpaid interest, as long as: +• +at least 65% of the aggregate principal amount of the notes issued on February 8, 2008, remains outstanding after each such redemption; and +• +the redemption occurs within 180 days after the closing of the equity offering. +The notes also provide that we may, at our option, redeem all or part of the notes at any time prior to February 15, 2013, at the make-whole price set forth in the indenture, and on or after February 15, 2013, at fixed redemption prices, plus accrued and unpaid interest, if any, to the date of redemption. Further, the indenture provides that upon a change of control, we must give holders of the notes the opportunity to put their notes to us for repurchase at a repurchase price of 101% of the principal amount, plus accrued and unpaid interest. +F-28 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NO TE 9 - ASSET RETIREMENT OBLIGATIONS +The following table presents the changes in carrying amounts of the asset retirement obligations associated with our working interest in natural gas and oil properties. +2009 +2008 +(in thousands) +Balance at beginning of year +$ +23,086 +$ +20,781 +Obligations assumed with development activities and acquisitions +883 +1,189 +Obligations discharged with disposal of properties and asset retirements +(52 +) +(114 +) +Accretion expense +1,368 +1,230 +Revisions in estimated cash flows +4,279 +- +Balance at end of year +29,564 +23,086 +Less current portion +(250 +) +(50 +) +Long-term portion +$ +29,314 +$ +23,036 +If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. +NO TE 10 - EMPLOYEE BENEFIT PLANS +We sponsor a qualified retirement plan covering substantially all of our employees. The plan consists of a 401(k) component and a profit sharing component. The 401(k) component enables eligible employees to contribute a portion of their compensation through pre-tax payroll deductions in accordance with specific guidelines. We provide a discretionary matching contribution based on a percentage of the employees' contributions up to certain limits. Our contribution to the profit sharing component is discretionary. Our total combined expense for both 401(k) and profit sharing in 2009, 2008 and 2007, was $1.7 million, $1.9 million and $1.4 million, respectively. +We provide a supplemental retirement benefit of deferred compensation under terms of the various employment agreements with certain executive officers. During 2009, 2008 and 2007, we charged $0.3 million, $0.2 million and $0.4 million, respectively, related to this plan to general and administrative expenses. As of December 31, 2009 and 2008, the liability related to this benefit was $2.4 million, which was included in other liabilities on the balance sheets, with the exception of $0.3 million included in other accrued expenses as of December 31, 2009. +We offer a supplemental healthcare benefit covering certain former executive officers and their spouses in accordance with each officer's employment agreement. Expenses incurred during 2009, 2008 and 2007 related to this plan were immaterial. As of December 31, 2009 and 2008, included in other liabilities on the balance sheets was a related liability of $0.5 million and $0.6 million, respectively. +We maintain a non-qualified deferred compensation plan for our non-employee directors. The amount of compensation deferred by each participant is based on participant elections. The amounts deferred pursuant to the plan are invested in our common stock, maintained in a rabbi trust and are classified in the balance sheets as treasury shares as a component of shareholders' equity. The plan may be settled in either cash or shares as requested by the participant. As of December 31, 2009 and 2008, the liability related to this plan was $0.2 million, which was included in other liabilities on the balance sheets. +NO TE 11 - COMMITMENTS AND CONTINGENCIES +Drilling and Development Agreements +In connection with the acquisition of natural gas and oil properties in October 2007 from an unaffiliated party, we are obligated to drill 100 wells on the acquired acreage in Pennsylvania by January 2016. We will retain a majority interest in each well drilled. For each well we fail to drill, we are obligated to pay to the seller liquidated damages of $25,000 per undrilled well for a total contingent obligation of $2.5 million or reassign to the seller the interest acquired in the number of undrilled well locations. As of December 31, 2009, we have drilled 28 wells pursuant to this agreement. +F-29 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +In September 2008, we entered into a pipeline and processing plants expansion agreement with an unrelated party, who is currently the purchaser of the majority of our Wattenberg Field natural gas production. Pursuant to the agreement, we agreed to make a capital investment of $60 million, for our own benefit, over a three-year period commencing on January 1, 2009, to develop or facilitate production in our Wattenberg Field dedicated to this purchaser and, if the purchaser failed to diligently proceed with the pipeline and processing plants, we would be relieved of our obligations under the agreement. In March 2009, we received from the unrelated party a notice waiving our commitment and stating that the pipeline and processing plant expansions were either on hold or had been delayed. The waiver relieves us of the $60 million capital investment obligation. +Firm Transportation Agreements +We have entered into contracts that provide firm transportation, sales and processing charges on pipeline systems through which we transport or sell our natural gas and the natural gas of other companies, working interest owners and our affiliated partnerships. These contracts require us to pay these transportation and processing charges whether the required volumes are delivered or not. Satisfaction of the volumes requirements include volumes produced by us, volumes purchased from third parties, volumes produced by our joint venture and affiliated partnerships. As of December 31, 2009, based on a review of our drilling plans and volume projections, we do not expect to meet all future volume requirements for a firm transportation agreement in our Piceance Basin. Accordingly, during the fourth quarter of 2009, we recorded a charge to natural gas and oil production and well operation costs of $2.7 million and a corresponding liability, which is included in other liabilities on the balance sheet. We are currently working with the third party to renegotiate the terms and timing of our volume requirements under this agreement. If we are not able to renegotiate this agreement or meet all future volume requirements, the result may be additional significant charges to natural gas and oil production and well operations costs. +The following table presents gross volume information related to our long-term firm sales, processing and transportation agreements for pipeline capacity. These agreements require a demand charge whether volumes are delivered or not. We record in our financial statements only our share of costs based upon our working and net revenue interest in the wells. If the volumes below are not met, we will bear all costs related to the volume shortfall. +Year Ending +Area +2010 +2011 +2012 +2013 +2014 +Through +Expiration +Expiration +Date +Volume (MMBtu) +Appalachian Basin (1) +803,900 +591,300 +4,106,120 +10,993,800 +94,965,560 +August 2022 +Grand Valley +31,780,021 +32,288,245 +32,785,874 +30,458,110 +96,725,834 +May 2021 +NECO +1,825,000 +- +- +- +- +December 2010 +NECO +1,825,000 +1,825,000 +1,825,000 +1,825,000 +5,475,000 +December 2016 +Dollar commitment (in thousands) +$ +18,483 +$ +17,979 +$ +20,046 +$ +22,397 +$ +100,979 +(1) +Includes a precedent agreement that becomes effective when the planned pipeline is placed in service, currently estimated to be 2012. This agreement will be null and void if the pipeline is not completed. In August 2009, we issued a letter of credit related to this agreement, see Note 8, Long-Term Debt. +F-30 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Litigation +We are involved in various legal proceedings that we consider normal to our business. Although the results cannot be known with certainty, we believe that we have properly accrued reserves. +Royalty Owner Class Actions +Glen Droegemueller v. Petroleum Development Corporation, Case No. 1:07-C-436 in the U.S. District Court, Weld County, Colorado, filed May 29, 2007 +Glen Droegemueller, individually and as representative plaintiff on behalf of all others similarly situated, filed a class action complaint against the Company alleging that we underpaid royalties on natural gas produced from wells operated by us in parts of the State of Colorado. The plaintiff sought declaratory relief and to recover an unspecified amount of compensation for underpayment of royalties paid by us pursuant to leases. We removed the case to Federal Court on June 28, 2007. On October 10, 2008, the court preliminarily approved a settlement agreement between the plaintiffs and the Company, on behalf of itself and the partnerships for which the Company is the managing general partner. Based on the settlement terms, the settlement amount payable by the Company is $5.8 million. Such moneys, in addition to moneys related to the settlement on behalf of the partnerships, were deposited in an escrow account on November 3, 2008. The final settlement was approved by the court on April 7, 2009. Settlement distribution checks were mailed in July 2009. +Beymer v. Petroleum Development Corporation and Riley Natural Gas Company, Case No. 2:09-C-3 in U. S. District Court, Northern District of West Virginia, filed on January 21, 2009, and +Gobel et al v. Petroleum Development Corporation, Case No. 09-C-40 in U. S. District Court, Northern District of West Virginia, filed on January 27, 2009 +Joe L. Beymer and Georgia F. Beymer, individually and as representative of the class of all similarly situated individuals and entities, filed a lawsuit against the Company alleging that we failed to properly pay royalties (the "Beymer lawsuit"). The allegations state that the Company improperly deducted certain charges and costs before applying the royalty percentage. Punitive damages are requested in addition to breach of contract, tort, and fraud allegations. A second suit was filed in West Virginia state court in Harrison County by David W. Gobel alleging a class action with allegations similar to those alleged in the Beymer lawsuit. Both cases have been removed to federal court in the Northern District of West Virginia. The Beymer suit was subsequently voluntarily dismissed by plaintiff's counsel. Initial mediation was commenced in January 2010. Although such removal has been contested, the case is currently stayed as the parties exchange information and investigate settlement. +Other +In July 2008, the Company self-reported to the Colorado Department of Public Health and Environment (the "CDPHE") certain non-compliance with air laws at its Logan Master Meter Station. The CDPHE subsequently initiated a review and inspection of air compliance at its Logan Master Meter Station. On November 18, 2009, and December 19, 2009, the Company received related compliance advisories for alleged non-compliance. On February 19, 2010, the Company received a letter from the CDPHE with a proposed settlement for this matter of $0.2 million. The Company has entered negotiations with the CDPHE regarding this assessment. +On December 8, 2008, we received a Notice of Violation/Cease and Desist Order (the "Notice") from the Colorado Department of Public Health and Environment, related to the stormwater permit for the Garden Gulch Road. The Company manages this private road for Garden Gulch LLC. The Company is one of eight users of this road, all of which are natural gas and oil companies operating in the Piceance region of Colorado. Operating expenses, including this fine, if any, are allocated among the eight users of the road based upon their respective usage. The Notice alleges a deficient and/or incomplete stormwater management plan, failure to implement best management practices and failure to conduct required permit inspections. The Notice requires corrective action and states that the recipient shall cease and desist such alleged violations. The Notice states that a violation could result in civil penalties up to $10,000 per day. The Company’s responses were submitted on February 6, 2009, and April 8, 2009. Given the inherent uncertainty in administrative actions of this nature, the Company is unable to predict the ultimate outcome of this administrative action at this time. +We are involved in various other legal proceedings that we consider normal to our business. Although the results cannot be known with certainty, we believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position, results of operations or liquidity. +F-31 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Partnership Repurchase Provision +Substantially all of our drilling programs contain a repurchase provision where investing partners may request that we purchase their partnership units at any time beginning with the third anniversary of the first cash distribution. The provision provides that we are obligated to purchase an aggregate of 10% of the initial subscriptions per calendar year (at a minimum price of four times the most recent 12 months' cash distributions from production), if repurchase is requested by investors, subject to our financial ability to do so. As of December 31, 2009, the maximum annual repurchase obligation, based upon the minimum price described above, was approximately $9.4 million. We believe we have adequate liquidity to meet this obligation. During 2009, 2008 and 2007, we paid $1.7 million, $1.8 million and $1.6 million, respectively, under this provision for the repurchase of partnership units. +Performance Supplements +Our drilling programs formed from 1999 through the second quarter of 2005 contain a performance supplement that provides for changes in the distribution of partnership profits if certain levels of performance are not met. The terms of this provision in the partnership agreements are not a guarantee of a rate of return on an investment in the partnership. Under those specific conditions, such changes can result in our share of an affected partnership’s profits being reduced by up to one half of the amount to which we otherwise would be entitled in the affected period. In no event would we be obligated to assume a disproportionate share of losses in such partnerships; should the partnerships that contain this provision in the partnership agreements incur a loss, our share of such losses would be unaffected by the terms of this provision. In accordance with these provisions, our share of partnership profits was reduced by an aggregate of $0.8 million, $1 million and $0.6 million during 2009, 2008 and 2007, respectively. As of December 31, 2009 and 2008, based on production through December 31 of the corresponding year, amounts accrued were immaterial. +Lease Agreements +We entered into operating leases principally for the leasing of natural gas compressors, office space in Denver and Bridgeport, and general office equipment. The following table presents the minimum future lease payments under the non-cancelable operating leases as of December 31, 2009. +Year +(in thousands) +2010 +$ +2,001 +2011 +1,431 +2012 +991 +2013 +886 +2014 +863 +Thereafter +645 +$ +6,817 +Operating lease expense for the years ended December 31, 2009, 2008 and 2007, was $2.3 million, $2.5 million and $1.5 million, respectively. +Employment Agreements with Executive Officers +We have employment agreements with our Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer and other executive officers. The employment agreements provide for annual base salaries, eligibility for performance bonus compensation and other various benefits, including retirement and termination benefits. +F-32 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +In the event of termination following a change of control of the Company, or where the Company terminates the executive officer without cause or where an executive officer terminates employment for good reason, the severance benefits range from two times to three times the sum of his highest annual base salary during the previous two years of employment immediately preceding the termination date and his highest annual bonus received during the same two year period. For this purpose a "change of control" corresponds to the definition of "change of control" under Section 409A of the Internal Revenue Code of 1986 (IRC) and the supporting treasury regulations. The executive officer is also entitled to (i) vesting of any unvested equity compensation (excluding all long-term incentive performance shares), (ii) reimbursement for any unpaid expenses, (iii) retirement benefits earned under the current and/or previous agreements, (iv) continued coverage under our medical plan for up to 18 months, and (v) payment of any earned and unpaid bonus amounts. In addition, the executive officer is entitled to receive any benefits that he would have otherwise been entitled to receive under our 401(k) and profit sharing plan, although those benefits are not increased or accelerated. +In the event that an executive officer is terminated for just cause, we are required to pay the executive officer his base salary through the termination date plus any bonus (only for periods completed and accrued, but not paid), incentive, deferred, retirement or other compensation, and to provide any other benefits, which have been earned or become payable as of the termination date but which have not yet been paid or provided. +In the event that an executive officer voluntarily terminates his employment for other than good reason, he is entitled to receive (i) his base salary, bonus and incremental retirement payment prorated for the portion of the year that the executive officer is employed by the Company, provided, however, that with respect to the bonus, for certain executive officers, there shall be no proration of the bonus if such executive leaves prior to the last day of the year and, with respect to the remaining executive officers, there shall be no proration of the bonus in the event such executive officer leaves prior to March 31 in the year of his termination, (ii) any incentive, deferred or other compensation which has been earned or has become payable, but which has not yet been paid under the schedule originally contemplated in the agreement under which they were granted, (iii) any unpaid expense reimbursement upon presentation by the executive officer of an accounting of such expenses in accordance with our normal practices, and (iv) any other payments for benefits earned under the employment agreement or our plans. +In the event of death or disability, the executive is entitled to receive certain benefits. For this purpose, the definition of "disability" corresponds to the definition under IRC 409A and the supporting treasury regulations. The benefits shall be payable in a lump sum and shall be equal to the compensation and other benefits that would otherwise have been paid for a six-month period following the termination date plus a pro-rated portion of the performance bonus. +Derivative Contracts +We would be exposed to natural gas and oil price fluctuations on underlying purchase and sale contracts should the counterparties to our derivative instruments or the counterparties to our gas marketing contracts not perform. Nonperformance is not anticipated. We have had no counterparty default losses. +Partnership Casualty Losses +As Managing General Partner of 33 partnerships, we have liability for potential casualty losses in excess of the partnership assets and insurance. We believe the casualty insurance coverage that we and our subcontractors carry is adequate to meet this potential liability. +NO TE 12 - COMMON STOCK +Sale of Equity Securities +In August 2009, we sold 4,312,500 shares of our common stock in an underwritten public offering at a price of $12.00 per share. We used the net proceeds of $48.5 million to pay down our credit facility and for general corporate purposes. The offering was made pursuant to an effective shelf registration statement on Form S-3 filed with the SEC on November 26, 2008, and declared effective on January 30, 2009. +F-33 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Stock-Based Compensation Plans +As approved by the shareholders in June 2004, we maintain a long-term equity compensation plan for our officers and certain key employees (the "2004 Plan"). In accordance with the plan, awards may be issued in the form of stock options, stock appreciation rights, restricted stock or performance shares. Awards pursuant to the plan vest over periods set at the discretion of the Compensation Committee of our Board of Directors ("Board") and, with regard to options, have a maximum exercisable period of ten years. We also maintain a restricted stock plan for our non-employee directors ("Non-Employee Director Plan"), approved by the shareholders in June 2005. +The following table presents summary data related to our outstanding stock-based compensation plans. +2004 Plan +Non-Employee Director Plan +Statement of Operations Impact +Statement of Operations Impact +Stock-Based +Income Tax +Net +Stock-Based +Income Tax +Net +Shares +Compensation +Benefit +Impact +Shares +Compensation +Benefit +Impact +(in thousands) +(in thousands) +Shares reserved for award +750,000 +100,000 +Awards granted, net of forfeitures +2009 (1) +158,422 +$ +5,194 +$ +(1,993 +) +$ +3,201 +32,700 +$ +741 +$ +(284 +) +$ +457 +2008 (2) +149,049 +5,725 +(2,184 +) +3,541 +14,000 +977 +(373 +) +604 +2007 +96,718 +2,003 +(773 +) +1,230 +12,710 +283 +(109 +) +174 +2006 and prior +184,298 +13,446 +Total awards granted +588,487 +72,856 +Remaining shares available for award +161,513 +27,144 +(1) +Includes a total of $1.7 million related to agreements with our former executive vice president and chief executive officer. +(2) +Includes a total of $2.6 million related to agreements with our former president and chief executive officer. +Stock Option Awards +We have granted stock options pursuant to various stock compensation plans. Outstanding options expire ten years from the date of grant and become exercisable ratably over a four year period. We have not issued any new stock options awards since 2006. For the year ended December 31, 2009, pursuant to an agreement with a former executive vice president, we accelerated the vesting schedule for 1,094 options, all of which vested pursuant to the original terms of the awards. For the year ended December 31, 2008, pursuant to agreements with our former president and our former chief executive officer, we modified options to purchase 9,905 shares by accelerating the vesting schedule, none of which would have vested pursuant to the original terms of the award. The incremental change in fair value per share of the modified awards was immaterial. +The following table presents the changes in our stock option awards for the year ended December 31, 2009. +Number of +Shares +Underlying +Options +Weighted +Average +Exercise +Price +Per Share +Weighted +Average +Remaining +Contractual +Term +(years) +Outstanding at December 31, 2008 +18,351 +$ +41.68 +6.8 +Forfeited +(8,045 +) +41.39 +Outstanding at December 31, 2009 +10,306 +41.90 +6.0 +Vested and expected to vest at December 31, 2009 +10,306 +41.90 +6.0 +Exercisable at December 31, 2009 +8,591 +41.42 +5.9 +F-34 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +As of/For the Year Ended December 31, +2009 +2008 +2007 +(in thousands, except market price) +Total intrinsic value of options exercised +$ +- +$ +659 +$ +1,691 +Total intrinsic value of options outstanding +- +- +1,319 +Total intrinsic value of options exercisable +- +- +971 +Market price per common share as of December 31 +18.21 +24.07 +59.13 +The options outstanding and exercisable at December 31, 2009 and 2008, had no intrinsic value as the exercise price of the options exceeded the closing market price of our common stock at the respective dates. Total compensation cost related to stock options granted and not yet recognized in our statement of operations as of December 31, 2009, was immaterial. +Restricted Stock Awards +Time-Based Awards . The fair value of the time-based awards is amortized ratably over the requisite service period, generally over four years, and five years in connection with a one-time grant to executive officers in March 2008. Time-based awards for non-employee directors generally vest on July 1 of the year following the date of the grant. +The following table presents the changes in non-vested time-based awards for the year ended December 31, 2009. +Weighted Average +Grant-Date +Shares +Fair Value +Non-vested at December 31, 2008 +218,060 +$ +52.59 +Granted +210,548 +14.02 +Vested +(105,032 +) +50.88 +Forfeited +(18,248 +) +36.36 +Non-vested at December 31, 2009 +305,328 +$ +27.55 +As of/For the Year Ended December 31, +2009 +2008 +2007 +(in thousands, except per share data) +Total intrinsic value of time-based awards vested +$ +1,731 +$ +6,710 +$ +2,208 +Total intrinsic value of time-based awards non-vested +5,560 +5,249 +10,161 +Market price per common share as of December 31 +18.21 +24.07 +59.13 +Weighted average grant date fair value per share +14.02 +57.64 +48.09 +The total compensation cost related to non-vested time-based awards expected to vest and not yet recognized in our statements of operations as of December 31, 2009, was $6.4 million. This cost is expected to be recognized over a weighted average period of 2.3 years. For the year ended December 31, 2009, pursuant to an agreement with a former executive vice president, we accelerated time-based awards to vest 30,875 shares, all of which would have vested pursuant to the original terms of the award. For the year ended December 31, 2008, pursuant to agreements with our former president and our former chief executive officer, we modified time-based awards to vest 24,024 shares by accelerating the vesting schedule, none of which would have vested pursuant to the original terms of the award, resulting in an increase in the original fair value of $0.4 million. +F-35 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Market-Based Awards . The fair value of the market-based awards is amortized ratably over the requisite service period, primarily three years. Generally, the market-based shares vest if the participant is continuously employed throughout the performance period and certain per share price thresholds are attained as of the last day of each performance period, with a maximum vesting period of five years. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. For the year ended December 31, 2009, pursuant to an agreement with a former executive vice president, 21,263 shares were forfeited. For the year ended December 31, 2008, pursuant to agreements with our former president and our former chief executive officer, we modified market-based awards to vest 38,979 shares by accelerating the vesting schedule, none of which would have vested pursuant to the original terms of the award. The incremental change in fair value per share of the modified awards was immaterial. +The weighted average grant date fair value per market-based share, including shares modified in 2008 pursuant to agreements with our former president and our former chief executive officer, was computed using the Monte Carlo pricing model using the weighted average assumptions presented in the table below. +Year Ended December 31, +2009 +2008 +2007 +Expected term of award +3 years +3 years +3 years +Risk-free interest rate +2.0 +% +2.7 +% +4.7 +% +Volatility +59.0 +% +45.6 +% +44.0 +% +Weighted average grant date fair value per share +$ +6.47 +$ +43.61 +$ +36.07 +For 2009, expected volatility was based on a blend of our historical and implied volatility and, for 2008, was based on our historical volatility. The expected lives of the awards were based on the requisite service period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant or modification and extrapolated to approximate the life of the award. We do not expect to pay dividends, nor do we expect to declare dividends in the foreseeable future. +The following table presents the changes in non-vested market-based awards for 2009. +Weighted Average +Grant-Date +Shares +Fair Value +Non-vested at December 31, 2008 +72,683 +$ +41.62 +Granted +28,130 +6.47 +Forfeited +(21,263 +) +29.15 +Non-vested at December 31, 2009 +79,550 +$ +32.52 +The total compensation cost related to non-vested market-based awards expected to vest and not yet recognized in our statement of operations as of December 31, 2009, was $0.4 million. This cost is expected to be recognized over a weighted average period of 1.2 years. +Treasury Share Purchases +Treasury shares purchased pursuant to our non-employee director deferred compensation plan are purchased in the open market at fair value and held in a rabbi trust. +Pursuant to our stock-based compensation plans, we purchase shares from employees for their payment of tax liabilities related to the vesting of securities. Shares are purchased at fair market value based on the closing price on the date of purchase and subsequently retired. +F-36 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +In 2006, our Board approved a purchase program authorizing us to purchase up to 10% (1,477,109 shares) of our then outstanding common stock through April 2008. Stock purchases under this program were made in 2007 and 2008 in the open market or in private transactions, at times and in amounts that we deem appropriate. Total shares purchased pursuant to the purchase program were 76,283 common shares at a cost of $5 million ($65.73 average price paid per share), including 68,943 shares from our executive officers at a cost of $4.6 million ($67.22 price paid per share). The authorization to purchase the remaining 1,400,826 shares effectively expired on April 30, 2008. All shares purchased in accordance with the program were subsequently retired. +Pursuant to our senior notes indenture entered in February 2008, any future treasury purchases are limited, see Note 8 – Long-Term Debt. +Shareholders’ Rights Agreement +In 2007, we entered into a rights agreement. The rights agreement is designed to improve the ability of our Board to protect the interest of our shareholders in the event of an unsolicited takeover attempt. Our Board declared a dividend of one right for each outstanding share of our common stock. The right dividend was paid to shareholders of record on September 14, 2007. A "distribution date," as defined in the rights agreement, can occur after any individual shareholder exceeds 15% ownership of our outstanding common stock. After the occurrence of a "distribution date," the right entitles each registered holder (other than the acquiring shareholder who triggered the "distribution date"), to purchase shares of our common stock (or, in certain circumstances, cash, property or other securities) having a then-current value equal to two times the exercise price of the right (i.e., for the $240 exercise price, the rights holder receives $480 worth of common stock). The exercise price is subject to adjustment for various corporate actions which affect all shareholders, such as a stock split. The rights agreement and all rights will expire on September 11, 2017. +Common and Preferred stock +In July 2008, pursuant to shareholder approval, we amended and restated our Articles of Incorporation to: (1) increase the number of the Company's authorized shares of common stock, par value $0.01, from 50,000,000 shares to 100,000,000 shares, and (2) authorize 50,000,000 shares of Company preferred stock, par value $0.01, which may be issued in one or more series, with such rights, preferences, privileges and restrictions as shall be fixed by our Board from time to time. As of December 31, 2009, no preferred stock had been issued. +NO TE 13 – NONCONTROLLING INTEREST IN SUBSIDIARIES +WWWV, LLC +In May 2007, we contributed $0.8 million for a 50% interest in WWWV, LLC (the "LLC"), a limited liability company for which we serve as the managing member. The LLC’s only asset is an aircraft and the LLC was formed for the purpose of owning and operating the aircraft. We consolidate the entity based on a controlling financial interest. +PDC Mountaineer, LLC +On October 29, 2009, we entered into a joint venture arrangement with Lime Rock Partners to form PDC Mountaineer, LLC, a VIE. The joint venture was formed to develop our Marcellus Shale acreage and shallow Devonian assets in the Appalachian Basin. Under the terms of the agreement, we contributed acreage, producing properties and related reserves, gathering assets and equipment with an estimated fair value of $158.5 million for which we received a return of capital cash payment of $45 million and a 67.4% interest at closing, with an option to receive an additional cash withdrawal of $11.5 million by the end of 2010. Lime Rock contributed $55 million at closing and will fund up to an additional $58.5 million as needed for drilling and operations until it earns a 50% interest in the joint venture. We anticipate the partner’s funding obligation to be reached in 2011. After the 50% interest is earned, all future costs and capital investments will be shared equally. +The assets we contributed consist of (i) approximately 115,000 net acres in the Appalachian Basin, of which approximately 55,000 acres are in the Marcellus fairway, (ii) 12 MMcf per day of existing production from primarily the shallow Devonian sands, and (iii) total proved reserves of 113 Bcfe, also from the shallow Devonian sands. None of our affiliated partnerships’ wells were included in the joint venture. +F-37 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The joint venture was determined to be a variable interest entity due to the disproportionate voting rights compared to the ownership rights. We consolidated the joint venture as a result of being the primary beneficiary. See Note 2, Summary of Significant Accounting Policies - Recent Accounting Standards, Recently Issued Accounting Standards, Consolidation – Variable Interest Entities . +With the exception of our capital contribution, we have not entered into any arrangement that would require us to provide financial support to the joint venture. Further, we are not liable for any debts, obligations and liabilities of the joint venture and its creditors have no recourse against our general credit in the event of default. +The following table presents the carrying amount and classification of the joint venture’s assets and liabilities on our balance sheet. +December 31, +2009 +(in thousands) +Cash and cash equivalents +$ +9,428 +Property, plant and equipment, net +158,788 +Other assets +6,003 +Total assets +$ +174,219 +Other current liabilities +$ +12,224 +Asset retirement obligation +14,769 +Other liabilities +2,068 +Total liabilities +$ +29,061 +During the fourth quarter of 2009, we paid and recognized in the statement of operations as a component of general and administrative expenses $7.9 million in fees and expenses related to this transaction. +NO TE 14 - BUSINESS SEGMENTS +In the third quarter of 2009, our chief operating decision maker, a team of executive officers, ("CODM") began utilizing financial data reorganized to better reflect the core businesses in which we operate and how they manage the Company's resources. As the business of our oil and gas well drilling operations was completed in June 2009 and reported as discontinued operation, discrete financial information for this segment no longer exists beginning in July 2009. Further, well operations and pipeline income, formerly a separate segment, was included as a component of the oil and gas sales segment as of October 2009. The combination of these two activities better reflects how information is reported to and reviewed by our CODM. +We separate our operating activities into two segments: natural gas and oil sales and natural gas marketing. All material inter-company accounts and transactions between segments have been eliminated. +Natural Gas and Oil Sales. Our natural gas and oil sales segment includes all of our natural gas and oil properties. The segment represents revenues and expenses from the production and sale of natural gas and oil. Segment revenue includes natural gas and oil sales, commodity price risk management, net and well operation and pipeline income. Segment income (loss) consists of segment revenue less natural gas and oil production and well operations cost, exploration expense and impairment of natural gas and oil properties, direct general and administrative expense and DD&A expense. Segment DD&A expense was $127.4 million for 2009, $102.1 million for 2008 and $69.3 million for 2007. +Natural Gas Marketing. Our natural gas marketing segment purchases, aggregates and resells natural gas produced by us and others. Segment income (loss) primarily represents sales from natural gas marketing and direct interest income less costs of natural gas marketing and direct general and administrative expense. +Unallocated amounts. Unallocated income includes unallocated other revenue less corporate general administrative expense, corporate DD&A expense, interest income and interest expense. +F-38 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following tables present our segment information, reclassified for discontinued operations. +2009 +2008 +2007 +(in thousands) +Year Ended December 31, +Revenues: +Natural gas and oil sales +$ +180,064 +$ +461,189 +$ +187,285 +Natural gas marketing +64,635 +140,263 +103,624 +Unallocated +19 +293 +828 +Total +$ +244,718 +$ +601,745 +$ +291,737 +Segment income (loss) before income taxes: +Natural gas and oil sales +$ +(36,256 +) +$ +234,673 +$ +44,635 +Natural gas marketing +2,091 +1,329 +3,822 +Unallocated +(92,757 +) +(67,846 +) +(5,867 +) +Total +$ +(126,922 +) +$ +168,156 +$ +42,590 +Expenditures for segment long-lived assets: +Natural gas and oil sales +$ +140,431 +$ +316,959 +$ +233,516 +Unallocated +2,602 +6,194 +5,472 +Total +$ +143,033 +$ +323,153 +$ +238,988 +As of December 31, +Segment assets: +Natural gas and oil sales (1) +$ +1,152,160 +$ +1,297,739 +$ +893,296 +Natural gas marketing +22,614 +50,117 +40,269 +Unallocated (2) +75,553 +54,848 +116,914 +Total +$ +1,250,327 +$ +1,402,704 +$ +1,050,479 +(1) +December 31, 2007, includes $4.9 million previously included in our oil and natural gas well drilling segment. See Note 16, Discontinued Operations. +(2) +December 31, 2008 and 2007, includes $0.4 million and $0.1 million, respectively, previously included in our oil and natural gas well drilling segment. See Note 16, Discontinued Operations. +NO TE 15 - TRANSACTIONS WITH AFFILIATES +Amounts due from/to the affiliated partnership are primarily related to derivative positions, unbilled well lease operating expenses, and costs resulting from audit and tax preparation services. +We enter into derivative instruments for our own production as well as for our 33 affiliated partnerships’ production. We enter into these derivative instruments for us and, as the managing general partner, for the affiliated partnerships jointly by area of operation. Prior to September 30, 2008, as volumes produced changed, the allocation between us and the affiliated partnerships changed. As of September 30, 2008, we fixed the allocation of the derivative positions between us and each affiliated partnership. Fixed quantities of each of the then existing positions were allocated to us and the affiliated partnerships based upon current estimated future production. For positions entered into subsequent to September 30, 2008, specific designations of the quantities between us and the affiliated partnerships are made at the time the positions are entered into based on estimated future production. As of December 31, 2009, we have recorded a payable to affiliates of $13.4 million representing their designated portion of the fair value of our gross derivative assets and a due from affiliates of $21 million representing their designated portion of the fair value of our gross derivative liabilities. +F-39 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Our natural gas marketing segment manages the marketing of natural gas for our affiliated partnerships in the Appalachian Basin. Our sales from natural gas marketing include $5.5 million, $12.4 million and $9.3 million in 2009, 2008 and 2007, respectively, related to the marketing of natural gas on behalf of our affiliated partnerships. Included in our cost of natural gas marketing is $5.4 million, $12.1 million and $9.1 million for 2009, 2008 and 2007, respectively, related to these sales . +Through June 2009, we provided natural gas and oil well drilling services to our affiliated partnerships. As part of these services, we sold to them at cost the natural gas and oil leases upon which the wells are drilled. For the years ended December 31, 2008 and 2007, we sold to our affiliated partnerships leases in the amounts of $0.5 million and $1.4 million, respectively. Further, we provide well operations and pipeline services to our affiliated partnerships. The majority of all of our revenue and expenses related to well operations and pipeline income are associated with services provided to our affiliated partnerships. See Note 16, Discontinued Operations , for the natural gas and oil well drilling revenue recognized in 2009, 2008 and 2007. +NO TE 16 – DISCONTINUED OPERATIONS +We offered our last sponsored drilling partnership in October 2007. In January 2008, we first announced that we had no plans to sponsor a new drilling partnership in 2008 and this decision was upheld again in 2009. As of June 30, 2009, all remaining contractual drilling and completion obligations were completed for all partnerships. The unused advance for future drilling contracts of $1.7 million as of December 31, 2008, was fully utilized as of June 30, 2009, with $0.2 million recognized in revenue and $0.3 million refunded to the partnerships. +As all partnership well drilling and completion activities have been completed and we currently do not have any plans in the foreseeable future to sponsor a drilling partnership, we believe it was appropriate to treat our natural gas and oil well drilling activities as discontinued operation for all periods presented. Prior period financial statements have been restated to present the activities of our natural gas and oil well drilling operations as discontinued operations. +The following table presents statements of operations data related to discontinued operations. +Year Ended December 31, +Statements of Operations Data: +2009 +2008 +2007 +(in thousands) +Revenues: +Natural gas and oil well drilling +$ +193 +$ +7,615 +$ +13,498 +Cost and expenses: +Cost of natural gas and oil well drilling (1) +- +1,068 +1,939 +Income from discontinued operations before income taxes +193 +6,547 +11,559 +Provision for income taxes +80 +2,370 +4,476 +Income from discontinued operations, net of tax +$ +113 +$ +4,177 +$ +7,083 +(1) +Costs reclassified from cost of natural gas and oil well drilling to natural gas and oil production and well operations costs for the years ended December 31, 2009, 2008 and 2007 were $0.6 million, $1.1 million and $0.6 million, respectively. +F-40 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NO TE 17 - SALE OF NATURAL GAS AND OIL PROPERTIES +In July 2006, we sold to an unaffiliated company a portion of our undeveloped leasehold located in Grand Valley Field, Garfield County, Colorado. The sale encompassed 100% of the working interest in approximately 8,700 acres, including approximately 6,400 acres of the Chevron leasehold and 2,300 acres of the Puckett Land Company leasehold. We retained approximately 475 undeveloped locations on 10 acre spacing on the Grand Valley Field leasehold in addition to all of our producing properties in the field. The proceeds from the sale were $353.6 million, which was recognized as a gain on sale of leaseholds in our statements of operations, $328 million recorded in 2006 and $25.6 million recorded in 2007. +In conjunction with the purchase and sale agreement described above, we entered into a Like-Kind Exchange ("LKE") agreement, in accordance with Section 1031 of the Internal Revenue Code, with a "qualified intermediary." Proceeds in the amount of $300 million were transferred directly to the qualified intermediary to be held in trust pursuant to the terms of the LKE agreement. We had until mid-January 2007 to close any acquisition of suitable like-kind property, allowing us to take advantage of the income tax deferral benefits of a LKE transaction. Any unused amounts at that time would become taxable at our 2006 effective tax rate. See Note 18, Acquisitions , for a discussion of the qualifying acquisitions. +In December 2007, we sold to the same unaffiliated party above a portion of our North Dakota properties for approximately $34.7 million. The properties, located in Dunn, Williams and McKenzie Counties, North Dakota, include interests in five producing Bakken wells and approximately 72,000 net undeveloped acres. The reduction in our production and proved reserves as a result of this transaction was immaterial. We recorded a gain on sale of leaseholds of $7.7 million in the fourth quarter of 2007. Following the sale, we retain ownership in three producing wells in Dunn County, ten producing wells in Burke County and approximately 60,000 acres of undeveloped leasehold in Burke County. +NO TE 18 – ACQUISITIONS +Acquisition of Internal Revenue Code Section 1031 – LKE Properties. In January 2007, we completed the acquisition of suitable like-kind properties in accordance with the LKE agreement we entered into in connection with our sale of undeveloped leaseholds located in Grand Valley Field, Garfield County, Colorado in July 2006. We acquired, with cash, qualifying natural gas and oil properties totaling $188.9 million, including costs of acquisition, as described below. +EXCO Properties. We purchased producing properties and undeveloped drilling locations and acreage in the Wattenberg Field of the DJ Basin, Colorado from EXCO Resources Inc., an unaffiliated party. The acquisition included substantially all of EXCO’s assets in the area and encompassed 144 natural gas and oil wells (approximating 25.5 Bcfe proved developed reserves as of December 31, 2005) and 8,160 acres of leasehold interests. The wells and leases acquired are located in Weld, Adams, Larimer and Broomfield Counties, Colorado. We operate the assets and hold a majority working interest in the properties . +Company Sponsored Partnerships . We purchased the remaining working interests in 44 of our sponsored partnerships. The transaction resulted in an increase in our ownership in 718 gross (423 net) wells that we currently operate. The wells are located primarily in the Appalachian Basin and Michigan. +Other. We acquired from unaffiliated parties undeveloped leaseholds in Erath County, Texas for $2.1 million, including costs of acquisition. Acreage in this area is prospective for development of natural gas and oil reserves in the Barnett Shale. +Other Acquisitions. In February 2007, we acquired, from an unaffiliated party, 28 producing wells and associated undeveloped acreage located in Colorado (Wattenberg Field) for a purchase price of $12 million, which was allocated to natural gas and oil properties. +In October 2007, with an effective date of October 1, 2007, we purchased from unrelated parties, Castle Gas Company, et.al., a majority working interest in 762 natural gas wells located in southwestern Pennsylvania for approximately $54 million. We estimated that the acquisition included approximately 47 Bcfe of reserves, or 31 Bcfe of proved reserves and 16 Bcfe of unproved reserves. The purchase also included associated pipelines, equipment, real estate and undeveloped acreage. +F-41 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Allocation of Final Purchase Price. The following table presents, as of the respective date of acquisition, the final allocation of the purchase price based on estimates of fair value. +EXCO +Partnerships +Castle +(in thousands) +Current assets acquired +$ +91 +$ +- +$ +185 +Proved natural gas and oil properties +117,099 +59,081 +55,778 +Unproved natural gas and oil properties +14,960 +- +217 +Other properties and equipment +- +- +2,115 +Other noncurrent assets +- +- +783 +Asset retirement obligation +(422 +) +(2,433 +) +(4,043 +) +Other liabilities assumed +(1,513 +) +- +(968 +) +Total acquisition cost +$ +130,215 +$ +56,648 +$ +54,067 +The assessment of fair value of proved natural gas and oil properties acquired was based primarily on projections of expected discounted future cash flows of acquired natural gas and oil reserves. To compensate for the inherent risk of estimating and valuing unproved properties, the discounted future net revenues of probable reserves were reduced by additional risk-weighting factors in that valuation. +Pro Forma Financial Information. The results of operations for the above acquisitions have been included in our consolidated financial statements from the dates of acquisition. The pro forma effect of the inclusion in our consolidated statement of operations for the year ended December 31, 2007, of the results of operations for the January and February 2007 acquisitions described above, individually and in the aggregate, was not material. +The following unaudited pro forma financial information presents a summary of our consolidated results of operations for the year ended December 31, 2007, assuming the Castle properties had been completed as of January 1, 2007, including adjustments to reflect the allocation of the purchase price to the acquired net assets. +Year Ended +December 31, +2007 +(in thousands, except per share data) +Total revenues +$ +310,351 +Net income +$ +34,571 +Earnings per common share: +Basic +$ +2.34 +Diluted +$ +2.33 +The pro forma results of operations are not necessarily indicative of what our results of operations would have been had the Castle properties been acquired at the beginning of the period indicated, nor does it purport to represent our results of operations for any future periods. +F-42 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +SUPPLEMENTAL INFORMATION – UNAUDITED +NA TURAL GAS AND OIL OPERATIONS +Costs Incurred in Natural Gas and Oil Property Acquisition, Exploration and Development Activities +Costs incurred in natural gas and oil property acquisition, exploration and development are presented below. +Year Ended December 31, +2009 +2008 +2007 +(in thousands) +Acquisition of properties: +Proved properties +$ +2,251 +$ +6,147 +$ +257,330 +Unproved properties +5,867 +6,890 +13,701 +Development costs +72,416 +257,656 +194,031 +Exploration costs: +Exploratory drilling +18,317 +26,499 +12,972 +Geological and geophysical +1,788 +2,121 +6,299 +Total costs incurred +$ +100,639 +$ +299,313 +$ +484,333 +· +Property acquisition costs - represent costs incurred to purchase, lease or otherwise acquire a property. +· +Development costs - represents costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells, recompletions and to provide facilities to extract, treat, gather and store natural gas and oil. Of these costs incurred for the years ended December 31, 2009, 2008 and 2007, $49.1 million, $66.2 million and $37.1 million, respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end. +· +Exploration costs - represents costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing natural gas and oil reserves. +Capitalized Natural Gas and Oil Costs +Aggregate capitalized costs related to natural gas and oil exploration and production activities with applicable accumulated DD&A are presented below: +December 31, +2009 +2008 +(in thousands) +Proved natural gas and oil properties (1) +$ +1,329,666 +$ +1,169,969 +Unproved natural gas and oil properties +38,626 +32,768 +1,368,292 +1,202,737 +Less accumulated DD&A +428,754 +306,142 +$ +939,538 +$ +896,595 +· +As of December 31, 2009, we had no capitalized proved undeveloped natural gas and oil properties disclosed as such for longer than 5 years. +F-43 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +Results of Operations for Natural Gas and Oil Producing Activities +The results of operations for natural gas and oil producing activities, excluding natural gas marketing, are presented below. +Year Ended December 31, +2009 +2008 +2007 +(in thousands) +Revenue: +Natural gas and oil sales +$ +179,093 +$ +321,877 +$ +175,187 +Commodity price risk management gain, net +(10,053 +) +127,838 +2,756 +169,040 +449,715 +177,943 +Expenses: +Production costs +57,825 +72,518 +44,238 +DD&A +125,415 +100,207 +68,086 +Exploration costs +22,887 +45,105 +23,551 +206,127 +217,830 +135,875 +Results of operations for natural gas and oil producing +activities before provision for income taxes +(37,087 +) +231,885 +42,068 +Provision (benefit) for income taxes +(13,833 +) +86,493 +16,280 +Results of operations for natural gas and oil producing activities, +excluding corporate overhead and interest costs +$ +(23,254 +) +$ +145,392 +$ +25,788 +Production costs include those costs incurred to operate and maintain productive wells and related equipment, including costs such as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance and production and severance taxes. In addition, production costs include administrative expenses and depreciation applicable to support equipment associated with these activities. DD&A expense includes those costs associated with capitalized acquisition, exploration and development costs, but does not include the depreciation applicable to support equipment. The provision for income taxes is computed using effective tax rates. +Net Proved Natural Gas and Oil Reserves +We utilized the services of independent petroleum engineers to estimate our natural gas and oil reserves. For each of the three years in the three-year period ended December 31, 2009, our reserve estimates for the Appalachian and Michigan Basins are based on reserve reports prepared by Wright & Company and for the Rocky Mountain Region and Fort Worth Basin, reserve estimates are based on reserve reports prepared by Ryder Scott Company, L.P. These reserve estimates have been prepared in compliance with professional standards and the reserves definitions prescribed by the SEC. +Proved reserves estimates may change, either positively or negatively, as additional information becomes available and as contractual, economic and political conditions change. Our net proved reserve estimates have been adjusted as necessary to reflect all contractual agreements, royalty obligations and interests owned by others at the time of the estimate. Proved developed reserves are the quantities of natural gas and oil expected to be recovered through existing wells with existing equipment and operating methods. In some cases, proved undeveloped reserves may require substantial new investments in additional wells and related facilities. +F-44 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +The prices used to estimate our reserves, by commodity, are presented below. +Price +Oil +Gas +2009 +$ +54.64 +$ +3.17 +2008 +37.85 +4.98 +2007 +80.67 +6.77 +Our estimated 2009 reserve values below were based on 12-month average prices. Using the prior SEC reporting guidelines for quantifying reserves as of December 31, 2009, the Company would have used a year-end spot price of $5.51 per Mcf and $72.91 per Bbl, for natural gas and oil, respectively. Under the prior methodology, total reserves would have been approximately 94 Bcfe higher, or 811 Bcfe, as of December 31, 2009. +The following tables present the changes in our estimated quantities of natural gas and oil reserves. +Natural Gas +Oil +Total +(MMcf) +(MBbl) +(MMcfe) +Proved Reserves: +Proved reserves, January 1, 2007 +279,078 +7,272 +322,710 +Revisions of previous estimates +14,177 +1,375 +22,427 +Extensions, discoveries and other additions +Rocky Mountain Region +210,402 +3,700 +232,602 +Appalachian Basin +5,493 +- +5,493 +Michigan Basin +488 +- +488 +Purchases of reserves +Rocky Mountain Region +39,239 +4,490 +66,179 +Appalachian Basin +63,014 +2 +63,026 +Michigan Basin +6,059 +- +6,059 +Dispositions to partnerships +(1,874 +) +(591 +) +(5,420 +) +Production +(22,513 +) +(910 +) +(27,973 +) +Proved reserves, December 31, 2007 +593,563 +15,338 +685,591 +Revisions of previous estimates +(25,216 +) +(1,538 +) +(34,444 +) +Extensions, discoveries and other additions +Rocky Mountain Region +100,323 +2,354 +114,447 +Appalachian Basin +24,875 +- +24,875 +Purchases of reserves +Rocky Mountain Region +1,712 +106 +2,348 +Appalachian Basin +83 +- +83 +Michigan Basin +46 +- +46 +Dispositions to partnerships +(769 +) +(63 +) +(1,147 +) +Production +(31,760 +) +(1,160 +) +(38,720 +) +Proved reserves, December 31, 2008 +662,857 +15,037 +753,079 +Revisions of previous estimates +(101,923 +) +2,957 +(84,181 +) +Extensions, discoveries and other additions +Rocky Mountain Region +79,574 +1,322 +87,506 +Appalachian Basin +3,190 +- +3,190 +Purchases of reserves +Rocky Mountain Region +648 +47 +930 +Appalachian Basin +59 +- +59 +Other +63 +- +63 +Dispositions to partnerships +(7 +) +(1 +) +(13 +) +Production +(35,536 +) +(1,292 +) +(43,288 +) +Proved reserves, December 31, 2009 +608,925 +18,070 +717,345 +F-45 +Table of Contents +Natual Gas +(MMcf) +Oil +(MBbl) +Total +(MMcfe) +Proved Developed Reserves, as of: +January 1, 2007 +144,672 +3,503 +165,690 +December 31, 2007 +286,570 +5,219 +317,884 +December 31, 2008 +297,041 +5,438 +329,669 +December 31, 2009 +258,375 +6,244 +295,839 +Proved Undeveloped Reserves, as of: +January 1, 2007 +134,406 +3,769 +157,020 +December 31, 2007 +306,993 +10,119 +367,707 +December 31, 2008 +365,816 +9,599 +423,410 +December 31, 2009 +350,550 +11,826 +421,506 +PETROLEUM DEVELOPMENT CORPORATION +2009 Activity. In 2009, we revised our previous estimate of proved reserves downward by 84.2 Bcfe. The revision was primarily due to a decrease of 99.5 Bcfe due to lower commodity pricing and 45.1 Bcfe due to adjustments to reserves removed or reclassified due to new rules limiting proved undeveloped reserves location to those scheduled to be drilled within the next five years. The downward adjustments were partially offset by an increase of 41.4 Bcfe due to decreased operating costs, 1 Bcfe due to interest adjustments and 17.9 Bcfe due to asset performance. New discoveries and extensions of 90.7 Bcfe in 2009 are due to drilling of 100 gross wells and the addition of new proved undeveloped reserves: 3.2 Bcfe in the Appalachian Basin and 87.5 Bcfe in the Rocky Mountain Region (13.7 Bcfe in Wattenberg Field, 73.3 Bcfe in Grand Valley Field, and 0.5 Bcfe in North Dakota). We acquired 1.1 Bcfe of proved reserves through the purchase of interest in some of our existing properties. We acquired reserves primarily in the Wattenberg Field with the remaining reserves split between the Appalachian Basin, Michigan Basin, Piceance Basin and North Dakota. We sold a minimal amount of reserves to unaffiliated third parties in the Wattenberg Field. +2008 Activity . In 2008, we revised our previous estimate of proved reserves downward by 34.4 Bcfe. The revision was primarily due to a decrease of 50 Bcfe due to lower commodity prices, 25.8 Bcfe due to increased operating costs, and 14.4 Bcfe due to adjustments to proved undeveloped reserve values, partially offset be an increase of 55.8 Bcfe due to asset performance. New discoveries and extensions of 139.3 Bcfe in 2008 are due to drilling of 229 net wells and the addition of new proved undeveloped reserves: 24.9 Bcfe in the Appalachian Basin and 114.4 Bcfe in the Rocky Mountain Region (26.6 Bcfe in the Wattenberg Field, 80 Bcfe in Grand Valley Field, and 7.8 Bcfe in NECO and other areas). We acquired 2.5 Bcfe of proved reserves through the purchases of interest in some of our existing properties. We acquired reserves primarily in the Wattenberg Field with the remaining reserves being split between the Appalachian Basin, Michigan, Piceance, the NECO area and North Dakota. We sold proved reserves of 1.1 Bcfe to unaffiliated third parties and to our sponsored partnerships for drilling activity. +2007 Activity. In 2007, we revised our previous estimate of proved reserves upward by 22.4 Bcfe. The revision was primarily due to an increase of 25 Bcfe and 12 Bcfe, due to asset performance and higher commodity prices, respectively, partially offset by a decrease of 14.6 Bcfe due primarily to increased operating costs, adjustments to proved undeveloped reserve values and change in well ownership interests. New discoveries and extensions of 238.6 Bcfe in 2007 are due to the drilling of 218 net wells and the addition of 232.6 Bcfe of new proved undeveloped reserves in the Rocky Mountain Region (43.5 Bcfe in the Wattenberg Field, 170.4 Bcfe in Grand Valley Field and 18.7 Bcfe in the NECO area). We acquired 135.3 Bcfe of proved reserves through purchases of natural gas and oil properties: 65.5 Bcfe in the Wattenberg Field of the Rocky Mountain Region, 63 Bcfe in the Appalachian Basin and 6.1 Bcfe in the Michigan Basin. We sold proved reserves of 5.4 Bcfe to unaffiliated third parties and to our sponsored partnerships for drilling activity. +F-46 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Natural Gas and Oil Reserves +Presented in the following table is information with respect to the standardized measure of discounted future net cash flows relating to proved natural gas and oil reserves. +2009 +2008 +2007 +(in thousands) +Future estimated cash flows +$ +2,915,377 +$ +3,867,461 +$ +5,257,962 +Future estimated production costs +(1,088,337 +) +(1,325,362 +) +(1,374,027 +) +Future estimated development costs +(825,139 +) +(1,100,533 +) +(876,961 +) +Future estimated income tax expense +(237,790 +) +(384,676 +) +(1,159,489 +) +Future net cash flows +764,111 +1,056,890 +1,847,485 +10% annual discount for estimated timing of cash flows +(416,475 +) +(700,085 +) +(1,094,414 +) +Standardized measure of discounted future estimated net cash flows +$ +347,636 +$ +356,805 +$ +753,071 +Future cash inflows are computed by applying prices used in estimating the entity's proved natural gas and oil reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the statutory rate in effect at the end of each year to the future pretax net cash flows, less the tax basis of the properties and gives effect to permanent differences, tax credits and allowances related to the properties. +The following table presents the principal sources of change in the standardized measure of discounted future estimated net cash flows. +2009 +2008 +2007 +(in thousands) +Sales of natural gas and oil production net of production costs +$ +(136,568 +) +$ +(261,692 +) +$ +(137,725 +) +Net changes in prices and production costs +(107,766 +) +(479,894 +) +157,797 +Extensions, discoveries, and improved recovery, less related costs +30,851 +80,859 +317,031 +Sales of reserves +(21 +) +(2,012 +) +(7,846 +) +Purchase of reserves +1,266 +4,280 +342,792 +Development costs incurred during the period +40,603 +88,008 +42,510 +Revisions of previous quantity estimates +(46,226 +) +(79,536 +) +92,462 +Changes in estimated income taxes +38,371 +239,054 +(335,327 +) +Net changes in future development costs +101,765 +(87,625 +) +- +Accretion of discount +49,434 +122,409 +38,660 +Timing and other +19,122 +(20,117 +) +27,055 +Total +$ +(9,169 +) +$ +(396,266 +) +$ +537,409 +It is necessary to emphasize that the data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein. +F-47 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +QU ARTERLY FINANCIAL DATA +Quarterly financial data for the years ended December 31, 2009 and 2008, is presented below. The sum of the quarters may not equal the total of the year's net income per share due to changes in the weighted average shares outstanding throughout the year. +2009 +Quarter Ended +March 31, +June 30, +September 30, +December 31, +Year Ended +(in thousands, except per share data) +Revenues: +Natural gas and oil sales +$ +39,742 +$ +41,558 +$ +44,006 +$ +53,787 +$ +179,093 +Sales from natural gas marketing +22,389 +12,367 +12,444 +17,435 +64,635 +Commodity price risk management gain (loss), net +23,683 +(23,284 +) +(13,813 +) +3,361 +(10,053 +) +Well operations, pipeline income and other +2,838 +2,948 +2,563 +2,694 +11,043 +Total revenues +88,652 +33,589 +45,200 +77,277 +244,718 +Costs and expenses: +Natural gas and oil production and well operations costs +16,361 +14,044 +15,218 +19,123 +64,746 +Cost of natural gas marketing +21,878 +11,992 +11,556 +17,108 +62,534 +Exploration expense and impairment of natural gas and oil properties +5,643 +3,133 +6,586 +7,525 +22,887 +General and administrative expense +12,094 +14,784 +9,627 +17,480 +53,985 +Depreciation, depletion and amortization +34,360 +33,860 +32,576 +30,208 +131,004 +Total costs and expenses +90,336 +77,813 +75,563 +91,444 +335,156 +Gain on sale of leaseholds +120 +- +- +350 +470 +Loss from operations +(1,564 +) +(44,224 +) +(30,363 +) +(13,817 +) +(89,968 +) +Interest income +20 +12 +208 +14 +254 +Interest expense +(8,383 +) +(9,420 +) +(9,221 +) +(10,184 +) +(37,208 +) +Loss from continuing operations before income taxes +(9,927 +) +(53,632 +) +(39,376 +) +(23,987 +) +(126,922 +) +Benefit for income taxes +(4,095 +) +(20,537 +) +(14,601 +) +(6,483 +) +(45,716 +) +Loss from continuing operations +(5,832 +) +(33,095 +) +(24,775 +) +(17,504 +) +(81,206 +) +Income from discontinued operations, net of tax +113 +- +- +- +113 +Net loss +(5,719 +) +(33,095 +) +(24,775 +) +(17,504 +) +(81,093 +) +Less: net loss attributable to noncontrolling interests +(16 +) +(16 +) +(299 +) +(1,485 +) +(1,816 +) +Net loss attributable to shareholders +$ +(5,703 +) +$ +(33,079 +) +$ +(24,476 +) +$ +(16,019 +) +$ +(79,277 +) +Amounts attributable to Petroleum Development Corporation shareholders: +Loss from continuing operations +$ +(5,816 +) +$ +(33,079 +) +$ +(24,476 +) +$ +(16,019 +) +$ +(79,390 +) +Income from discontinued operations, net of tax +113 +- +- +- +113 +Net loss attributable to shareholders +$ +(5,703 +) +$ +(33,079 +) +$ +(24,476 +) +$ +(16,019 +) +$ +(79,277 +) +Earnings (loss) per share attributable shareholders: +Basic +Loss from continuing operations +$ +(0.39 +) +$ +(2.23 +) +$ +(1.44 +) +$ +(0.84 +) +$ +(4.83 +) +Income from discontinued operations +0.01 +- +- +- +0.01 +Net loss attributable to shareholders +$ +(0.38 +) +$ +(2.23 +) +$ +(1.44 +) +$ +(0.84 +) +$ +(4.82 +) +Diluted +Loss from continuing operations +$ +(0.39 +) +$ +(2.23 +) +$ +(1.44 +) +$ +(0.84 +) +$ +(4.83 +) +Income from discontinued operations +0.01 +- +- +- +0.01 +Net loss attributable to shareholders +$ +(0.38 +) +$ +(2.23 +) +$ +(1.44 +) +$ +(0.84 +) +$ +(4.82 +) +Weighted average common shares outstanding +Basic +14,793 +14,811 +16,962 +19,172 +16,448 +Diluted +14,793 +14,811 +16,962 +19,172 +16,448 +F-48 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +2008 +Quarter Ended +March 31, +June 30, +September 30, +December 31, +Year Ended +(in thousands, except per share data) +Revenues: +Natural gas and oil sales +$ +71,646 +$ +94,549 +$ +99,422 +$ +56,260 +$ +321,877 +Sales from natural gas marketing +23,325 +30,941 +53,372 +32,625 +140,263 +Commodity price risk management gain (loss), net +(42,310 +) +(101,798 +) +169,402 +102,544 +127,838 +Well operations, pipeline income and other +2,355 +2,472 +3,376 +3,564 +11,767 +Total revenues +55,016 +26,164 +325,572 +194,993 +601,745 +Costs and expenses: +Natural gas and oil production and well operations costs +18,203 +21,330 +22,582 +17,239 +79,354 +Cost of natural gas marketing +22,121 +30,117 +54,372 +32,624 +139,234 +Exploration expense and impairment of natural gas and oil properties +4,283 +3,467 +10,212 +27,143 +45,105 +General and administrative expense +9,823 +9,231 +8,106 +10,555 +37,715 +Depreciation, depletion and amortization +21,147 +22,121 +28,661 +32,711 +104,640 +Total costs and expenses +75,577 +86,266 +123,933 +120,272 +406,048 +Income (loss) from operations +(20,561 +) +(60,102 +) +201,639 +74,721 +195,697 +Interest income +271 +75 +151 +94 +591 +Interest expense +(4,932 +) +(6,394 +) +(7,817 +) +(8,989 +) +(28,132 +) +Income (loss) from continuing operations before income taxes +(25,222 +) +(66,421 +) +193,973 +65,826 +168,156 +Provision (benefit) for income taxes +(9,343 +) +(23,844 +) +67,834 +24,442 +59,089 +Income (loss) from continuing operations +(15,879 +) +(42,577 +) +126,139 +41,384 +109,067 +Income (loss) from discontinued operations, net of tax +1,935 +1,849 +741 +(348 +) +4,177 +Net income (loss) +(13,944 +) +(40,728 +) +126,880 +41,036 +113,244 +Less: net loss attributable to noncontrolling interests +(16 +) +(16 +) +(16 +) +(17 +) +(65 +) +Net income (loss) attributable to shareholders +$ +(13,928 +) +$ +(40,712 +) +$ +126,896 +$ +41,053 +$ +113,309 +Amounts attributable to Petroleum Development Corporation shareholders: +Income (loss) from continuing operations +$ +(15,863 +) +$ +(42,561 +) +$ +126,155 +$ +41,401 +$ +109,132 +Income (loss) from discontinued operations, net of tax +1,935 +1,849 +741 +(348 +) +4,177 +Net income (loss) attributable to shareholders +$ +(13,928 +) +$ +(40,712 +) +$ +126,896 +$ +41,053 +$ +113,309 +Earnings (loss) per share attributable to shareholders: +Basic +Income (loss) from continuing operations +$ +(1.08 +) +$ +(2.89 +) +$ +8.54 +$ +2.80 +$ +7.41 +Income (loss) from discontinued operations +0.13 +0.13 +0.05 +(0.02 +) +0.28 +Net income (loss) attributable to shareholders +$ +(0.95 +) +$ +(2.76 +) +$ +8.59 +$ +2.78 +$ +7.69 +Diluted +Income (loss) from continuing operations +$ +(1.08 +) +$ +(2.89 +) +$ +8.50 +$ +2.80 +$ +7.35 +Income (loss) from discontinued operations +0.13 +0.13 +0.05 +(0.02 +) +0.28 +Net income (loss) attributable to shareholders +$ +(0.95 +) +$ +(2.76 +) +$ +8.55 +$ +2.78 +$ +7.63 +Weighted average common shares outstanding +Basic +14,738 +14,742 +14,767 +14,778 +14,736 +Diluted +14,738 +14,742 +14,835 +14,791 +14,848 +F-49 +Table of Contents +PETROLEUM DEVELOPMENT CORPORATION +FINANCIAL STATEMENT SCHEDULE +Sc hedule II -VALUATION AND QUALIFYING ACCOUNTS +Description +Beginning +Balance +January 1 +Charged to +Costs and +Expenses +Deductions (a) +Ending +Balance +December 31 +(in thousands) +2009: +Allowance for doubtful accounts +$ +537 +$ +120 +$ +109 +$ +548 +Valuation allowance for state tax benefits +$ +- +$ +747 +$ +- +$ +747 +Valuation allowance for unproved natural gas and oil properties +$ +12,870 +$ +7,279 +$ +5,148 +$ +15,001 +2008: +Allowance for doubtful accounts +$ +357 +$ +180 +$ +- +$ +537 +Valuation allowance for unproved natural gas and oil properties +$ +2,365 +$ +12,798 +$ +2,293 +$ +12,870 +2007: +Allowance for doubtful accounts +$ +415 +$ +50 +$ +108 +$ +357 +Valuation allowance for unproved natural gas and oil properties +$ +596 +$ +2,183 +$ +414 +$ +2,365 +(a) +For allowance for doubtful accounts, deductions represent the write-off of accounts receivable deemed uncollectible. For calculation of allowance for unproved properties, deductions represent amortization of expired or abandoned unproved natural gas and oil properties. +F-50 \ No newline at end of file diff --git a/raw/filings/0000077877/2009/0001140361-10-009868/filing_metadata.csv b/raw/filings/0000077877/2009/0001140361-10-009868/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..e77997b48b1c31bd07ef5946423d3920cd2a4ab9 --- /dev/null +++ b/raw/filings/0000077877/2009/0001140361-10-009868/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 +0000077877,PDCE,"PDC ENERGY, INC.",10-K,2010-03-04,2009-12-31,2010-03-04T13:00:25.000Z,0001140361-10-009868,form10k.htm,PETROLEUM DEVELOPMENT CORP 10-K 12-31-2009,5420045,0,0,https://www.sec.gov/Archives/edgar/data/77877/000114036110009868/form10k.htm,https://www.sec.gov/Archives/edgar/data/77877/000114036110009868/,2009,2009,1 diff --git a/raw/filings/0000077877/2009/0001140361-10-009868/item1.txt b/raw/filings/0000077877/2009/0001140361-10-009868/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..2b9a6f7ac7d23d91e97975ae8d7a151ebdcee885 --- /dev/null +++ b/raw/filings/0000077877/2009/0001140361-10-009868/item1.txt @@ -0,0 +1,3 @@ +Item 1. +Business +2 \ No newline at end of file diff --git a/raw/filings/0000077877/2009/0001140361-10-009868/item13.txt b/raw/filings/0000077877/2009/0001140361-10-009868/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..41dfbbf39da97459144be28d5003746e6ccb97c1 --- /dev/null +++ b/raw/filings/0000077877/2009/0001140361-10-009868/item13.txt @@ -0,0 +1,3 @@ +Item 13. +Certain Relationships and Related Transactions, and Director Independence +50 \ No newline at end of file diff --git a/raw/filings/0000077877/2009/0001140361-10-009868/item9a.txt b/raw/filings/0000077877/2009/0001140361-10-009868/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..890643347e2940bac008e998d1bbcb347409b9aa --- /dev/null +++ b/raw/filings/0000077877/2009/0001140361-10-009868/item9a.txt @@ -0,0 +1,3 @@ +Item 9A. +Controls and Procedures +49 \ No newline at end of file diff --git a/raw/filings/0000077877/2009/0001140361-10-009868/rp_note.txt b/raw/filings/0000077877/2009/0001140361-10-009868/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2009/0001140361-10-009868/rpt_disclosure.txt b/raw/filings/0000077877/2009/0001140361-10-009868/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..c9d87680259808b6cd5db3dab148e54f25a151ac --- /dev/null +++ b/raw/filings/0000077877/2009/0001140361-10-009868/rpt_disclosure.txt @@ -0,0 +1,130 @@ +The related party transaction policy applies to each Director +and executive officer of the Company, any nominee for election +as a Director, any security holder who is known to own more than +five percent of the Company’s voting securities, any +immediate family member of any of the foregoing persons and any +corporation, firm or association in which one or more of the +Company’s Directors are directors or officers, or have a +substantial financial interest. +Under the related party transaction policy, a related person +transaction is a transaction or arrangement involving a related +person in which the Company is a participant or that would +require disclosure in the Company’s filings with the SEC as +a transaction with a related person. +The related persons must disclose to the Audit Committee any +potential related person transactions and must disclose all +material facts with respect to such interest. All related person +transactions will be reviewed by the Audit Committee. In +determining whether to approve or ratify a transaction, the +Audit Committee will consider the relevant facts and +circumstances of the transaction which may include factors such +as the relationship of the related person with the Company, the +materiality or significance of +26 +Table of Contents +the transaction to the Company and the business purpose and +reasonableness of the transaction, whether the transaction is +comparable to a transaction that could be available to the +Company on an arms-length basis, and the impact of the +transaction on the Company’s business and operations. +From January 1, 2009 to the present, there was no +transaction or series of transactions, or any currently proposed +transaction, in which the amount involved exceeds $120,000 and +in which any director, executive officer, holder of more than +five percent of the Company’s common stock or any member of +the immediate family of any of the foregoing persons had or will +have a direct or indirect material interest. +Indemnification +of Directors and Officers +The Company’s By-Laws provide that the Company shall +indemnify any Director, officer, employee, or other agent of the +Company who is or was a party, or is threatened to be made a +party, to any proceeding (other than an action by or in the +right of the Company to procure a judgment in its favor) by +reason of the fact that such person is or was an agent of the +Company, against expenses, judgments, fines, settlements, and +other amounts actually and reasonably incurred in connection +with such proceeding, if that person acted in good faith and in +a manner that person reasonably believed to be in the best +interest of the Company, and in the case of a criminal +proceeding, had no reasonable cause to believe the conduct of +that person was unlawful. +The Company has entered into separate indemnification agreements +with each of its Directors whereby the Company has agreed to +indemnify the Director against all expenses, including +attorneys’ fees, and other amounts reasonably incurred by +the director in connection with any threatened, pending or +completed civil, criminal, administrative or investigative +action or proceeding to which such person is party by reason of +the fact that he is or was a Director, as the case may be, of +the Company, if the person acted in good faith and in a manner +reasonably believed to be in or not opposed to the best +interests of the Company, and, with respect to any criminal +action or proceeding, the person had no reasonable cause to +believe such conduct to be unlawful. The agreements provide for +the advancement of expenses and that the Company has the right +to purchase and maintain insurance on behalf of the director +against any liability or liabilities asserted against such +person, whether or not the Company would have the power to +indemnify the person against such liability under any provision +of the agreement. The Company has agreed to indemnify such +person against expenses actually and reasonably incurred in +connection with any action in which the person has been +successful on the merits or otherwise. Indemnification must also +be provided by the Company (unless ordered otherwise by a court) +only as authorized in the specific case upon a determination +that the indemnification of the person is appropriate because he +or she has met the applicable standard of conduct described in +the agreement made by (1) the Board of Directors, by a +majority vote of a quorum consisting of Directors who are not +parties to such action or proceeding, (2) independent legal +counsel in a written opinion or (3) the shareholders of the +Company. +Additional +Information +The “Corporate Governance” section of the +Company’s internet site contains additional information, +including PDC’s Certificate of Incorporation and By-Laws, +written charters for each Board committee, and Board policy +statements. +The Company files annual, quarterly and current reports, proxy +statements and other information with the SEC. Copies of the +Company’s filings with the SEC are available to the public +at the SEC’s website at +http://www.sec.gov . +These documents may also be viewed at the SEC’s public +reference room located at 100 F Street, N.E., +Washington, D.C. 20549. Please call the SEC at +1-800-SEC-0330 +for further information on the public reference room. +27 +Table of Contents +EXECUTIVE +OFFICERS +The current executive officers of the Company, their principal +occupations for the past five years and additional information +is set forth below. +Name +Age +Position(s) +Richard W. McCullough +58 +Chairman, Chief Executive Officer and Director +Gysle R. Shellum +58 +Chief Financial Officer +Barton R. Brookman, Jr. +47 +Senior Vice President Exploration and Production +Daniel W. Amidon +49 +General Counsel and Secretary +Lance +Lauck (1) +47 +Senior Vice President Business Development +(1) +Mr. Lauck became Senior Vice President Business Development +on August 31, 2009. +RICHARD W. MCCULLOUGH was appointed Chief Executive +Officer of the Company in June 2008 and Chairman of PDC’s \ No newline at end of file diff --git a/raw/filings/0000077877/2010/0000077877-11-000011/filing.txt b/raw/filings/0000077877/2010/0000077877-11-000011/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..1e27e5a806e07d89c57a96e7a46bd4630ac294ea --- /dev/null +++ b/raw/filings/0000077877/2010/0000077877-11-000011/filing.txt @@ -0,0 +1,7817 @@ +10-K +1 +petrodev10kfy10.htm +PDC 2010 FORM 10-K +WebFilings | EDGAR view +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +FORM 10-K +T 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 +£ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period from __________ to _________ +Commission File Number 000-07246 +PETROLEUM DEVELOPMENT CORPORATION +(Exact name of registrant as specified in its charter) +(Doing Business as PDC Energy) +Nevada +95-2636730 +(State of Incorporation) +(I.R.S. Employer Identification No.) +1775 Sherman Street, Suite 3000 +Denver, Colorado 80203 +(Address of principal executive offices) (Zip Code) +Registrant's telephone number, including area code: (303) 860-5800 +Securities registered pursuant to Section 12(b) of the Act: +Title of Each Class +Name of Each Exchange on Which Registered +Common Stock, par value $0.01 per share +NASDAQ Global Select Market +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 £ No T +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 £ No T +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 T No £ +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 £ No £ +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. £ +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 definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. +Large accelerated filer £ +Accelerated filer x +Non-accelerated filer £ +(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 £ No T +The aggregate market value of our common stock held by non-affiliates on June 30, 2010 , was $489,660,892 (based on the then closing price of $25.62 ). +As of February 11, 2011 , there we re 23,463,272 sh ares of our common stock outstanding. +DOCUMENTS INCORPORATED BY REFERENCE +The information required by Part III of this Form is incorporated by reference to our definitive proxy statement to be filed pursuant to Regulation 14A for our 2011 Annual Meeting of Shareholders. +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +2010 ANNUAL REPORT ON FORM 10-K +TABLE OF CONTENTS +PART I +Page +Items 1 and 2. +Business and Properties +4 +Item 1A. +Risk Factors +16 +Item 1B. +Unresolved Staff Comments +27 +Item 3. +Legal Proceedings +27 +Item 4. +[Reserved] +27 +PART II +Item 5. +Market for the Registrant's Common Equity, Related Stockholders Matters and Issuer Purchases of Equity Securities +27 +Item 6. +Selected Financial Data +28 +Item 7. +Management's Discussion and Analysis of Financial Condition and Results of Operations +30 +Item 7A. +Quantitative and Qualitative Disclosure About Market Risk +45 +Item 8. +Financial Statements and Supplementary Data +48 +Item 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +48 +Item 9A. +Controls and Procedures +48 +Item 9B. +Other Information +49 +PART III +Item 10. +Directors, Executive Officers and Corporate Governance +49 +Item 11. +Executive Compensation +49 +Item 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +49 +Item 13. +Certain Relationships and Related Transactions and Director Independence +49 +Item 14. +Principal Accountant Fees and Services +49 +PART IV +Item15. +Exhibits, Financial Statement Schedules +49 +SIGNATURES +52 +PART I +REFERENCES TO THE REGISTRANT +Unless the context otherwise requires, references to "PDC," "PDC Energy," "the Company," "we," "us," "our," "ours" or "ourselves" in this report refer to the registrant, Petroleum Development Corporation and its consolidated entities. See Note 1, Nature of Operations and Basis of Presentation, to our consolidated financial statements included in this report for a description of our consolidated entities. +WHERE YOU CAN FIND MORE INFORMATION +We file annual, quarterly and current reports, proxy statements and other information with the United States ("U.S.") Securities and Exchange Commission ("SEC"). Our SEC filings are available free of charge from the SEC’s website at www.sec.gov or from our website at www.petd.com. You may also read or copy any document we file at the SEC’s public reference room in Washington, D.C., located at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Please call the SEC at (800) SEC-0330 for further information on the public reference room. We also make available free of charge any of our SEC filings by mail. For a mailed copy of a report, please contact Petroleum Development Corporation, Investor Relations, 1775 Sherman Street, Suite 3000, Denver, CO 80203, or call toll free (800) 624-3821. +We recommend that you view our web site for additional information, as we routinely post information that we believe is important for investors. Our web site can be used to access such information as our recent news releases, bylaws, committee charters, code of business conduct and ethics, shareholder communication policy, director nomination procedures and our whistle-blower hotline. While we recommend that you view our web site, the information available on our web site is not part of this report and is not hereby incorporated by reference. +UNITS OF MEASUREMENT +The following presents a list of units of measurement used throughout the document. +Bbl – One barrel of crude oil or NGL or 42 gallons of liquid volume. +Bcf – One billion cubic feet of natural gas volume. +Bcfe – One billion cubic feet of natural gas equivalent. +Btu – British thermal unit. +BBtu - One billion British thermal units. +MBbls – One thousand barrels of crude oil. +Mcf – One thousand cubic feet of natural gas volume. +Mcfe – One thousand cubic feet of natural gas equivalent (six Mcf of natural gas equals one Bbl of crude oil or NGL). +MMBtu – One million British thermal units. +MMcf – One million cubic feet of natural gas volume. +MMcfe – One million cubic feet of natural gas equivalent. +GLOSSARY OF INDUSTRY TERMS +The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report. +Behind-pipe reserves - Natural gas and crude oil reserves, proved or unproved, that cannot be produced until future perforation of casing at the depth of that reservoir. Generally, these are reserves in reservoirs above currently producing zones. +CIG - Colorado Interstate Gas. +Completion - The installation of permanent equipment for the production of natural gas and crude 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 hydrocarbons in sufficient quantities to justify completion as an oil or gas well. +Exit rate - Natural gas equivalent produced as of the date specified. +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 gas in another reservoir. +Extensions and discoveries - As to any period, the increases to proved reserves from all sources other than the acquisition of proved properties or revisions of previous estimates. +Farm-out - Transfer of all or part of the operating rights from a working interest owner to an assignee, who assumes all or some of the burden of development in return for an interest in the property. The assignor usually retains an overriding royalty interest but may retain any type of interest. +1 +Fracturing - Procedure to stimulate production by forcing a mixture of fluid (usually water) and proppant (usually sand) into the formation under high pressure. Fracing creates artificial fractures in the reservoir rock to increase permeability and porosity. +Gross acres or wells - Refers to the total acres or wells in which we have a working interest. +Horizontal drilling - A drilling technique that permits the operator to contact and intersect a larger portion of the producing horizon than conventional vertical drilling techniques and may, depending on the horizon, result in increased production rates and greater ultimate recoveries of hydrocarbons. +Joint interest billing or JIB - Process of distributing the costs related to well completions and operations among working interest partners. +Natural gas liquid(s) or NGL(s) - Hydrocarbons which can be extracted from wet natural gas and become liquid under various combinations of increasing pressure and lower temperature. NGLs consist primarily of ethane, propane, butane, and natural gasolines. +Net acres or wells - Refers to gross acres or wells multiplied, in each case, by the percentage working interest we own. +Net production - Natural gas and crude oil production that we own, less royalties and production due to others. +NYMEX - New York Mercantile Exchange. +Operator - The individual or company responsible for the exploration, development and/or production of an oil or gas well or lease. +PEPL - Panhandle Eastern Pipeline. +Proved developed non-producing reserves or PDNPs - Reserves that consist of (i) proved reserves from wells which have been completed and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and/or (ii) proved reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the wells. +Proved developed producing reserves or PDPs - Proved reserves that can be expected to be recovered from currently producing zones under the continuation of present operating methods. +Proved developed reserves - The combination of proved developed producing and proved developed non-producing reserves. +Proved reserves - Those quantities of natural gas, NGL, crude oil and condensate, 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 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. +Proved undeveloped reserves or PUDs - Proved 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 modification of an existing well for the purpose of producing natural gas and crude oil from a different producing formation. +Refrac or refracture - A refrac is when we stimulate the present producing zone of a well to increase its production as well as its PDPs, using hydraulic, acid, gravel, etc. fracture techniques. +Reserve replacement - Calculated by dividing the sum of reserve additions from all sources (revisions, extensions, discoveries and other additions and acquisitions) by the actual production for the corresponding period. The values used for reserve additions are derived directly from the proved reserves table located in Supplemental Information - Natural Gas and Crude Oil Operations to our consolidated financial statements included in this report. We use the reserve replacement ratio as an indicator of our ability to replenish annual production volumes and grow our reserves, thereby providing some information on the sources of future production. It should be noted that the reserve replacement ratio is a statistical indicator that has limitations. As an annual measure, the ratio is limited because it typically varies widely based on the extent and timing of new discoveries and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not embed the cost or timing of future production of new reserves, it cannot be used as a measure of value creation. +Reserves - Estimated remaining quantities of natural gas and crude oil and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering natural gas and crude oil or related substances to market, and all permits and financing required to implement the project. +2 +Royalty - An interest in a natural gas and crude oil lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner. +Standardized measure of discounted future net cash flows - Future net cash flows discounted at a rate of 10%. Future net cash flows represent the estimated future revenues to be generated from the production of proved reserves determined in accordance with Securities and Exchange Commission guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, giving effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment and (ii) future income tax expense. +Trunk line - A pipeline for the transportation of natural gas or crude oil from producing areas to refineries or terminals. +Undeveloped acreage - Leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and crude oil, regardless of whether such acreage contains proved reserves. +Wellbore - A physical hole that makes up the well, and can be cased, open or a combination of both. +Working interest - An interest in a natural gas and crude oil lease that gives the owner of the interest the right to drill and produce natural gas and crude oil on the leased acreage. It requires the owner to pay all of their share of the costs of drilling and production operations. +Workover - Major remedial operations on a producing well to restore, maintain or improve the well's production. +SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS +This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 ("Securities Act") and Section 21E of the Securities Exchange Act of 1934 ("Exchange Act") regarding our business, financial condition, results of operations and prospects. All statements other than statements of historical facts included in and incorporated by reference into this report are forward-looking statements. Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements herein, which include statements of estimated natural gas, NGL and crude oil production and reserves, drilling plans, future cash flows, anticipated liquidity, anticipated capital expenditures and our management’s strategies, plans and objectives. However, these are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Consequently, forward-looking statements are inherently subject to risks and uncertainties, including risks and uncertainties incidental to the exploration for, and the acquisition, development, production and marketing of natural gas and crude oil, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements. Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to: +• +changes in production volumes, worldwide demand and commodity prices for natural gas and crude oil; +• +changes in estimates of proved reserves; +• +declines in the values of our natural gas and crude oil properties resulting in impairments; +• +the timing and extent of our success in discovering, acquiring, developing and producing reserves; +• +our ability to acquire leases, drilling rigs, supplies and services at reasonable prices; +• +reductions in the borrowing base under our credit facility; +• +risks incident to the drilling and operation of natural gas and crude oil wells; +• +future production and development costs; +• +the availability of sufficient pipeline and other transportation facilities to carry our production and the impact of these facilities on price; +• +the effect of existing and future laws, governmental regulations and the political and economic climate of the U.S.; +• +changes in environmental laws and the regulation and enforcement related to those laws; +• +the identification of and severity of environmental events and governmental responses to the events; +• +our ability to insure adequately against operational mishaps and environment events; +• +the effect of natural gas and crude oil derivatives activities; +• +the availability and cost of capital to us; +• +our ability to consummate the prospective mergers of the 2005 partnerships and the timing of consummating these mergers, if at all; +• +conditions in the capital markets; and +• +losses possible from pending or future litigation. +3 +Further, we urge you to carefully review and consider the disclosures made in this report, including the risks and uncertainties that may affect our business as described herein under Item 1A, Risk Factors , and our other filings with the SEC. We caution you not to place undue reliance on forward-looking statements, which speak only as of the date of this report. We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. +ITEMS 1 AND 2. BUSINESS AND PROPERTIES +The Company +Established in 1969, we are an independent natural gas and crude oil company that explores for and acquires, develops, produces and markets natural gas and crude oil resources. Effective July 15, 2010, we began conducting business as PDC Energy. A new logo and corporate identity accompanied this change. Our common stock continues to trade on the NASDAQ Global Select Market under the ticker symbol PETD. Our web site, www.petd.com, reflects the new PDC Energy name and brand identity. We believe that the name PDC Energy more fully portrays the range of business activities in which we engage. At our annual shareholder meeting to be held in June 2011, we plan to request our shareholders to approve and amend our articles of incorporation to formally change our corporate name to PDC Energy. +2010 Overview +The year 2009 serves to remind us just how uncertain the commodity and financial markets can be and that our response to such uncertainty is crucial to our ability to achieve growth. We spent much of our efforts in 2009 ensuring that we had sufficient liquidity to weather the uncertain economic environment by maintaining a disciplined capital expenditure program. In 2010, as the economic environment began a slow but steady recovery, we increased our capital budget and were in an opportunistic position to be able to participate in certain growth opportunities presented. With capital markets showing renewed strength and confidence late in 2010, we took the opportunity to access the markets in November 2010 and successfully completed a $132.5 million sale of equity and a $115 million issuance of 3.25% convertible senior notes. Further in November 2010, we amended our bank credit facility, increasing our maximum facility amount and extending the maturity date to November 2015. +Our 2010 capital expenditures, exclusive of acquisitions, increased 13.8% over those in 2009. Because growth in production generally lags behind the investment, as evidenced by our decrease in production in 2010 as a result of our controlled investment in 2009, we believe that the consecutive increases in quarterly production experienced during the second half of 2010 signify our return to production growth. +In addition to our focus on organic growth, our business development group was actively pursuing available opportunities. In July, we successfully completed our first acquisition in the liquid producing province of the Permian Basin in West Texas. This acquisition was strategically important for two reasons: (1) it brought us closer to achieving our natural gas/crude oil production mix goal of 65/35 and (2) it allowed us to monetize our Michigan asset group while benefiting from Internal Revenue Code Section 1031, Like Kind Exchange , with the deferral of a $6.5 million tax liability. In November 2010, we completed our second acquisition in the Permian Basin, adding to our acreage holdings an additional 5,760 contiguous net undeveloped acres. Finally, in December 2010, we completed the acquisition of four affiliated partnerships. We believe that these partnership acquisitions will allow us the opportunity to grow through an accelerated refracturing program in our liquids-rich Wattenberg Field. +Business Strategy +Our primary objectives are to increase shareholder value through the growth of our reserves and production, while operating our properties in an efficient manner to maximize the cash flow and earnings potential of our assets. To achieve meaningful increases in these key areas, we maintain an active drilling and acquisition program that focuses on low risk development of our natural gas and crude oil reserves, targets emerging plays and enables us to acquire producing and undeveloped properties with what we believe to be significant development potential. In addition, we believe we maintain a conservative and disciplined financial strategy focused on providing sufficient liquidity and balance sheet strength to execute our business strategy. Our exploration program seeks to explore in areas where we believe we have a competitive advantage through operational expertise and a low cost of entry. +Drill and Develop +Our acreage holdings consist primarily of interests in developed and undeveloped natural gas and crude oil leases with positions primarily in the Rocky Mountain Region, the Permian Basin in West Texas and, through our joint venture, PDC Mountaineer, LLC ("PDCM"), the Appalachian Basin. We seek to maximize the value of our existing wells through a program of well recompletions, refractures and workovers and believe that our holdings of undeveloped properties provide us with a number of substantial new drilling projects. For 2011, we have planned approximately 124 new gross developmental drilling projects in the Rocky Mountain Region, including 14 horizontal projects targeting the Horizontal Niobrara formation and 90 vertical projects targeting the Codell and Niobrara formations, 25 projects in the Permian Basin and 9 horizontal Marcellus projects in the Appalachian Basin. Further, we have planned approximately 140 recompletion and refracture opportunities in our Wattenberg Field. +4 +Drilling Activities. Our primary focus in the Rocky Mountain Region is on developmental drilling in the Wattenberg Field, where we primarily produce from the Codell and Niobrara formations. In October 2010, we launched a horizontal drilling program in our Wattenberg Field targeting the liquid rich play of the Niobrara shale. We currently have two drilling rigs operating in the Wattenberg Field and one rig in the Piceance Basin, executing a natural gas project with a strong focus on cost control and reserve optimization. In the Permian +Basin, we currently are focusing on developmental drilling and plan to keep at least one drilling rig operating on such projects. During 2010, in the Appalachian Basin, PDCM drilled five horizontal Marcellus shale wells to total depth, with three of them currently producing to pipeline, and began drilling a sixth well. +The following table presents the wells drilled, by operating area, during the last three years, as well as our planned 2011 drilling activity. +Planned +Year Ended December 31, +2011 +2010 +2009 +2008 +Gross +Gross +Net +Gross +Net +Gross +Net +Rocky Mountain Region +Wattenberg Field +104 +171 +134.4 +82 +65.2 +149 +122.7 +Grand Valley Field +12 +25 +25.0 +1 +1.0 +62 +54.4 +Other +12 +2 +0.5 +9 +5.0 +100 +88.7 +Total Rocky Mountain Region +128 +198 +159.9 +92 +71.2 +311 +265.8 +Permian Basin +25 +6 +5.0 +— +— +— +— +Appalachian Basin +9 +8 +4.5 +8 +8.0 +62 +62.0 +Other +6 +1 +0.7 +— +— +6 +5.6 +Total wells planned/drilled +168 +213 +170.1 +100 +79.2 +379 +333.4 +The following table presents our developmental and exploratory drilling activity for the last three years. There is no correlation between the number of productive wells completed during any period and the aggregate reserves attributable to those wells. Productive wells consist of wells spudded, turned in line and producing during the period. In-process wells represent wells that have been spudded, drilled and waiting to be fractured and/or for gas pipeline connection during the period. +Gross Drilling Activity +Year Ended December 31, +2010 +2009 +2008 +Productive +In-Process (1) +Dry +Productive +In-Process (2) +Dry +Productive +In-Process (3) +Dry +Development Wells +Rocky Mountain Region +150 +47 +— +70 +17 +2 +216 +73 +8 +Permian Basin +— +6 +— +— +— +— +— +— +— +Appalachian Basin +1 +2 +— +2 +— +— +44 +16 +— +Total development wells +151 +55 +— +72 +17 +2 +260 +89 +8 +Exploratory Wells +Rocky Mountain Region +— +1 +— +2 +1 +— +4 +3 +7 +Appalachian Basin +5 +— +— +5 +1 +— +— +2 +— +Other +— +1 +— +— +— +— +3 +— +3 +Total exploratory wells +5 +2 +— +7 +2 +— +7 +5 +10 +Total drilling activity +156 +57 +— +79 +19 +2 +267 +94 +18 +Recompletions/refractures +40 +32 +125 +__________ +(1) +Of the 57 wells in process as of December 31, 2010, 20 were connected and turned in line by February 11, 2011. +(2) +Of the 19 wells in process as of December 31, 2009, all were connected and turned in line in 2010. +(3) +Of the 94 wells in process as of December 31, 2008, 81 were connected and turned in line in 2009 and 13 were shut-in and are awaiting completion of a pipeline. +5 +Net Drilling Activity +Year Ended December 31, +2010 +2009 +2008 +Productive +In-Process +Dry +Productive +In-Process +Dry +Productive +In-Process +Dry +Development Wells +Rocky Mountain Region +125.4 +33.5 +— +61.3 +6.9 +1.0 +174.0 +69.8 +8.0 +Permian Basin +— +5.0 +— +— +— +— +— +— +— +Appalachian Basin +0.6 +1.1 +— +2.0 +— +— +44.0 +16.0 +— +Total development wells +126.0 +39.6 +— +63.3 +6.9 +1.0 +218.0 +85.8 +8.0 +Exploratory Wells +Rocky Mountain Region +— +1.0 +— +1.0 +1.0 +— +4.0 +3.0 +7.0 +Appalachian Basin +2.8 +— +— +5.0 +1.0 +— +— +2.0 +— +Other +— +0.7 +— +— +— +— +3.0 +— +2.6 +Total exploratory wells +2.8 +1.7 +— +6.0 +2.0 +— +7.0 +5.0 +9.6 +Total drilling activity +128.8 +41.3 +— +69.3 +8.9 +1.0 +225.0 +90.8 +17.6 +Recompletions/refractures +29.3 +30.6 +106.9 +Strategically Acquire +Our acquisition efforts focus on producing properties that have a significant undeveloped acreage component. When weighing potential acquisitions, we prefer properties that have value in producing wells, behind-pipe reserves and high quality undeveloped drilling locations. In late 2009 and early 2010, we completed a U.S. onshore basin study that analyzed new areas where we could bring our skills and capital to crude oil and liquid rich fields that we believe can help deliver higher margins with scale and predictable drilling results. We plan to acquire properties through either direct acquisitions of the assets or acquisitions of entities owning the assets. We may also divest non-core assets as we seek to optimize our property portfolio. During 2011 and 2012, we expect to focus our resources on identifying and acquiring properties that have a high liquids component relative to its overall content. +Acquisitions in the Permian Basin. In July 2010, we acquired from an unrelated party 72 producing wells and 120 crude oil drilling locations located in the Wolfberry Trend in the Permian Basin in West Texas for $74.9 million. In November 2010, we acquired from an unrelated party 100% of the interest in additional producing assets and undeveloped acreage for $39.4 million. This second acquisition consisted of a primarily contiguous 5,760 net acre block with 122 identified crude oil drilling locations, based on 40-acre spacing. +Partnership Purchase Plan. In 2010, we initiated a plan to purchase our affiliated partnerships. The acquisition of these partnerships will provide us with immediate growth in both production and proved reserves from assets with which we are familiar. We believe that these acquisitions will also allow us to realize operational benefits and cost synergies as well as the opportunity to identify, pursue and accelerate a refracture program of the wells acquired. Pursuant to the plan, the following activity occurred in 2010. +• +Acquisition of 2004 Partnerships . In December 2010, we acquired four affiliated partnerships: PDC 2004-A Limited Partnership, PDC 2004-B Limited Partnership, PDC 2004-C Limited Partnership and PDC 2004-D Limited Partnership. We purchased these partnerships for the aggregate amount of $34.8 million. These purchases included assets located in our core Wattenberg and Grand Valley Fields. +• +Potential Acquisition of 2005 Partnerships . In November 2010, we announced that we were pursuing the purchase of three affiliated partnerships: PDC 2005-A Limited Partnership, PDC 2005-B Limited Partnership and Rockies Region Private Limited Partnership. The special meetings whereby investor partners of the 2005 partnerships will have an opportunity to vote and approve the applicable merger agreements are currently scheduled for March 25, 2011. We expect that if the required approvals are received from the investor partners at the special meetings and various other closing conditions are satisfied, each of the mergers for the 2005 partnerships will close no later than March 31, 2011. If all three 2005 partnerships are acquired, we will pay up to an aggregate of approximately $43.3 million for the limited partnership units of these partnerships. The assets in these 2005 partnerships are located in our core Wattenberg and Grand Valley Fields. +Divestiture of Michigan Assets. In July 2010, we divested our Michigan assets, consisting of primarily natural gas properties, and related liabilities for net cash proceeds of $22 million. We realized a loss on the sale of $4.7 million in the form of an impairment charge. Following the sale to an unrelated party, we do not have significant continuing involvement in the operations of or cash flows from this asset group; accordingly, the results of operations related to the Michigan assets have been separately reported as discontinued operations in the consolidated financial statements included in this report. +North Dakota Assets Held for Sale . During the fourth quarter of 2010, we developed a plan to divest and began marketing for sale our North Dakota assets. The assets include producing wells, undeveloped leaseholds and related facilities primarily located in Burke County. The plan received board approval and is expected to occur within one year of approval. In December 2010, we executed a letter of intent with an unrelated third party, which provides for the sale of 100% of our North Dakota assets. On February 7, 2011, we executed a purchase and +6 +sale agreement with the same unrelated party and we expect the transaction to close early March 2011. Following the sale to the unrelated party, we will not have significant continuing involvement in the operations of or cash flows from these assets; accordingly, the results of operations related to the North Dakota assets have been separately reported as discontinued operations in the consolidated financial statements included in this report. +Manage Operational and Financial Risk +Historically, we have concentrated on developmental drilling and geographical diversification to help reduce risk levels associated with natural gas and crude oil drilling, production and commodity markets. Currently, the majority of our proved reserves are located in the Rocky Mountain Region. However, we believe we benefit from operational diversity in the Rocky Mountain Region by maintaining significant activity and production in separate areas containing a balanced mix of natural gas and crude oil. These areas include our liquid rich Wattenberg Field, including the emerging Horizontal Niobrara crude oil play, located in the DJ Basin in north central Colorado and our Grand Valley gas field in the Piceance Basin in western Colorado. In addition, we recently entered the liquid-rich Permian Basin of West Texas where we are building a significant drilling inventory in the Wolfberry Trend. We regularly review opportunities to further diversify into other regions where we can apply our operational expertise. We believe developmental drilling will remain the foundation of our capital program because we believe it is less risky than exploratory drilling. Although we engage in limited exploratory drilling, we view our exploratory activities as having the potential to identify new development opportunities that provide long-term production and reserve growth. We believe our joint venture, PDCM, serves to mitigate the risks associated with exploring our Marcellus Shale acreage by sharing the cost of exploratory drilling activities with an investing partner. +We believe we maintain a conservative financial approach and proactively employ strategies to help reduce the risks associated with the oil and natural gas industry. We believe we maintain a conservative balance sheet, focusing on providing sufficient liquidity to execute our business strategy. In addition, we utilize commodity-based derivative instruments to manage a portion of our exposure to price volatility with regard to our natural gas and crude oil sales and natural gas marketing. We utilize both financial and physical derivative instruments. The financial instruments generally consist of floors, collars, swaps and basis swaps and consist of NYMEX, CIG and PEPL-based contracts. We may utilize derivatives based on other indices or markets where appropriate. The contracts economically provide price stability for committed and anticipated natural gas and crude oil sales and purchases, generally forecasted to occur within the next two to four-year period. Our policies prohibit the use of commodity derivatives for speculative purposes and permit utilization of derivatives only if there is an underlying physical position. As of December 31, 2010, we had natural gas and crude oil derivative positions in place for 2011 covering 52.8% of our expected natural gas production and 51.3% of our expected crude oil production. +Riley Natural Gas ("RNG"), a wholly owned subsidiary, uses financial derivatives in its gas marketing operations to coordinate fixed purchases and sales. RNG also enters into back-to-back fixed-price physical purchases and sales contracts with counterparties. RNG does not always hedge the area basis risk for third party trades with back-to-back fixed price purchases and sales. We continue to evaluate the potential for reducing this risk by entering into derivative transactions. Further, we may choose to close out any portion of a derivative contract existing at any time, which may result in a realized gain or loss on that derivative transaction. +Business Segments +We divide our operating activities into two segments: natural gas and crude oil sales and natural gas marketing. +Natural Gas and Crude Oil Sales +Commodity sales. Our natural gas and crude oil sales segment primarily reflects revenues and expenses from the production and sale of natural gas, NGLs and crude oil. We sell our natural gas and NGLs to other gas marketers, utilities, industrial end-users and other wholesale gas purchasers. We generally sell the natural gas that we produce under contracts with indexed monthly pricing provisions. Virtually all of our contracts include provisions wherein prices change monthly with changes in the market, for which certain adjustments may be made based on whether a well delivers to a gathering or transmission line, quality of natural gas and prevailing supply and demand conditions. Therefore, the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. As a result, our revenues from the sale of natural gas, holding production volume constant, increase as market prices increase and decrease as market prices decline. We believe that the pricing provisions of our natural gas contracts are customary in the industry. We also enter into financial derivatives in order to reduce the impact of possible price volatility regarding the physical sales market. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations: Results of Operations – Commodity Price Risk Management, Net, Natural Gas and Crude Oil Derivative Activities and Note 4, Derivative Financial Instruments , to our consolidated financial statements included in this report. +Our wells in the Permian Basin and our Wattenberg Field produce crude oil and condensate as well as natural gas and NGLs. We do not refine any of our crude oil production. Our Wattenberg crude oil production is sold to purchasers at or near our wells under both short and long-term purchase contracts with monthly pricing provisions. Our Permian crude oil production is transported through our own and third party gathering systems and pipelines to move our crude oil from the wellhead to a purchaser-specified delivery point. +7 +Well operations and pipeline services. In addition to commodity sales, our natural gas and crude oil sales segment includes revenues and expenses related to well operations and pipeline services. As of December 31, 2010, we had an interest in 5,048 wells. We are paid a monthly operating fee for the portion of each well we operate that is owned by others, including our sponsored partnerships. The fee is competitive with rates charged by other operators in the area. As we are successful in our partnership acquisition program, revenues related to well operations and pipeline services will decrease. +We develop, own and operate gathering systems in some of our areas of operations. Pipelines and related facilities can represent a significant portion of the capital costs of developing wells, particularly in new areas located at a distance from existing pipelines. We consider these costs in our evaluation of our leasing, development and acquisition opportunities. +Our natural gas, NGLs and crude oil are transported through our own and third party gathering systems and pipelines, and we incur processing, gathering and transportation expenses to move our natural gas from the wellhead to a purchaser-specified delivery point. These expenses vary based on the volume and distance shipped, and the fee charged by the third-party processor or transporter. Capacity on these gathering systems and pipelines is occasionally limited and at times unavailable because of repairs or improvements, or as a result of priority transportation agreements with other gas transporters. While our ability to market our natural gas has been only infrequently limited or delayed, if transportation space is restricted or is unavailable, our cash flow from the affected properties could be adversely affected. In certain instances, we enter into firm transportation agreements to provide for pipeline capacity to flow and sell a portion of our gas volumes. In order to meet pipeline specifications, we are required, in some cases, to process our gas before we can transport it. We typically contract with third parties in the Grand Valley and NECO areas of our Rocky Mountain Region and Appalachian Basin for firm transportation of our natural gas. We also may enter into firm sales agreements to ensure that we are selling to a purchaser who has contracted for pipeline capacity. These agreements are subject to the same limitations discussed above in this paragraph. See Note 11, Commitments and Contingencies - Firm Transportation Agreements , to our consolidated financial statements included in this report for our long-term firm sales, processing and transportation agreements for pipeline capacity. +See Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations, Summary Operating Results, for production, sales, prices and lifting cost data for each of the years in the three-year period ended December 31, 2010. +Natural Gas Marketing +Our natural gas marketing segment is comprised of RNG. RNG specializes in the purchase, aggregation and sale of natural gas production in our Appalachian Basin. RNG purchases for resale natural gas produced by third party producers as well as natural gas produced by us, PDCM and our affiliated partnerships. The gas is marketed to third party marketers, natural gas utilities, as well as industrial and commercial customers, either directly through our gathering system, or through transportation services provided by regulated interstate pipeline companies. +For additional information regarding our business segments, see Note 17, Business Segments , to our consolidated financial statements included in this report. +Areas of Operations +The following map presents the general locations of our development, production and exploration activities as of December 31, 2010 . We focus our development, production and exploration efforts primarily in three geographic areas of the U.S.: the Rocky Mountain Region, the Permian Basin of West Texas and, through our joint venture, the Appalachian Basin. +8 +Rocky Mountain Region +Our primary focus in the Rocky Mountain Region is on developmental drilling. We divide our Rocky Mountain Region into two major operating areas: the Wattenberg and Grand Valley Fields. +• +Wattenberg Field, DJ Basin, Weld County, Colorado. Wells drilled in this area have historically been vertical and range from approximately 7,000 to 8,000 feet in depth. These wells targeted reservoirs in the Codell and Niobrara formations that have historically contained about 50% crude oil and NGLs. In October 2010, we began a horizontal drilling program targeting the liquid rich play of the Niobrara shale. Operations in the area, in addition to developmental drilling, include a program of refracturing existing wells in the Codell and Niobrara reservoirs. Well spacing ranges from 20 to 40 acres per well. +• +Grand Valley Field, Piceance Basin, Garfield County, Colorado. The majority of the development wells drilled in this area are drilled directionally from multi-well pads and generally range from two to ten wells per drilling pad. Wells range from 7,000 to 9,500 feet in depth and primarily target natural gas reserves developed from multiple sandstone reservoirs in the Mesaverde Williams Fork formation. Well spacing is approximately ten acres per well. +Permian Basin +We entered the Permian Basin through an acquisition in July 2010 and further added to our position in November 2010. Operating activities in this area focus on developmental drilling for crude oil from the Wolfberry Trend, which combines the Spraberry and Wolfcamp formations. Our Permian Basin assets also produce from additional long-life formations, including the Strawn, Fusselman and Ellenberger formations, where we have initiated production optimization and recompletion programs. +Appalachian Basin +In October 2009, through our contribution of the majority of our Appalachian Basin assets, consisting of acreage, producing properties and related reserves, gathering assets and equipment, and a cash contribution by Lime Rock Partners, LP, we formed the joint venture PDCM. The producing properties we contributed included developmental wells producing from the shallow Devonian and Mississippian aged tight sandstone reservoirs. PDCM focuses primarily on exploratory drilling, targeting the Marcellus Shale formation in West Virginia. In 2010, through our joint venture, we drilled five horizontal Marcellus Shale wells to total depth, with three of them currently producing to pipeline, and began drilling a sixth well. +In addition to wells owned through our joint venture, we own an interest in approximately 271 gross, 88.5 net, natural gas and crude oil wells in West Virginia, Pennsylvania and Tennessee. +9 +Properties +Productive Wells +The table below presents our productive wells by operating area at December 31, 2010 . +Productive Wells +As of December 31, 2010 +Natural Gas +Crude Oil +Total +Location +Gross +Net +Gross +Net +Gross +Net +Rocky Mountain Region +Wattenberg Field +1,627 +1,175.3 +25 +19.3 +1,652 +1,194.6 +Grand Valley Field +331 +231.7 +— +— +331 +231.7 +Other +717 +501.8 +12 +4.4 +729 +506.2 +Total Rocky Mountain Region +2,675 +1,908.8 +37 +23.7 +2,712 +1,932.5 +Permian Basin +— +— +74 +71.4 +74 +71.4 +Appalachian Basin +2,217 +965.4 +39 +15.5 +2,256 +980.9 +Other +6 +5.7 +— +— +6 +5.7 +Total productive wells +4,898 +2,879.9 +150 +110.6 +5,048 +2,990.5 +Proved Reserves +All of our proved reserves are located in the U.S. Our reserve estimates are prepared with respect to reserve categorization, using the definitions for proved reserves set forth in SEC Regulation S-X, Rule 4-10(a) and subsequent SEC staff regulations, interpretations and guidance. Substantially all of our proved reserves, including reserves held by consolidated companies and our proportionate share of PDCM and our affiliated partnerships, have been estimated by independent engineers. For our Appalachian Basin reserves, our internal reserve engineers estimated approximately three percent of the total proved developed natural gas reserves and approximately one percent of total proved undeveloped natural gas reserves. +We have a comprehensive process that governs the determination and reporting of our proved reserves. As part of our internal control process, our reserves are reviewed annually by an internal team composed of reservoir engineers, geologists and accounting personnel for adherence to SEC guidelines through a detailed review of land records, available geological and reservoir data as well as production performance data. The review includes, but is not limited to, confirmation that reserve estimates (1) include all properties owned, (2) are based on proper working and net revenue interests, and (3) reflect reasonable cost estimates and field performance. The internal team compiles the reviewed data and forwards the data to an independent engineering firm engaged to estimate our reserves. +Our reserve estimates as of December 31, 2010 , were substantially based on reserve reports prepared by Ryder Scott Company, L.P. ("Ryder Scott"); approximately three percent of the total proved developed natural gas reserves and approximately one percent of total proved undeveloped natural gas reserves were based on reserve estimates prepared by our internal engineering team. For each of the years in the two-year period ended December 31, 2009, our reserve estimates for the Rocky Mountain Region and Fort Worth Basin were prepared by Ryder Scott and our reserve estimates for the Appalachian and Michigan Basins were based on reserve reports prepared by Wright & Company. When preparing our reserve estimates, the independent engineers did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, production volumes, well test data, historical costs of operations and development, product prices, or any agreements relating to current and future operations of properties and sales of production. +The independent petroleum engineers prepare an estimate of our reserves in conjunction with an ongoing review by our engineers. A final comparison of data is performed to ensure that the reserve estimates are complete, determined by acceptable industry methods and to a level of detail we deem appropriate. The final independent petroleum engineers' estimated reserve reports are reviewed and approved by our engineering staff and management. +The professional qualifications of the lead engineer primarily responsible for overseeing the preparation of our reserve estimates meet the standards of Reserves Estimator as defined in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information as promulgated by the Society of Petroleum Engineers. This employee holds a Bachelor of Science degree in Petroleum and Natural Gas Engineering and has over 25 years of experience in reservoir engineering. The individual is a member of the Society of Petroleum Engineers, allowing the individual to remain current with developments and trends in the industry. Further, during 2009, this individual attended ten hours of formalized training relating to the definitions and disclosure guidelines set forth in the SEC's final rule released January 2009, Modernization of Oil and Gas Reporting . +10 +The tables below present information regarding our estimated proved reserves. Reserves cannot be measured exactly, because reserve estimates involve judgments. The estimates must be reviewed periodically and adjusted to reflect additional information gained from reservoir performance, new geological and geophysical data and economic changes. Neither the estimated future net cash flows nor the standardized measure is intended to represent the current market value of our proved reserves. For additional information regarding both of these measures, as well as other information regarding our proved reserves, see the Natural Gas and Crude Oil Information section of the supplemental information provided with our consolidated financial statements included in this report. +As of December 31, +2010 +2009 +2008 +Proved reserves +Natural gas (MMcf) +657,306 +608,925 +662,857 +Crude Oil, Condensate and NGLs (MBbls) (1) +33,885 +18,070 +15,037 +Total proved reserves (MMcfe) +860,616 +717,345 +753,079 +Proved developed reserves (MMcfe) +301,141 +295,839 +329,669 +Estimated future net cash flows (in thousands) (2) +$ +1,314,642 +$ +764,111 +$ +1,056,890 +Standardized measure (in thousands) (2)(3) +$ +488,418 +$ +347,636 +$ +356,805 +______________ +(1) +Prior to 2010, NGLs were included in natural gas, which impacts comparability for 2010 to 2009 and 2008. In 2010, NGLs represented 7.4% of total proved reserves. +(2) +Estimated future net cash flow represents the undiscounted estimated future gross revenue to be generated from the production of proved reserves, net of estimated production costs, future development costs and income tax expense. Prices used to estimate future gross revenues and production and development costs were based on the following: +• +Gross revenues +• +For 2010 and 2009, a 12-month average price calculated as the unweighted arithmetic average of the prices on the first day of each month, January through December; for 2008, prices in effect as of December 31, 2008. +• +Prices for each of the three years were adjusted by field for Btu content, transportation and regional price differences; however, they were not adjusted to reflect the value of our commodity hedges. +• +Production and development costs +• +Prices as of December 31 for each of the respective years presented. +• +The amounts shown do not give effect to non-property related expenses, such as corporate general and administrative expenses, debt service, or to depreciation, depletion and amortization expense. +(3) +The standardized measure of discounted future net cash flow represents the present value of estimated future net cash flows discounted at a rate of 10% per annum to reflect timing of future cash flows. +11 +As of December 31, 2010 +Natural Gas +(MMcf) +Crude Oil, Condensate and NGLs (MBbls) +Natural Gas +Equivalent +(MMcfe) +Percent +Proved developed +Rocky Mountain Region +Wattenberg Field +52,487 +10,298 +114,275 +38 +% +Grand Valley Field +106,260 +244 +107,724 +36 +% +Other +35,525 +287 +37,247 +12 +% +Total Rocky Mountain Region +194,272 +10,829 +259,246 +86 +% +Permian Basin +2,854 +1,427 +11,416 +4 +% +Appalachian Basin +30,081 +44 +30,345 +10 +% +Other +134 +— +134 +— +% +Total proved developed +227,341 +12,300 +301,141 +100 +% +Proved undeveloped +Rocky Mountain Region +Wattenberg Field +79,259 +18,187 +188,381 +34 +% +Grand Valley Field +304,343 +304 +306,167 +55 +% +Other +9,058 +— +9,058 +1 +% +Total Rocky Mountain Region +392,660 +18,491 +503,606 +90 +% +Permian Basin +2,125 +3,094 +20,689 +4 +% +Appalachian Basin +35,180 +— +35,180 +6 +% +Total proved undeveloped +429,965 +21,585 +559,475 +100 +% +Proved reserves +Rocky Mountain Region +Wattenberg Field +131,746 +28,485 +302,656 +35 +% +Grand Valley Field (1) +410,603 +548 +413,891 +48 +% +Other +44,583 +287 +46,305 +5 +% +Total Rocky Mountain Region +586,932 +29,320 +762,852 +88 +% +Permian Basin +4,979 +4,521 +32,105 +4 +% +Appalachian Basin +65,261 +44 +65,525 +8 +% +Other +134 +— +134 +— +% +Total proved reserves +657,306 +33,885 +860,616 +100 +% +______________ +(1) +Two leases in our Grand Valley Field represent 48% of our total proved reserves. +Substantially all of our natural gas and crude oil properties, exclusive of properties held by PDCM, have been mortgaged or pledged as security for our credit facility. Substantially all of PDCM's properties have been pledged as collateral for the joint venture's credit facility. See Note 4, Derivative Financial Instruments , and Note 8, Long-Term Debt , to our consolidated financial statements included in this report. +Developed and Undeveloped Acreage +The following table presents, by operating area, leased acres as of December 31, 2010 . +As of December 31, 2010 +Developed +Undeveloped (1) +Total +Location +Gross +Net +Gross +Net +Gross +Net +Rocky Mountain Region +Wattenberg Field +49,900 +48,300 +33,600 +25,200 +83,500 +73,500 +Grand Valley Field +2,900 +2,900 +5,100 +5,100 +8,000 +8,000 +Other +32,520 +24,400 +164,400 +107,700 +196,920 +132,100 +Total Rocky Mountain Region +85,320 +75,600 +203,100 +138,000 +288,420 +213,600 +Permian Basin +6,900 +6,400 +6,600 +6,400 +13,500 +12,800 +Appalachian Basin +53,900 +53,200 +9,500 +8,600 +63,400 +61,800 +Other +400 +400 +17,300 +14,100 +17,700 +14,500 +Total acreage +146,520 +135,600 +236,500 +167,100 +383,020 +302,700 +12 +__________ +(1) +Substantially all of our undeveloped acreage is related to leaseholds that are held by production. We have no material acreage with near term expiry, with the exception of 5,800 gross, 5,500 net, acres located in the Permian Basin, which expire during 2011. We have initiated a continuous drilling program in accordance with the terms of the leases, which will allow us to establish and hold by production those properties deemed prospective for commercial development. +Title to Properties +We believe that we hold good and defensible title to our developed properties, in accordance with standards generally accepted in the industry. As is customary in the industry, a preliminary title examination is conducted at the time the undeveloped properties are acquired. Prior to the commencement of drilling operations, a title examination is conducted and remedial work is performed with respect to discovered defects which we deem to be significant. Title examinations have been performed with respect to substantially all of our producing properties. +The properties we own are subject to royalty, overriding royalty and other outstanding interests customary to the industry. The properties may also be subject to additional burdens, liens or encumbrances customary to the industry, including items such as operating agreements, current taxes, development obligations under natural gas and crude oil leases, farm-out agreements and other restrictions. We do not believe that any of these burdens will materially interfere with the use of the properties. +Facilities +We lease 39,720 square feet in downtown Denver, Colorado, which serves as our corporate offices, through December 2015. We own a 32,000 square feet administrative office building located in Bridgeport, West Virginia, where we also lease approximately 17,700 square feet of office space in a second building through October 2011. +We own or lease field operating facilities in the following locations: +• +Colorado: Evans, Parachute and Wray +• +Pennsylvania: Indiana and Mahaffey +• +Texas: Midland +• +West Virginia: Bridgeport and Glenville +Governmental Regulation +While the prices of natural gas and crude oil are market driven, other aspects of our business and the industry in general are heavily regulated. The availability of a ready market for natural gas and crude oil production depends on several factors beyond our control. These factors include regulation of production, federal and state regulations governing environmental quality and pollution control, the amount of natural gas and crude oil available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. State and federal regulations generally are intended to protect consumers from unfair treatment and oppressive control, to reduce the risk to the public and workers from the drilling, completion, production and transportation of natural gas and crude oil, to prevent waste of natural gas and crude oil, to protect rights among owners in a common reservoir and to control contamination of the environment. Pipelines are subject to the jurisdiction of various federal, state and local agencies. In the western part of the U.S., the federal and state governments own a large percentage of the land and the rights to develop natural gas and crude oil. Generally, government leases are subject to additional regulations and controls not commonly seen on private leases. We take the steps necessary to comply with applicable regulations, both on our own behalf and as part of the services we provide to our drilling partnerships. We believe that we are in compliance with such statutes, rules, regulations and governmental orders, although there can be no assurance that this is or will remain the case. The following summary discussion of the regulation of the U.S. oil and natural gas industry is not intended to constitute a complete discussion of the various statutes, rules, regulations and environmental orders to which our operations may be subject. +Regulation of Natural Gas and Crude Oil Exploration and Production. Our exploration and production business is subject to various federal, state and local laws and regulations on the taxation of natural gas and crude oil, the development, production and marketing of natural gas and crude oil and environmental and safety matters. Many laws and regulations require drilling permits and govern the spacing of wells, rates of production, water discharge, prevention of waste and other matters. Prior to commencing drilling activities for a well, we must procure permits and/or approvals for the various stages of the drilling process from the applicable state and local agencies in the state in which the area to be drilled is located. The permits and approvals include those for the drilling of wells. Additionally, other regulated matters include: +• +bond requirements in order to drill or operate wells; +• +the location of wells; +• +the method of drilling and casing wells; +• +the surface use and restoration of well properties; +• +the plugging and abandoning of wells; and +• +the disposal of fluids. +Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the density of wells which may be drilled and the unitization or pooling of properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely primarily or exclusively on voluntary +13 +pooling of lands and leases. In areas where pooling is voluntary, it may be more difficult to form units, and therefore, more difficult to develop a project if the operator owns less than 100% of the leasehold. In addition, state conservation laws may establish maximum rates of production from natural gas and crude oil wells, generally prohibiting the venting or flaring of natural gas and imposing certain requirements regarding the ratability of production. Where wells are to be drilled on state or federal leases, additional regulations and conditions may apply. The effect of these regulations may limit the amount of natural gas and crude oil we can produce from our wells and may limit the number of wells or the locations at which we can drill. Such laws and regulations may increase the costs of planning, designing, drilling, installing, operating and abandoning our natural gas and crude oil wells and other facilities. In addition, these laws and regulations, and any others that are passed by the jurisdictions where we have production, could limit the total number of wells drilled or the allowable production from successful wells, which could limit our reserves. As a result, we are unable to predict the future cost or effect of complying with such regulations. +Although we currently hold very little acreage under federal leases, if we wish to increase such holdings then our costs and timing will be increased due to the new Bureau of Land Management leasing policies announced in May 2010. These policies change, among other things, the required environmental review, including additional public input related to the proposed leases. +Regulation of Sales and Transportation of Natural Gas. Historically, the price of natural gas was subject to limitation by federal legislation. The Natural Gas Wellhead Decontrol Act removed, as of January 1, 1993, all remaining federal price controls from natural gas sold in "first sales" on or after that date. The Federal Energy Regulatory Commission's, or FERC, jurisdiction over natural gas transportation was unaffected by the Decontrol Act. +We move natural gas through pipelines owned by other companies, and sell natural gas to other companies that also utilize common carrier pipeline facilities. Natural gas pipeline interstate transmission and storage activities are subject to regulation by the FERC under the Natural Gas Act of 1938, or NGA, and under the Natural Gas Policy Act of 1978, and, as such, rates and charges for the transportation of natural gas in interstate commerce, accounting, and the extension, enlargement or abandonment of its jurisdictional facilities, among other things, are subject to regulation. Each natural gas pipeline company holds certificates of public convenience and necessity issued by the FERC authorizing ownership and operation of all pipelines, facilities and properties for which certificates are required under the NGA. Each natural gas pipeline company is also subject to the Natural Gas Pipeline Safety Act of 1968, as amended, which regulates safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities. FERC regulations govern how interstate pipelines communicate and do business with their affiliates. Interstate pipelines may not operate their pipeline systems to preferentially benefit their marketing affiliates. +Each interstate natural gas pipeline company establishes its rates primarily through the FERC’s rate-making process. Key determinants in the ratemaking process are: +• +costs of providing service, including depreciation expense; +• +allowed rate of return, including the equity component of the capital structure and related income taxes; and +• +volume throughput assumptions. +The availability, terms and cost of transportation affect our natural gas sales. In the past, FERC has undertaken various initiatives to increase competition within the industry. As a result of initiatives like FERC Order No. 636, issued in April 1992, the interstate natural gas transportation and marketing system was substantially restructured to remove various barriers and practices that historically limited non-pipeline natural gas sellers, including producers, from effectively competing with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. The most significant provisions of Order No. 636 require that interstate pipelines provide transportation separate or "unbundled" from their sales service, and require that pipelines provide firm and interruptible transportation service on an open access basis that is equal for all natural gas suppliers. In many instances, the result of Order No. 636 and related initiatives has been to substantially reduce or eliminate the interstate pipelines' traditional role as wholesalers of natural gas in favor of providing only storage and transportation services. Another effect of regulatory restructuring is greater access to transportation on interstate pipelines. In some cases, producers and marketers have benefited from this availability. However, competition among suppliers has greatly increased and traditional long-term producer-pipeline contracts are rare. Furthermore, gathering facilities of interstate pipelines are no longer regulated by FERC, thus allowing gatherers to charge higher gathering rates. Historically, producers were able to flow supplies into interstate pipelines on an interruptible basis; however, recently we have seen the increased need to acquire firm transportation on pipelines in order to avoid curtailments or shut-in gas, which could adversely affect cash flows from the affected area. +Additional proposals and proceedings that might affect the industry occur frequently in Congress, FERC, state commissions, state legislatures, and the courts. The industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by FERC and Congress will continue. We cannot determine to what extent our future operations and earnings will be affected by new legislation, new regulations, or changes in existing regulation, at federal, state or local levels. +Environmental Matters +Our operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and tougher environmental legislation and regulations is expected to continue. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs and reduced access to the industry in general, our business and prospects could be adversely affected. +14 +We generate wastes that may be subject to the Federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes. The U.S. Environmental Protection Agency, or EPA, and various state agencies have limited the approved methods of disposal for certain hazardous and non-hazardous wastes. Furthermore, certain wastes generated by our operations that are currently exempt from treatment as "hazardous wastes" may in the future be designated as "hazardous wastes," and therefore be subject to more rigorous and costly operating and disposal requirements. +We currently own or lease numerous properties that for many years have been used for the exploration and production of natural gas and crude oil. Although we believe that we have utilized good operating and waste disposal practices, and when necessary, appropriate remediation techniques, prior owners and operators of these properties may not have utilized similar practices and techniques, and hydrocarbons or other wastes may have been disposed of or released on or under the properties that we own or lease or on or under locations where such wastes have been taken for disposal. These properties and the wastes disposed thereon may be subject to the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, RCRA and analogous state laws, as well as state laws governing the management of natural gas and crude oil wastes. Under such laws, 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) or to perform remedial plugging operations to prevent future contamination. +CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed of or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for release of hazardous substances under CERCLA may be subject to full liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and 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. As an owner and operator of natural gas and crude oil wells, we may be liable pursuant to CERCLA and similar state laws. +Our operations may be subject to the Clean Air Act, or CAA, and comparable state and local requirements. Amendments to the CAA were adopted in 1990 and contain provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. The EPA and states have been developing regulations to implement these requirements. We may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues. The State of Colorado has implemented new air emission regulations in 2009, which affect the industry, including our operations. +The Federal Clean Water Act, or CWA, and analogous state laws impose strict controls against the discharge of pollutants, including spills and leaks of crude oil and other substances. The CWA also regulates storm water run-off from natural gas and crude oil facilities and requires a storm water discharge permit for certain activities. Spill prevention, control, and countermeasure requirements of the CWA require appropriate containment terms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. +Crude oil production is subject to many of the same operating hazards and environmental concerns as natural gas production, but is also subject to the risk of crude oil spills. Federal regulations require certain owners or operators of facilities that store or otherwise handle crude oil, including us, to procure and implement Spill Prevention, Control and Counter-measures plans relating to the possible discharge of crude oil into surface waters. The Oil Pollution Act of 1990, or OPA, subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from crude oil spills. Noncompliance with OPA may result in varying civil and criminal penalties and liabilities. We are also subject to the CWA and analogous state laws relating to the control of water pollution, which laws provide varying civil and criminal penalties and liabilities for release of petroleum or its derivatives into surface waters or into the ground. Historically, we have not experienced any significant crude oil discharge or crude oil spill problems. Our shift in production since mid-2010 to a greater percentage of crude oil also enhances our risks related to soil and water contamination. +In 2009, the State of Colorado’s Oil and Gas Conservation Commission implemented new broad-based environmental and wildlife protection regulations for the industry. These regulations will continue to increase our costs and may ultimately limit some drilling locations. Our expenses relating to preserving the environment have risen over the past few years and are expected to continue to rise in 2011 and beyond. Environmental regulations have increased our costs and planning time, but have had no materially adverse effect on our ability to operate to date. However, no assurance can be given that environmental regulations or interpretations of such regulations will not, in the future, result in a curtailment of production or otherwise have a materially adverse effect on our business, financial condition or results of operations. See Note 11, Commitments and Contingencies – Litigation , Colorado Stormwater Permit, to our consolidated financial statements included in this report. +Operating Hazards and Insurance +Our exploration and production operations include a variety of operating risks, including, but not limited to, the risk of fire, explosions, blowouts, cratering, pipe failure, casing collapse, abnormally pressured formations, and environmental hazards such as gas leaks, ruptures and discharges of natural gas. The occurrence of any of these could result in substantial losses to us due to injury and loss of life, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. Our pipeline, gathering and distribution operations are +15 +subject to the many hazards inherent in the industry. These hazards include damage to wells, pipelines and other related equipment, damage to property caused by hurricanes, floods, fires and other acts of God, inadvertent damage from construction equipment, leakage of natural gas and other hydrocarbons, fires and explosions and other hazards that could also result in personal injury and loss of life, pollution and suspension of operations. +Any significant problems related to our facilities could adversely affect our ability to conduct our operations. In accordance with customary industry practice, we maintain insurance against some, but not all, potential risks; however, there can be no assurance that such insurance will be adequate to cover any losses or exposure for liability. The occurrence of a significant event not fully insured against could materially adversely affect our operations and financial condition. We cannot predict whether insurance will continue to be available at premium levels that justify our purchase or whether insurance will be available at all. Furthermore, we are not insured against our economic losses resulting from damage or destruction to third party property, such as the Rockies Express pipeline; such an event could result in significantly lower regional prices or our inability to deliver gas. +Competition +We believe that our exploration, drilling and production capabilities and the experience of our management and professional staff generally enable us to compete effectively. We encounter competition from numerous other natural gas and crude oil companies, drilling and income programs and partnerships in all areas of operations, including drilling and marketing natural gas and crude oil and obtaining desirable natural gas and crude oil leases on producing properties. Many of these competitors possess larger staffs and greater financial resources than we do, which may enable them to identify and acquire desirable producing properties and drilling prospects more economically. Our ability to explore for natural gas and crude oil prospects and to acquire additional properties in the future depends upon our ability to conduct our operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. We also face intense competition in the marketing of natural gas from competitors including other producers as well as marketing companies. Also, international developments and the possible improved economics of domestic natural gas exploration may influence other companies to increase their domestic natural gas and crude oil exploration. Furthermore, competition among companies for favorable prospects can be expected to continue, and it is anticipated that the cost of acquiring properties may increase in the future. +In 2010, certain regions experienced strong demand for drilling services and supplies which resulted in increasing costs. Our Wattenberg Field, Permian Basin and especially our Appalachian Basin experienced intense competition to gain access to drilling and pumping services. For 2011, early signs indicate increased costs are likely, in particular in our Wattenberg Field. Factors affecting competition in the industry include price, location of drilling, availability of drilling prospects and drilling rigs, fracturing services, pipeline capacity, quality of production and volumes produced. We believe that we can compete effectively in the industry in each of the areas where we have operations. Nevertheless, our business, financial condition and results of operations could be materially adversely affected by competition. We also compete with other natural gas and crude oil companies as well as companies in other industries for the capital we need to conduct our operations. With all the turmoil in the 2008/2009 capital markets, financing was more expensive and more difficult to obtain. If we do not have adequate capital to execute our business plan, we may be forced to curtail our drilling and acquisition activities. +Employees +As of December 31, 2010 , we had 327 employees, including 195 in production, 8 in natural gas marketing, 30 in exploration and development, 72 in finance, accounting and data processing and 22 in administration. Our employees are not covered by a collective bargaining agreement. We consider relations with our employees to be very good. +Our engineers, supervisors and well tenders are responsible for the day-to-day operation of wells and some pipeline systems. Much of the work associated with drilling, completing and connecting wells, including fracturing, logging and pipeline construction, is performed under our direction by subcontractors specializing in these activities as is common in the industry. +ITEM 1A. RISK FACTORS +You should carefully consider the following risk factors in addition to the other information included in this report. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common stock or other securities. +Risks Related to the Domestic and Global Economic Environment +The current slow economic growth both domestically and globally may not improve or there may be a reoccurrence of the recent global economic recession, which increases the magnitude and the likelihood of the occurrence of the negative consequences discussed in many of the risks factors that follow. +In particular, consider the risks related to (1) the rapid deterioration of demand for natural gas and crude oil resulting from such economic environment and the related negative effects on natural gas and crude oil pricing, and (2) the effect of the credit constraints on our business, including the severe reduction in the availability of credit for drilling or to finance acquisitions. Also consider the interplay between these two risks: decline in natural gas and crude oil prices can lead to a reduction in the borrowing base for our credit line, and hence a reduction in our credit available for drilling. Similarly, further reductions in natural gas and crude oil prices could result in some of our assets becoming uneconomic to exploit, which would reduce our reserves, which in turn would reduce our borrowing base and the credit available +16 +to us. These factors could result in less drilling and production by us, and could thereby adversely affect our profitability and could limit our ability to execute our business plan. These factors could also make it impossible or extremely expensive to extend the term of our revolving credit line. The global economic environment also increases the potential of counterparty failure risk for both the banks which are parties to our natural gas and crude oil derivative holdings and for payments from purchasers of our natural gas and crude oil. Lastly, inability to ascertain the ultimate depth and duration of such economic environment could cause us to refrain from capital expenditures in order to maintain higher liquidity; our uncertainty and caution could result in significantly reduced drilling and hence reduced future production, which in turn may result in reduced reserves, resulting in a reduced borrowing base and availability of funds from our credit facility. All these risks could have a significant adverse effect on our business and our financial results. Any deterioration in the domestic or global economic conditions will further amplify these risks. +The current slow economic growth both domestically and globally may not improve or there may be a reoccurrence of the disruptions during the recent recession in the global financial markets and the related economic environment may further decrease the demand for natural gas and crude oil and the prices of natural gas and crude oil, thereby limiting our future drilling and production, and thereby adversely affecting our financial condition and profitability. +The global financial market disruptions during the recent recession and the related economic environment resulted in a decrease in the demand for natural gas and crude oil and therefore lower natural gas and crude oil prices. For example, during the last six months of 2008, the prices for natural gas and crude oil decreased over 60% from the 2008 peak. If there is such an additional reduction in demand in the future, the continued production of gas may increase current oversupply and result in still lower gas prices. There is no certainty how long this low price environment would continue. We operate in a highly competitive industry, and certain competitors may have lower operating costs in such an environment. Furthermore, as a result of any such disruptions in the financial markets, it is possible that in future years we would not be able to borrow or otherwise raise sufficient funds to sustain or increase capital expenditures. Such market conditions may also make it more difficult or impossible for us to finance acquisitions, through either equity or debt; acquisitions have historically been a major source of growth for us. Consequently, we would be unable to expand our reserves, drilling operations and production. We may also have difficulty finding partners to develop new drilling prospects and to build the pipeline systems needed to transport our gas. Inability of third parties to finance and build additional pipelines out of the Rockies, the Marcellus and elsewhere could cause significant negative pricing effects. Any of the above factors could adversely affect our operating results. +Risks Related to Our Business and the Industry +Natural gas and crude oil prices fluctuate unpredictably and a decline in natural gas and crude oil prices can significantly affect the value of our assets, our financial results and impede our growth. +Our revenue, profitability and cash flow depend in large part upon the prices and demand for natural gas and crude oil. The markets for these commodities are very volatile, and even relatively modest drops in prices can significantly affect our financial results and impede our growth. For instance, in much of 2010, natural gas prices were too low to economically justify many drilling operations. Changes in natural gas and crude oil prices have a significant effect on our cash flow and on the value of our reserves, which can in turn reduce our borrowing base under our senior credit facility Prices for natural gas and crude oil may fluctuate widely in response to relatively minor changes in the supply of and demand for natural gas and crude oil, market uncertainty and a variety of additional factors that are beyond our control, including national and international economic and political factors and federal and state legislation. For example, any significant reduction in the growth rate of China could affect global oil prices significantly. +The prices of natural gas and crude oil are volatile, often fluctuating greatly. Lower natural gas and crude oil prices may not only reduce our revenues, but also may reduce the amount of natural gas and crude oil that we can produce economically. As a result, we may have to make substantial additional downward adjustments to our estimated proved reserves. If this occurs or if our estimates of development costs increase, production data factors change or our exploration results deteriorate, accounting rules may require us to write-down operating assets to fair value, as a non-cash charge to earnings. We assess impairment of capitalized costs of proved natural gas and crude oil properties by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which management reasonably estimates such products may be sold. In 2010, in conjunction with our decision to divest our Michigan assets, we recorded a related impairment charge on proved natural gas and crude oil properties of $4.7 million and in 2008, we recorded impairment charges totaling $12.8 million, primarily related to our properties in the Fort Worth Basin and in North Dakota. We may incur impairment charges in the future, which could have a material adverse effect on the results of our operations. +A substantial part of our natural gas and crude oil production is located in the Rocky Mountain Region, making it vulnerable to risks associated with operating primarily in a single geographic area. +Our operations have been focused on the Rocky Mountain Region, which means our current producing properties and new drilling opportunities are geographically concentrated in that area. Because our operations are not as diversified geographically as many of our competitors, the success of our operations and our profitability may be disproportionately exposed to the effect of any regional events, including fluctuations in prices of natural gas and crude oil produced from the wells in the region, natural disasters, restrictive governmental regulations, transportation capacity constraints, curtailment of production or interruption of transportation, and any resulting delays or interruptions of production from existing or planned new wells. For example, the recent increase in activity in the Niobrara could lead to bottlenecks in processing that negatively affect our results disproportionately compared to our more geographically diverse competitors. +17 +Prior to 2010, natural gas prices in the Rocky Mountain Region often fell disproportionately when compared to other markets, due in part to continuing constraints in transporting natural gas from producing properties in the region. Because of the concentration of our operations in the Rocky Mountain Region, such price decreases are more likely to have a material adverse effect on our revenue, profitability and cash flow than those of our more geographically diverse competitors. Although current natural gas prices in the Rocky Mountain Region are not steeply discounted to NYMEX, there can be no assurance as to such continuation. +Our estimated natural gas and crude oil reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves. +Natural gas and crude oil reserve engineering requires subjective estimates of underground accumulations of natural gas and crude oil and assumptions concerning future natural gas and crude oil prices, production levels, and operating and development costs over the economic life of the properties. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be inaccurate. Independent petroleum engineers prepare our estimates of natural gas and crude oil reserves using pricing, production, cost, tax and other information that we provide. The reserve estimates are based on certain assumptions regarding future natural gas and crude oil prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect: +• +the estimates of reserves; +• +the economically recoverable quantities of natural gas and crude oil attributable to any particular group of properties; +• +future depreciation, depletion and amortization ("DD&A") rates and amounts; +• +impairments in the value of our assets; +• +the classifications of reserves based on risk of recovery; +• +estimates of the future net cash flows; +• +timing of our capital expenditures; and +• +the amount of funds available for us to utilize under our revolving credit facility. +Some of our reserve estimates must be made with limited production history, which renders these reserve estimates less reliable than estimates based on a longer production history. Numerous changes over time to the assumptions on which the reserve estimates are based, as described above, often result in the actual quantities of natural gas and crude oil recovered being different from earlier reserve estimates. +The present value of our estimated future net cash flows from proved reserves is not necessarily the same as the current market value of our estimated natural gas and crude oil reserves. The estimated discounted future net cash flows from proved reserves were based on the 12-month average natural gas and crude oil index prices. However, factors such as actual prices we receive for natural gas and crude oil and hedging instruments, the amount and timing of actual production, amount and timing of future development costs, supply of and demand for natural gas and crude oil, and changes in governmental regulations or taxation also affect our actual future net cash flows from our natural gas and crude oil properties. +The timing of both our production and incurrence of expenses in connection with the development and production of natural gas and crude oil properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor (the rate required by the SEC) we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates currently in effect and risks associated with our natural gas and crude oil properties or the industry in general. +Unless natural gas and crude oil reserves are replaced as they are produced, our reserves and production will decline, which would adversely affect our future business, financial condition and results of operations. +Producing natural gas and crude oil reservoirs generally is characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The rate of decline will change if production from existing wells declines in a different manner than we estimated and the rate can change due to other circumstances. Thus, our future natural gas and crude oil reserves and production and, therefore, our cash flow and income, are highly dependent on efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, discover or acquire additional reserves to replace our current and future production at acceptable costs. As a result, our future operations, financial condition and results of operations would be adversely affected. +Acquisitions are subject to the uncertainties of evaluating recoverable reserves and potential liabilities. +Acquisitions of producing properties and undeveloped properties have been an important part of our historical growth. We expect acquisitions will also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, many of which are beyond our control. These factors include recoverable reserves, development potential, future natural gas and crude oil prices, operating costs and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform engineering, geological and geophysical reviews of the acquired properties, which we believe are generally consistent with industry practices. However, such reviews are not likely to permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well prior to an acquisition and our ability to evaluate undeveloped acreage is inherently imprecise. Even when we inspect a well, we may not always discover structural, subsurface and environmental problems that may exist or arise. In some cases, our review prior to signing a definitive purchase agreement may be even more limited. +18 +Our focus on acquiring producing natural gas and crude oil properties may increase our potential exposure to liabilities and costs for environmental and other problems existing on acquired properties. Often we are not entitled to contractual indemnification associated with acquired properties. We often acquire interests in properties on an "as is" basis with no or limited remedies for breaches of representations and warranties. We could incur significant unknown liabilities, including environmental liabilities, or experience losses due to title defects, in our acquisitions for which we have limited or no contractual remedies or insurance coverage. +Additionally, significant acquisitions can change the nature of our operations 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. We acquire interests in wells which we may need to operate together with other partners, and we acquire pipelines that we may need to operate and expect we may need to commit to drilling in the acquired areas to achieve the expected benefits. Consequently, we may not be able to efficiently realize the assumed or expected economic benefits of properties that we acquire, if at all. +We may not be able to consummate additional prospective acquisitions of our drilling partnerships, which could adversely affect our business operations. +Consummation of future acquisitions of drilling partnerships, which is conditioned on a pricing agreement with the special committee of our board of directors, as well as customary closing conditions, which may not be satisfied or waived. In addition, consummation of the acquisition of partnerships requires approval by the holders of a majority of the limited partnership units held by the non-affiliated investors of each respective partnership. Furthermore, each of the partnerships must complete their SEC proxy disclosure review process and receive clearance from the SEC before the partnerships can request approval of the merger transactions from their non-affiliated investors. If we are unable to consummate all or a portion of these prospective acquisitions, we would not realize the expected benefits of the proposed acquisitions. In addition, we will have incurred, and will remain liable for, transaction costs, including legal, accounting, financial advisory and other costs relating to the prospective acquisitions, including the costs of the special committee of our board of directors, whether or not they are consummated. The occurrence of any of these events individually or in combination could have an adverse effect on our business, financial condition and results of operations. +Any acquisitions we complete, including the prospective acquisitions, are subject to substantial risks that could adversely affect our financial condition and results of operations. +Even if we complete the prospective acquisitions, integration of the prospective acquisitions may be difficult. Any acquisition involves potential risks, including, among other things: +• +the validity of our assumptions about reserves, future production, future commodity prices, +revenues, capital expenditures and operating costs, including synergies; +• +an inability to integrate the businesses we acquire successfully; +• +a decrease in our liquidity by using a portion of our available cash or borrowing capacity under +our revolving credit facility to finance acquisitions; +• +a significant increase in our interest expense or financial leverage if we incur additional debt to +finance acquisitions; +• +the assumption of unknown liabilities, losses or costs, including those that are environmental, for +which we are not indemnified or for which our indemnity is inadequate; +• +the diversion of management’s attention from other business concerns; +• +natural disasters; +• +the incurrence of other significant charges, such as impairment of natural gas and crude oil properties, +goodwill or other intangible assets, asset devaluation or restructuring charges; +• +unforeseen difficulties encountered in operating in new geographic areas; and +• +customer or key employee losses at the acquired businesses. +If we fail to realize the benefits we anticipate from an acquisition, our results of operations may be adversely affected. +When drilling prospects, we may not yield natural gas or crude oil in commercially viable quantities. +A prospect is a property on which our geologists have identified what they believe, based on available information, to be indications of natural gas or crude oil bearing rocks. However, our geologists cannot know conclusively prior to drilling and testing whether natural gas or crude oil will be present or, if present, whether natural gas or crude oil will be present in sufficient quantities to repay drilling or completion costs and generate a profit given the available data and technology. If a well is determined to be dry or uneconomic, which can occur even though it contains some natural gas or crude oil, it is classified as a dry hole and must be plugged and abandoned in accordance with applicable regulations. This generally results in the loss of the entire cost of drilling and completion to that point, the cost of plugging, and lease costs associated with the prospect. Even wells that are completed and placed into production may not produce sufficient natural gas and crude oil to be profitable. If we drill a dry hole or unprofitable well on current and future prospects, the profitability of our operations will decline and our value will likely be reduced. In sum, the cost of drilling, completing and operating any well is often uncertain and new wells may not be productive. +19 +We may not be able to identify and acquire enough attractive prospects on a timely basis to meet our development needs, which could limit our future development opportunities and adversely affect our profitability. +Our geologists have identified a number of potential drilling locations on our existing acreage. These drilling locations must be replaced as they are drilled for us to continue to grow our reserves and production. Our ability to identify and acquire new drilling locations depends on a number of uncertainties, including the availability of capital, regulatory approvals, natural gas and crude oil prices, competition, costs, availability of drilling rigs, drilling results and the ability of our geologists to successfully identify potentially successful new areas to develop. Because of these uncertainties, our profitability and growth opportunities may be limited by the timely availability of new drilling locations. As a result, our operations and profitability could be adversely affected. +Drilling for and producing natural gas and crude oil are high risk activities with many uncertainties that could adversely affect our business, financial condition and results of operations. +Drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for natural gas and crude oil can be unprofitable, not only due to dry holes, but also due to curtailments, delays or cancellations as a result of other factors, including: +• +unusual or unexpected geological formations; +• +pressures; +• +fires; +• +blowouts; +• +loss of drilling fluid circulation; +• +title problems; +• +facility or equipment malfunctions; +• +unexpected operational events; +• +shortages or delivery delays of equipment and services; +• +compliance with environmental and other governmental requirements; and +• +adverse weather conditions. +Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and regulatory penalties. We maintain insurance against various losses and liabilities arising from operations; however, insurance against all operational risks is not available. Additionally, our management may elect not to obtain insurance if the cost of available insurance is excessive relative to the perceived risks presented. Thus, losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance and the governmental response to an event could have a material adverse effect on our business activities, financial condition and results of operations. +Our hydrocarbon drilling, transportation and processing activities are subject to a range of applicable federal, state and local laws and regulations. A loss of containment of hydrocarbons during these activities could potentially subject us to civil and/or criminal liability and the possibility of substantial costs, including environmental remediation, depending upon the circumstances of the loss of containment, the nature and scope of the loss and the applicable laws and regulations. We are currently involved in various remedial and investigatory activities at some of our wells and related sites. See Note 11, Commitments and Contingencies - Environmental , to our consolidated financial statements included in this report. +Under the "successful efforts" accounting method that we use, unsuccessful exploratory wells must be expensed in the period when they are determined to be non-productive, which reduces our net income in such periods and could have a negative effect on our profitability. +We have conducted exploratory drilling and plan to continue exploratory drilling in 2011 in order to identify additional opportunities for future development. Under the "successful efforts" method of accounting that we use, the cost of unsuccessful exploratory wells must be charged to expense in the period when they are determined to be unsuccessful. In addition, lease costs for acreage condemned by the unsuccessful well must also be expensed. In contrast, unsuccessful development wells are capitalized as a part of the investment in the field where they are located. Because exploratory wells generally are more likely to be unsuccessful than development wells, we anticipate that some or all of our exploratory wells may not be productive. The costs of such unsuccessful exploratory wells could result in a significant reduction in our profitability in periods when the costs are required to be expensed and have a negative effect on our debt covenants. +Increasing finding and development costs may impair our profitability. +In order to continue to grow and maintain our profitability, we must annually add new reserves that exceed our yearly production at a finding and development cost that yields an acceptable operating margin and DD&A rate. Without cost effective exploration, development or acquisition activities, our production, reserves and profitability will decline over time. Given the relative maturity of most natural gas and crude oil basins in North America and the high level of activity in the industry, the cost of finding new reserves through exploration and development operations has been increasing. The acquisition market for natural gas and crude oil properties has become extremely competitive among producers for additional production and expanded drilling opportunities in North America. Acquisition values for crude +20 +oil properties climbed in 2010 and these values may continue to increase in the future. This increase in finding and development costs results in higher DD&A rates. If the upward trend in crude oil finding and development costs continues, we will be exposed to an increased likelihood of a write-down in carrying value of our crude oil properties in response to any future falling commodity prices and reduced profitability of our operations. +Our development and exploration operations require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our natural gas and crude oil reserves, and ultimately our profitability. +Our industry is capital intensive. We expect to continue to make substantial capital expenditures in our business and operations for the exploration, development, production and acquisition of natural gas and crude oil reserves. To date, we have financed capital expenditures primarily with bank borrowings under our credit facility, cash generated by operations and capital markets, through the sale of equity and the issuance of debt securities. We intend to finance our future capital expenditures utilizing similar financing sources. Our cash flows from operations and access to capital are subject to a number of variables, including: +• +our proved reserves; +• +the amount of natural gas and crude oil we are able to produce from existing wells; +• +the prices at which natural gas and crude oil are sold; +• +the costs to produce natural gas and crude oil; and +• +our ability to acquire, locate and produce new reserves. +If our revenues or the borrowing base under our credit facility decreases as a result of lower natural gas and crude oil prices, operating difficulties, declines in reserves or for any other reason, then we may have limited ability to obtain the capital necessary to sustain our operations at current levels. We may, from time to time, need to seek additional financing. There can be no assurance as to the availability or terms of any additional financing. Our inability to obtain additional financing, or sufficient financing on favorable terms, would adversely affect our financial condition and profitability. +If our revenues or the borrowing base under our revolving credit facility decreases as a result of lower natural gas and crude oil prices, or we incur operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at planned levels, and our profitability may be adversely affected. +If additional capital is needed, we may not be able to obtain debt or equity financing on favorable terms, or at all. If cash generated by our operations or available under our revolving credit facility is not sufficient to meet our capital requirements, failure to obtain additional financing could result in a curtailment of the exploration and development of our prospects, which in turn could lead to a possible loss of properties, decline in natural gas and crude oil reserves and production and a decline in our profitability. +Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate. +Seasonal weather conditions and lease stipulations designed to protect various wildlife affect natural gas and crude oil operations in the Rocky Mountains. In certain areas, including parts of the Piceance Basin in Colorado, drilling and other natural gas and crude oil activities are restricted or prohibited by lease stipulations, or prevented by weather conditions, for up to six months out of the year. This limits our operations in those areas and can intensify competition during those months for drilling rigs, oil field equipment, services, supplies and qualified personnel, which may lead to additional or increased costs or periodic shortages. These constraints and the resulting high costs or shortages could delay our operations and materially increase operating and capital costs and therefore adversely affect our profitability. +We have limited control over activities on properties in which we own an interest but we do not operate, which could reduce our production and revenues. +We operate approximately 93% of the wells in which we own an interest. If we do not operate the properties in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of underlying properties. The failure by an operator to adequately perform operations, or an operator’s breach of the applicable agreements, could reduce production and revenues and adversely affect our profitability. The success and timing of drilling and development activities on properties operated by others therefore depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise (including safety and environmental compliance) and financial resources, inclusion of other participants in drilling wells, and use of technology. +Market conditions or operational impediments could hinder our access to natural gas and crude oil markets or delay production and thereby adversely affect our profitability. +Market conditions or the unavailability of satisfactory natural gas and crude oil transportation arrangements may hinder our access to natural gas and crude oil markets or delay our production. The availability of a ready market for natural gas and crude oil production depends on a number of factors, including the demand for and supply of natural gas and crude oil and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells for the lack of a market or because of inadequacy, unavailability or the pricing +21 +associated with natural gas pipelines, gathering system capacity or processing facilities. If that were to occur, we would be unable to realize revenue from those wells until we made production arrangements to deliver the product to market. Thus, our profitability would be adversely affected. +Our derivative activities could result in financial losses or reduced income from failure to perform by our counterparties or could limit our potential gains from increases in prices. +We use derivatives for a portion of our natural gas and crude oil production from our own wells, our partnerships and for natural gas purchases and sales by our marketing subsidiary to achieve a more predictable cash flow, to reduce exposure to adverse fluctuations in the prices of natural gas and crude oil, and to allow our natural gas marketing company to offer pricing options to natural gas sellers and purchasers. These arrangements expose us to the risk of financial loss in some circumstances, including when purchases or sales are different than expected, the counter-party to the derivative contract defaults on its contract obligations, or when there is a change in the expected differential between the underlying price in the derivative agreement and actual prices that we receive. +In addition, derivative arrangements may limit the benefit from increases in the prices for natural gas and crude oil. They may also require the use of our resources to meet cash margin requirements. Since we do not designate our derivatives as hedges, we do not currently qualify for use of hedge accounting; therefore, changes in the fair value of derivatives are recorded in our income statements, and our net income is subject to greater volatility than if our derivative instruments qualified for hedge accounting. For instance, if natural gas and crude oil prices rise significantly, it could result in significant non-cash charges each quarter, which could have a material negative effect on our net income. +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 our natural gas, NGL and crude oil sales or joint interest billings to a small number of third parties in the energy industry. This concentration of customers and joint interest owners may affect our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, our natural gas and crude oil derivatives as well as the derivatives used by our marketing subsidiary expose us to credit risk in the event of nonperformance by counterparties. Nonperformance by our customers may adversely affect our financial condition and profitability. +Terrorist attacks or similar hostilities may adversely affect our results of operations. +Increasing terrorist attacks around the world have created many economic and political uncertainties, some of which may materially adversely affect our business. Uncertainty surrounding military strikes or a sustained military campaign may affect our operations in unpredictable ways, including disruptions of fuel supplies and markets, particularly crude oil, and the possibility that infrastructure facilities, including pipelines, production facilities, processing plants and refineries, could be direct targets of, or indirect casualties of, an act of terror or war. The continuation of these attacks may subject our operations to increased risks and, depending on their ultimate magnitude, could have a material adverse effect on our business, results of operations, financial condition and prospects. +Our insurance coverage may not be sufficient to cover some liabilities or losses that we may incur. +The occurrence of a significant accident or other event not fully covered by insurance or in excess of our insurance coverage could have a material adverse effect on our operations and financial condition. Insurance does not protect us against all operational risks. We do not carry business interruption insurance at levels that would provide enough funds for us to continue operating without access to other funds. We do not carry contingent business interruption insurance related to the processing plants owned by our natural gas purchasers or oil refineries owned by our crude oil purchasers. For some risks, such as drilling blow-out insurance, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks that we are subject to are generally not fully insurable. +We may not be able to keep pace with technological developments in our industry. +Our industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement those or other new technologies at substantial cost. In addition, other natural gas and crude oil companies 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. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we were unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected. +Competition in our industry is intense, which may adversely affect our ability to succeed. +Our industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce natural gas and crude oil, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive natural gas and crude oil properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than we can. In addition, these +22 +companies may have a greater ability to continue exploration activities during periods of low natural gas and crude oil market prices. Larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which can adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because many companies in our industry have greater financial and human resources, we may be at a disadvantage in bidding for exploratory prospects and producing natural gas and crude oil properties. These factors could adversely affect the success of our operations and our profitability. +Anti-oil and gas industry sentiment has increased. The current trend is to increase regulation of our operations and the industry. We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business. +Our exploration, development, production and marketing operations are regulated extensively at the federal, state and local levels. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon natural gas and crude oil wells. Under these laws and regulations, we could also be liable for personal injuries, property damage and other damages. Failure to comply with these laws and regulations may result in the suspension or termination of operations and subject us to administrative, civil and criminal penalties. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects. +Part of the regulatory environment includes federal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing exploration and production activities. In addition, our activities are subject to the regulation of conservation practices and protection of correlative rights by state governments. These regulations affect our operations, increase our costs of exploration and production and limit the quantity of natural gas and crude oil that we can produce and market. A major risk inherent in our drilling plans is the need to obtain drilling permits from state and local authorities. Delays in obtaining regulatory approvals, drilling permits, 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. Additionally, the natural gas and crude oil regulatory environment could change in ways that might substantially increase our financial and managerial costs to comply with the requirements of these laws and regulations and, consequently, adversely affect our profitability. Furthermore, these additional costs may put us at a competitive disadvantage compared to larger companies in the industry which can spread such additional costs over a greater number of wells and larger operating staff. +Illustrative of this trend are the regulations implemented in 2009 by the State of Colorado, which focus on the industry. These multi-faceted regulations significantly enhance requirements regarding natural gas and crude oil permitting, environmental requirements and wildlife protection. Permitting delays and increased costs could result from these final regulations. +The BP crude oil spill in the Gulf of Mexico and anti-industry sentiment may result in new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. Although we have no operations in the Gulf of Mexico, this incident could result in regulatory initiatives in other areas as well that could limit our ability to drill wells and increase our costs of exploration and production. Furthermore, the U.S. Environmental Protection Agency ("EPA") has recently focused on citizen concerns about the risk of water contamination and public health problems from drilling and hydraulic fracturing activities, including public meetings around the country on this issue which have been well publicized and well attended. This renewed focus could lead to additional federal and state laws and regulations affecting our drilling, fracturing and operations. Additional laws, regulations or other changes could significantly reduce our future growth, increase our costs of operations, and reduce our cash flow, in addition to undermining the demand for the natural gas and crude oil we produce. +Other potential laws and regulations affecting us include new or increased severance taxes proposed in several states, including Pennsylvania. This could adversely affect the existing operations in these states and the economic viability of future drilling. Additional laws, regulations or other changes could significantly reduce our future growth, increase our costs of operations and reduce our cash flow, in addition to undermining the demand for the natural gas and crude oil we produce. +Certain federal income tax deductions currently available with respect to natural gas and crude oil and exploration and development may be eliminated as a result of future legislation. +In February 2009, U.S. President Barack Obama ("President Obama") and his administration (the "Obama administration"), released its budget proposals for the fiscal year 2010, which included numerous proposed tax changes. In April 2009, legislation was introduced to further these objectives, and in February 2010, the Obama administration released similar budget proposals for the fiscal year 2011. Although these proposals were not enacted, the changes contained in the budget proposals included the elimination of certain key U.S. federal income tax preferences currently available to natural gas and crude oil exploration and production. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for natural gas and crude oil properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is not possible at this time to predict how legislation or new regulations that may be adopted to address these proposals would impact our business, but any such future laws and regulations could negatively affect our financial condition and results of operation. +23 +New derivatives legislation and regulation could adversely affect our ability to hedge natural gas and crude oil prices and increase our costs and adversely affect our profitability. +In July 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”). The Dodd-Frank Act regulates derivative transactions, including our natural gas and crude oil hedging swaps (swaps are broadly defined to include most of our hedging instruments). The new law requires the issuance of new regulations and administrative procedures related to derivatives within one year. The effect of such future regulations on our business is currently uncertain. In particular, note the following: +• +The Dodd-Frank Act may decrease our ability to enter into hedging transactions which would expose us to additional risks related to commodity price volatility; commodity price decreases would then have an immediate significant adverse affect on our profitability and revenues. Reduced hedging may also impair our ability to have certainty with respect to a portion of our cash flow, which could lead to decreases in capital spending and, therefore, decreases in future production and reserves. +• +We expect that the cost to hedge will increase as a result of fewer counterparties in the market and the pass-through of increased counterparty costs, thereby increasing the costs of derivative instruments. Our derivatives counterparties may be subject to significant new capital, margin and business conduct requirements imposed as a result of the new legislation. +• +The Dodd-Frank Act contemplates that most swaps will be required to be cleared through a registered clearing facility and traded on a designated exchange or swap execution facility. There are some exceptions to these requirements for entities that use swaps to hedge or mitigate commercial risk. While we may ultimately be eligible for such exceptions, the scope of these exceptions currently is somewhat uncertain, pending further definition through rulemaking proceedings. +• +The above factors could also affect the pricing of derivatives and make it more difficult for us to enter into hedging transactions on favorable terms. +Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the natural gas and crude oil that we produce while physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects. +In December 2009, the EPA, published its findings 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. These findings allow the EPA to adopt and implement regulations that would restrict emissions of greenhouse gases under existing provisions of the Federal Clean Air Act. In June 2010, the EPA published its final rule to address the permitting of greenhouse gas emissions from stationary sources under the Prevention of Significant Deterioration ("PSD"), and Title V permitting programs. This rule “tailors” these permitting programs to apply to certain stationary sources of greenhouse gas emissions in a multi-step process, with the largest sources first subject to permitting. It is widely expected that facilities required to obtain PSD permits for their greenhouse gas emissions will be required to also reduce those emissions according to “best available control technology,” or BACT, standards. In its permitting guidance for greenhouse gases, issued on November 10, 2010, the EPA has recommended options for BACT, which include improved energy efficiency, among others. Any regulatory or permitting obligation that limits emissions of greenhouse gases could require us to incur costs to reduce emissions of greenhouse gases associated with our operations and also adversely affect demand for the natural gas and crude oil that we produce. +In addition, in October 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas sources in the U.S. on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010. On November 8, 2010, the EPA finalized rules to expand its greenhouse gas reporting rule to include onshore natural gas and crude oil production, processing, transmission, storage and distribution facilities. Reporting of greenhouse gas emissions from such facilities will be required on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011. +In June 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 on emissions of greenhouse gases in the U.S. and would require most sources of greenhouse gas emissions to obtain and hold “allowances” corresponding to their annual emissions of greenhouse gases. By steadily reducing the number of available allowances over time, ACESA would require a 17 percent reduction in greenhouse gas emissions from 2005 levels by 2020, increasing up to an 83 percent reduction of such emissions by 2050. Many 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. The passage of legislation that limits emissions of greenhouse gases from our equipment and operations could require us to incur costs to reduce the greenhouse gas emissions from our operations, and it could also adversely affect demand for the natural gas and crude oil that we produce. +Some have suggested that one consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods. If such effects were to occur, our operations could be adversely affected in various ways, including damages to our facilities from powerful winds or increased costs for insurance. +24 +Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we produce. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate +that climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is difficult to predict how the market for our fuels could be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business. +Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays in the production of natural gas and crude oil, including from the development of shale plays. A decline in the drilling of new wells and related servicing activities caused by these initiatives could adversely affect our financial position, results of operations and cash flows. +Most of our drilling uses hydraulic fracturing. Proposals have been introduced in the U.S. Congress to regulate hydraulic fracturing operations and related injection of fracturing fluids and propping agents used by the oil and natural gas industry in fracturing fluids under the federal Safe Drinking Water Act ("SDWA"), and to require the disclosure of chemicals used in the hydraulic fracturing process under the SDWA, Emergency Planning and Community Right-to-Know Act ("EPCRA"), or other laws. Hydraulic fracturing is an important and commonly used process in the completion of unconventional natural gas and crude oil wells in shale, coalbed and tight sand formations. Sponsors of these bills, which are currently being considered in the legislative process, including the House Energy and Commerce Committee and the Senate Environmental and Public Works Committee, have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies and otherwise cause adverse environmental impacts. The Chairman of the House Energy and Commerce Committee has initiated an investigation of the potential impacts of hydraulic fracturing, which has involved seeking information about fracturing activities and chemicals from certain companies in the oil and natural gas sector. The EPA has recently focused on citizen concerns about the risk of water contamination and public health problems from drilling and hydraulic fracturing activities, including public meetings around the country on this issue which have been well publicized and well attended. In March 2010, the EPA announced its intention to conduct a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on water quality and public health. The initial results are expected in the fall of 2012. +Several states have also proposed additional disclosure concerning chemicals used in the process. New York has imposed a moratorium on hydraulic fracturing of horizontal wells pending additional environmental investigation by the state. Lawsuits have also been filed against unrelated third parties in Pennsylvania and New York alleging contamination of drinking water by hydraulic fracturing. Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to natural gas and crude oil production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or lead us to incur increased operating costs in the production of natural gas and crude oil, including from the development of shale plays, or could make it more difficult to perform hydraulic fracturing. If these legislative and regulatory initiatives cause a material decrease in the drilling of new wells and in related servicing activities, our profitability could be materially impacted. +Litigation against us pertaining to our royalty practices and payments is ongoing; our cost of defending these lawsuits, and any future similar lawsuits, could be significant and any resulting judgments against us could have a material adverse effect upon our financial condition. +In recent years, litigation has commenced against us and other companies in our industry regarding royalty practices and payments in jurisdictions where we conduct business. For more information on the suits that currently relate to us, see Note 11, Commitments and Contingencies , to our consolidated financial statements included in this report. We intend to defend ourselves vigorously in these cases. Even if the ultimate outcome of this litigation resulted in our dismissal, defense costs could be significant. These costs would be reflected in terms of dollar outlay as well as the amount of time, attention and other resources that our management would have to appropriate to the defense. Although we cannot predict an eventual outcome of this litigation, a judgment in favor of a plaintiff could have a material adverse effect on our financial condition and profitability. +Risks Associated with Our Indebtedness +Our credit facility has substantial restrictions and financial covenants and we may have difficulty obtaining additional credit, which could adversely affect our operations. Our lenders can unilaterally reduce our borrowing availability based on anticipated sustained natural gas and crude oil prices. +We depend on our revolving credit facility for future capital needs. The terms of the borrowing agreement require us to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flows from operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants under the revolving credit facility or other debt financing could result in a default under those facilities, which could cause all of our existing indebtedness to be immediately due and payable. +The revolving credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion based upon projected revenues from the natural gas and crude oil properties securing their loan. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the revolving credit facility. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other natural gas and crude oil properties as additional collateral. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory +25 +principal prepayments required under the revolving credit facility. Our inability to borrow additional funds under our credit facility could adversely affect our operations and our financial results. +The indentures governing our outstanding notes and our senior credit facility impose (and we anticipate that the indentures governing any other debt securities we may issue will also impose) restrictions on us that may limit the discretion of management in operating our business. That, in turn, could impair our ability to meet our obligations. +The indentures governing our outstanding notes and our senior credit facility contain (and we anticipate that the indentures governing any other debt securities we may issue will also contain) various restrictive covenants that limit management’s discretion in operating our business. In particular, these covenants limit our ability to, among other things: +• +incur additional debt; +• +make certain investments or pay dividends or distributions on our capital stock, or purchase, redeem or retire capital stock; +• +sell assets, including capital stock of our restricted subsidiaries; +• +restrict dividends or other payments by restricted subsidiaries; +• +create liens; +• +enter into transactions with affiliates; and +• +merge or consolidate with another company. +These covenants could materially and adversely affect our ability to finance our future operations or capital needs. Furthermore, they may restrict our ability to expand, to pursue our business strategies and otherwise conduct our business. Our ability to comply with these covenants may be affected by circumstances and events beyond our control, such as prevailing economic conditions and changes in regulations, and we cannot assure you that we will be able to comply with them. A breach of any of these covenants could result in a default under the indentures governing our outstanding senior notes and any other debt securities we may issue in the future and/or our senior credit facility. If there were an event of default under our indentures and/or the senior credit facility, the affected creditors could cause all amounts borrowed under these instruments to be due and payable immediately. Additionally, if we fail to repay indebtedness under our senior credit facility when it becomes due, the lenders under the senior credit facility could proceed against the assets which we have pledged to them as security. Our assets and cash flow might not be sufficient to repay our outstanding debt in the event of a default. The occurrence of such an event would adversely affect our operations and profitability. +Our senior credit facility also requires us to maintain specified financial ratios and satisfy certain financial tests. Our ability to maintain or meet such financial ratios and tests may be affected by events beyond our control, including changes in general economic and business conditions, and we cannot assure you that we will maintain or meet such ratios and tests, or that the lenders under the senior credit facility will waive any failure to meet such ratios or tests. +In addition, upon a change in control, we are required to offer to buy each senior note for 101% of the principal amount, plus unpaid interest. A change in control is defined to include: (i) when a majority of the Board of Directors are not continuing directors; (ii) when one person (or group of related persons) holds direct or indirect ownership of over 50% of our voting stock; or (iii) upon sale, transfer or lease of substantially all of our assets. +We may incur additional indebtedness to facilitate our acquisition of additional properties, which would increase our leverage and could negatively affect our business or financial condition. +Our business strategy includes the acquisition of additional properties that we believe would have a positive effect on our current business and operations. We expect to continue to pursue acquisitions of such properties and may incur additional indebtedness to finance the acquisitions. Our incurrence of additional indebtedness would increase our leverage and our interest expense, which could have a negative effect on our business or financial condition. +If we fail to obtain additional financing, we may be unable to refinance our existing debt, expand our current operations or acquire new businesses. This could result in our failure to grow in accordance with our plans, or could result in defaults in our obligations under our senior credit facility or the indentures relating to our outstanding senior notes. +In order to refinance indebtedness, expand existing operations and acquire additional businesses or properties, we will require substantial amounts of capital. There can be no assurance that financing, whether from equity or debt financings or other sources, will be available or, if available, will be on terms satisfactory to us. If we are unable to obtain such financing, we will be unable to acquire additional businesses or properties and may be unable to meet our obligations under our senior credit facility and the indentures relating to our outstanding senior notes or any other debt securities we may issue in the future. Such an event would adversely affect our operations and profitability. +Risks Associated with Our Joint Venture +PDC Mountaineer, LLC is dependent upon our equity partner (the “Investor”) and poses exit-related risks for us. +The board of managers of the joint venture consists of three representatives appointed by us and three representatives appointed by the Investor, each with equal voting power. The joint venture agreement generally requires the affirmative vote of a majority of the members of the board to approve an action, and we and the Investor may not always agree on the best course of action for the joint venture. If such a +26 +disagreement were to occur, we would not be able to cause the joint venture to take action that we believed to be in the best interests of the joint venture. Consequently, our best interests may not be advanced and our investment in the joint venture could be adversely affected. If there is a disagreement about a development plan and budget for the joint venture, the Investor is entitled to unilaterally suspend substantially all of the operations of the joint venture, which could have a material adverse impact on the results of operations of the joint venture and our investment. Such a suspension could last for up to two years, at which point either party could elect to dissolve the joint venture or to sell their ownership interests to a third party. The Investor is entitled to a preference with respect to liquidating distributions and proceeds from significant sales of ownership interests up to the amount of its contributed capital, which would diminish our returns if the value of the joint venture had declined at the time of the liquidation or sale. +After a “restricted period” which generally lasts for the four year years following the closing of the joint venture, the Investor can seek to sell its interest in the joint venture to a third party, subject to rights of first offer and refusal in favor of us. If we do not exercise those rights in a sale involving all of the Investor’s ownership interests, the Investor can exercise “drag-along” rights and compel us to sell all of our interests in the proposed transaction. Accordingly, if we possessed insufficient funds and were unable to obtain financing necessary to purchase the Investor’s interest under the rights of first offer and refusal, we may be required to sell our interest in the joint venture at a time when we may not wish to do so. Under these circumstances, our investment in the joint venture could be adversely affected. +ITEM 1B. UNRESOLVED STAFF COMMENTS +None. +ITEM 3. LEGAL PROCEEDINGS +Information regarding our legal proceedings can be found in Note 11, Commitments and Contingencies – Litigation , to our consolidated financial statements included in this report. +ITEM 4. [RESERVED] +PART II +ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDERS MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES +Our authorized capital stock consists of 100,000,000 shares of common stock, par value $0.01 per share. Our common stock is traded on the NASDAQ Global Select Market under the ticker symbol PETD. The following table presents the range of high and low sales prices for our common stock for each of the periods presented. +Price Range +High +Low +January 1 - March 31, 2009 +$ +27.91 +$ +9.39 +April 1 - June 30, 2009 +20.63 +11.21 +July 1 - September 30, 2009 +19.14 +12.50 +October 1 - December 31, 2009 +21.87 +16.06 +January 1 - March 31, 2010 +25.37 +18.11 +April 1 - June 30, 2010 +27.73 +17.92 +July 1 - September 30, 2010 +30.39 +23.82 +October 1 - December 31, 2010 +43.01 +27.44 +As of February 11, 2011 , we had approximately 944 shareholders of record. +We have not paid any dividends on our common stock and currently intend to retain earnings for use in our business. We do not expect to declare cash dividends in the foreseeable future. +27 +The following table presents information about our purchases of our common stock during the three months ended December 31, 2010 . +Period +Total Number +of Shares +Purchased (1) +Average Price +Paid per Share +Total Number +of Shares +Purchased as +Part of Publicly +Announced Plans +or Programs +Maximum Number +of Shares that May +Yet Be Purchased +Under the Plans +or Programs +October 1 - 31, 2010 +724 +$ +31.26 +— +— +November 1 - 30, 2010 +3,207 +34.57 +— +— +December 1 - 31, 2010 +1,474 +42.25 +— +— +Total fourth quarter purchases +5,405 +36.22 +__________ +(1) +Purchases represent shares purchased pursuant to our stock-based compensation plans for payment of tax liabilities related to the vesting of securities. +SHAREHOLDER PERFORMANCE GRAPH +The performance graph below compares the cumulative total return of our common stock over the five-year period ended December 31, 2010 , with the cumulative total returns for the same period for the Standard and Poor's ("S&P") 500 Index and the Standard Industrial Code ("SIC") Index. The SIC Index is a weighted composite of 175 crude petroleum and natural gas companies. The results shown in the graph below are not necessarily indicative of future performance. +__________ +(1) +The cumulative total shareholder return assumes that $100 was invested, including reinvestment of dividends, if any, in our common stock on December 31, 2005, and in the S&P 500 Index and the SIC Index on the same date. +ITEM 6. SELECTED FINANCIAL DATA +28 +Year Ended December 31, +2010 +2009 +2008 +2007 (3) +2006 (3) +(in thousands, except per share data and as noted) +Statement of Operations +Natural gas, NGL and crude oil sales +$ +209,644 +$ +171,242 +$ +304,867 +$ +175,187 +$ +115,189 +Commodity price risk management gain (loss), net (1) +59,891 +(10,053 +) +127,838 +2,756 +9,147 +Total revenues +347,647 +230,876 +572,501 +291,737 +267,237 +Income (loss) from continuing operations +6,921 +(80,118 +) +105,831 +26,085 +233,102 +Earnings (loss) per share attributable to shareholders: +Net income (loss) attributable to shareholders - basic +$ +0.32 +$ +(4.82 +) +$ +7.69 +$ +2.25 +$ +15.18 +Net income (loss) attributable to shareholders - diluted +$ +0.31 +$ +(4.82 +) +$ +7.63 +$ +2.24 +$ +15.11 +Statement of Cash Flows +Net cash provided by operating activities +$ +151,813 +$ +143,895 +$ +139,101 +$ +60,304 +$ +67,390 +Capital expenditures +162,723 +143,033 +323,153 +238,988 +146,180 +Acquisitions +158,051 +— +— +255,661 +18,512 +Balance Sheet +Total assets +$ +1,389,035 +$ +1,250,327 +$ +1,402,704 +$ +1,050,479 +$ +884,287 +Working capital (deficit) +16,194 +32,936 +31,266 +(50,212 +) +29,180 +Long-term debt +295,695 +280,657 +394,867 +235,000 +117,000 +Equity +642,241 +538,593 +512,275 +396,285 +360,144 +Production, Pricing, and Lifting Costs +Total production (Bcfe) +37.6 +41.6 +36.9 +28.0 +16.9 +Average sales price (excluding gains/losses on derivatives) (per Mcfe) +$ +5.67 +$ +4.19 +$ +8.37 +$ +6.26 +$ +6.80 +Average sales price (including gains/losses on derivatives) (per Mcfe) +$ +6.92 +$ +6.77 +$ +8.62 +$ +6.52 +$ +6.91 +Average lifting cost (per Mcfe) (2) +$ +1.11 +$ +0.81 +$ +1.08 +$ +0.90 +$ +0.76 +Total proved reserves (Bcfe) +860.6 +717.3 +753.1 +685.6 +322.7 +______________ +(1) +See Note 4, Derivative Financial Instruments, to our consolidated financial statements included in this report. +(2) +Lifting costs represent lease operating expenses, excluding production taxes, on a per unit basis. +(3) +The years ended 2007 and 2006 do not present the effects of the divestitures of our Michigan and North Dakota assets as discontinued operations as the amounts related to these operations were immaterial to these years. +29 +ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +The following discussion and analysis, as well as other sections in this report, should be read in conjunction with our consolidated financial statements and related notes to consolidated financial statements included in this report. Further, we encourage you to revisit Special Note Regarding Forward-Looking Statements on page 3 of this report. +Non-GAAP Financial Measures +We use "adjusted cash flow from operations," "adjusted net income (loss) attributable to shareholders" and "adjusted EBITDA," non-GAAP financial measures, for internal managerial purposes, when evaluating period-to-period comparisons and providing public guidance on possible future results. These measures are not measures of financial performance under U.S. GAAP and should be considered in addition to, not as a substitute for, cash flows from operations, investing, or financing activities, nor as a liquidity measure or indicator of cash flows reported in accordance with U.S. GAAP. The non-GAAP financial measures that we use may not be comparable to similarly titled measures reported by other companies. Also, in the future, we may disclose different non-GAAP financial measures in order to help our investors more meaningfully evaluate and compare our future results of operations to our previously reported results of operations. We strongly encourage investors to review our financial statements and publicly filed reports in their entirety and to not rely on any single financial measure. See Reconciliation of Non-GAAP Financial Measures below for a detailed description of these measures as well as a reconciliation of each to the nearest U.S. GAAP measure. +2010 Overview +In 2010, we committed our efforts to strengthen the structure of our business, by building a foundation that will support our operations for future growth. Production from continuing operations decreased by 9.5% compared to 2009, including the impact on comparability due to the recognition of NGL volumes separately from natural gas, which lessens the year-over-year decrease. We experienced a decrease in quarter-over-quarter production during the first half of the year, but achieved production growth in the third and fourth quarters, which we expect will be the trend in 2011 and beyond. The decrease in production in 2010 was a result of our conservative capital spending program in 2009 due to the unstable financial and commodity markets. Despite the decrease in production, our natural gas, NGL and crude oil sales revenue increased by $38.4 million due to improved pricing and our initiatives to increase crude oil and NGL production as a percentage of total production. The increase in crude oil and NGL production was the result of our increased investment in organic growth, primarily in our liquid-rich Wattenberg Field, and our more recent acquisitions in liquid-rich acreage in the Permian Basin. Our total 2010 revenues were also favorably impacted by realized derivative gains related to natural gas and crude oil sales of $47.1 million, which effectively resulted in a net realized price of $6.92 per Mcfe. +We closed 2010 with available liquidity of $356.9 million compared to $238.2 million at the end of 2009. Available liquidity is comprised of cash, cash equivalents and funds available under our credit facility. Capital markets strengthened during 2010 and as such, in November 2010, we recognized an opportunity to access the markets and did so through the sale of equity and the issuance of convertible debt, raising $247.5 million in capital. With our strong liquidity position, 2011 will be a year of increased capital spending, focused on organic growth in the liquid-rich areas of our Wattenberg Field and the Permian Basin along with the proposed acquisitions of our affiliated partnerships. We believe that, combined with our investment in 2010, our capital budget will grow our production from continuing operations by 19% in 2011, excluding any future acquisitions, while increasing the liquids portion of our production as a percentage of our total production and thereby benefiting from the crude oil to natural gas price differential. +Results of Operations +Summary Operating Results +The following table presents selected information regarding our operating results from continuing operations. Prior to 2010, NGLs were included in natural gas, which impacts the comparability for 2010 to 2009 and 2008. +30 +Year Ended December 31, +Change +2010 +2009 +2008 +2010-2009 +2009-2008 +(dollars in thousands, except per unit data) +Production (1) +Natural gas (MMcf) +26,387.5 +34,089.6 +30,101.1 +(22.6 +)% +13.3 +% +Crude oil (MBbls) +1,265.3 +1,244.0 +1,135.8 +1.7 +% +9.5 +% +NGLs (MBbls) +601.2 +— +— +* +* +Natural gas equivalent (MMcfe) (2) +37,586.6 +41,553.4 +36,915.6 +(9.5 +)% +12.6 +% +Average MMcfe per day +103.0 +113.8 +100.9 +(9.5 +)% +12.9 +% +Natural Gas, NGL and Crude Oil Sales +Natural gas +$ +95,147 +$ +105,449 +$ +207,086 +(9.8 +)% +(49.1 +)% +Crude oil +93,670 +68,499 +101,806 +36.7 +% +(32.7 +)% +NGLs +24,079 +— +— +* +* +Provision for underpayment of natural gas sales +(3,252 +) +(2,706 +) +(4,025 +) +20.2 +% +(32.8 +)% +Total natural gas, NGL and crude oil sales +$ +209,644 +$ +171,242 +$ +304,867 +22.4 +% +(43.8 +)% +Realized Gain (Loss) on Derivatives, net (3) +Natural gas +$ +40,024 +$ +89,464 +$ +12,632 +(55.3 +)% +* +Crude oil +7,071 +17,881 +(3,145 +) +(60.5 +)% +* +Total realized gain on derivatives, net +$ +47,095 +$ +107,345 +$ +9,487 +(56.1 +)% +* +Average Sales Price (excluding gain/loss on derivatives) +Natural gas (per Mcf) +$ +3.61 +$ +3.09 +$ +6.88 +16.8 +% +(55.1 +)% +Crude oil (per Bbl) +74.03 +55.07 +89.64 +34.4 +% +(38.6 +)% +NGLs (per Bbl) +40.05 +— +— +* +* +Natural gas equivalent (per Mcfe) +5.67 +4.19 +8.37 +35.3 +% +(49.9 +)% +Average Sales Price (including gain/loss on derivatives) +Natural gas (per Mcf) +$ +5.12 +$ +5.72 +$ +7.30 +(10.4 +)% +(21.7 +)% +Crude oil (per Bbl) +79.62 +69.44 +86.86 +14.7 +% +(20.1 +)% +NGLs (per Bbl) +40.05 +— +— +* +* +Natural gas equivalent (per Mcfe) +6.92 +6.77 +8.62 +2.2 +% +(21.5 +)% +Average Lifting Cost (per Mcfe) (4) +$ +1.11 +$ +0.81 +$ +1.08 +37.0 +% +(25.0 +)% +Natural Gas Marketing (5) +$ +1,056 +$ +1,977 +$ +942 +(46.6 +)% +109.9 +% +Other Costs and Expenses +Exploration expense +$ +20,266 +$ +18,177 +$ +31,783 +11.5 +% +(42.8 +)% +Impairment of proved natural gas and crude oil properties +— +926 +7,579 +(100.0 +)% +(87.8 +)% +General and administrative expense +42,188 +53,985 +37,715 +(21.9 +)% +43.1 +% +Depreciation, depletion and amortization +109,243 +126,755 +101,443 +(13.8 +)% +25.0 +% +Interest Expense +$ +33,250 +$ +37,208 +$ +28,132 +(10.6 +)% +32.3 +% +* Percentage change is not meaningful or equal to or greater than 300%. +Amounts may not recalculate due to rounding. +______________ +(1) +Production is net and determined by multiplying the gross production volume of properties in which we have an interest by the percentage interest we own. +(2) +Six Mcf of natural gas equals one Bbl of crude oil or NGL. +(3) +Represents realized derivative gains and losses related to natural gas and crude oil sales segment, which do not include realized derivative gains and losses related to natural gas marketing. +(4) +Represents lease operating expenses, exclusive of production taxes, on a per unit basis. +(5) +Represents sales from natural gas marketing, net of costs of natural gas marketing, including realized and unrealized derivative gains and losses related to natural gas marketing activities. +31 +Natural Gas, NGL and Crude Oil Sales +The following tables present natural gas, NGL and crude oil production and average sales price by area. Prior to 2010, NGLs were included in natural gas, which impacts the comparability for 2010 to 2009 and 2008. +Year Ended December 31, +Change +Production +2010 +2009 +2008 +2010-2009 +2009-2008 +Natural gas (MMcf) +Rocky Mountain Region +23,650.8 +29,957.4 +26,087.8 +(21.1 +)% +14.8 +% +Permian Basin +148.5 +— +— +* +* +Appalachian Basin (1) +2,526.0 +4,010.5 +3,902.2 +(37.0 +)% +2.8 +% +Other +62.2 +121.7 +111.1 +(48.9 +)% +9.5 +% +Total +26,387.5 +34,089.6 +30,101.1 +(22.6 +)% +13.3 +% +Crude oil (MBbls) +Rocky Mountain Region +1,224.9 +1,233.3 +1,127.9 +(0.7 +)% +9.3 +% +Permian Basin +34.0 +— +— +* +* +Appalachian Basin (1) +5.9 +9.6 +6.6 +(38.5 +)% +45.5 +% +Other +0.5 +1.1 +1.3 +(54.5 +)% +(15.4 +)% +Total +1,265.3 +1,244.0 +1,135.8 +1.7 +% +9.5 +% +NGLs (MBbls) +Rocky Mountain Region +561.1 +— +— +* +* +Permian Basin +31.6 +— +— +* +* +Other +8.5 +— +— +* +* +Total +601.2 +— +— +* +* +Natural gas equivalent (MMcfe) +Rocky Mountain Region +34,367.2 +37,357.0 +32,855.1 +(8.0 +)% +13.7 +% +Permian Basin +541.7 +— +— +* +* +Appalachian Basin (1) +2,561.4 +4,068.1 +3,941.9 +(37.0 +)% +3.2 +% +Other +116.3 +128.3 +118.6 +(9.4 +)% +8.2 +% +Total +37,586.6 +41,553.4 +36,915.6 +(9.5 +)% +12.6 +% +* Percentage change is not meaningful or equal to or greater than 300%. +Amounts may not recalculate due to rounding. +__________ +(1) +For 2010, the decrease in production was primarily the result of our contribution of natural gas and crude oil properties to PDCM. Effective January 1, 2010, PDCM was deconsolidated and accounted for in accordance with the proportionate consolidation method. See Note 1, Nature of Operations and Basis of Presentation, to our consolidated financial statements included in this report. +32 +Year Ended December 31, +Average Sales Price +Change +(excluding gain/loss on derivatives) +2010 +2009 +2008 +2010-2009 +2009-2008 +Natural gas (per Mcf) +Rocky Mountain Region +$ +3.52 +$ +2.97 +$ +6.53 +18.5 +% +(54.5 +)% +Permian Basin +3.54 +— +— +* +* +Appalachian Basin +4.44 +4.00 +9.21 +11.0 +% +(56.6 +)% +Other +2.49 +2.40 +7.21 +3.8 +% +(66.7 +)% +Weighted average price +3.61 +3.09 +6.88 +16.8 +% +(55.1 +)% +Crude oil (per Bbl) +Rocky Mountain Region +$ +73.95 +$ +55.06 +$ +89.63 +34.3 +% +(38.6 +)% +Permian Basin +76.56 +— +— +* +* +Appalachian Basin +77.10 +57.24 +88.80 +34.7 +% +(35.5 +)% +Other +62.68 +40.62 +100.79 +54.3 +% +(59.7 +)% +Weighted average price +74.03 +55.07 +89.64 +34.4 +% +(38.6 +)% +NGLs (per Bbl) +Rocky Mountain Region +$ +39.56 +$ +— +$ +— +* +* +Permian Basin +47.20 +— +— +* +* +Other +46.29 +— +— +* +* +Weighted average price +40.05 +— +— +* +* +Natural gas equivalent (per Mcfe) +Rocky Mountain Region +$ +5.71 +$ +4.20 +$ +8.26 +36.0 +% +(49.2 +)% +Permian Basin +8.52 +— +— +* +* +Appalachian Basin +4.55 +4.08 +9.27 +11.5 +% +(56.0 +)% +Other +4.99 +2.62 +7.81 +90.5 +% +(66.5 +)% +Weighted average price +5.67 +4.19 +8.37 +35.3 +% +(49.9 +)% +* Percentage change is not meaningful or equal to or greater than 300%. +Amounts may not recalculate due to rounding. +Natural gas, NGL and crude oil sales revenue in 2010 increased $38.9 million, excluding the provision for underpayment of natural gas sales, compared to 2009. Approximately $61.6 million of the increase was due to pricing, offset in part by decreased production, which reduced natural gas and oil sales by $22.7 million. The 2010 decrease in production was directly attributable to our decision to reduce our capital expenditures for new wells drilled in 2009 due to the decline in commodity prices from 2008 to 2009 and the continued significant uncertainty in the financial and commodity markets. The decrease in production was offset in part by our decision to report NGLs separately from natural gas volumes as these amounts are expected to become more significant as we concentrate our drilling and acquisition spending toward more liquid rich resources as well as to enhance comparability among our peers, which resulted in the recognition of approximately 1.9 Bcfe of additional production. As market conditions showed signs of improvement, we cautiously increased our capital spending. During the third quarter of 2010, we began to experience the first increase in our quarterly production rate since the third quarter of 2009. Our production in 2009 increased compared to 2008 primarily as a result of our 2008 investment in new wells drilled. Although production increased in 2009, natural gas, NGL and crude oil sales revenue decreased by $134.9 million, excluding the provision for underpayment of natural gas sales, compared to 2008, primarily due to depressed natural gas and crude oil pricing in 2009. The lower commodity prices contributed $172.1 million to the total decrease in natural gas, NGL and crude oil sales revenues, which was offset in part by the increase in production, contributing $37.2 million. The effects of the decrease in natural gas and crude oil pricing was significantly reduced by realized derivative gains in 2009 of $107.3 million. See Commodity Price Risk Management, Net discussion below. At December 31, 2010, our production exit rate was 109 MMcfe/day compared to 98 MMcfe/day at December 31, 2009, and 115 MMcfe/day at December 31, 2008. +Natural Gas and Crude Oil Pricing. Our results of operations depend upon many factors, particularly the price of natural gas and crude oil and our ability to market our production effectively. Natural gas and crude oil prices are among the most volatile of all commodity prices. These price variations have a material impact on our financial results. Natural gas prices vary by region and locality, depending upon the distance to markets, the availability of pipeline capacity and the supply and demand relationships in that region or locality. This can be especially true in the Rocky Mountain Region. The combination of increased drilling activity and the lack of local markets has resulted in local market oversupply situations from time to time. Like most producers in the region, we rely on major interstate pipeline companies to construct these pipelines to increase capacity, rendering the timing and availability of these facilities beyond our control. Crude oil pricing is predominately driven by the physical market, supply and demand, the financial markets and politics. +33 +The price we receive for our natural gas produced in the Rocky Mountain Region is based on a market basket of prices, which generally includes natural gas sold at, near or below CIG prices as well as other nearby region prices. The CIG Index, and other indices for production delivered to other Rocky Mountain pipelines, has historically been less than the price received for natural gas produced in the eastern regions, which is NYMEX-based. This negative differential has narrowed over the last few years and is lower than historical variances. The negative differential between NYMEX and CIG averaged $0.47, $0.92 and $2.80 for 2010, 2009 and 2008, respectively. +Production Costs. Production costs include our lease operating expenses, production taxes, the cost to operate wells and pipelines and certain production and engineering staff related overhead costs. +Year Ended December 31, +2010 +2009 +2008 +(in thousands) +Lease operating expenses +$ +41,784 +$ +33,807 +$ +39,726 +Production taxes +12,067 +8,834 +17,438 +Costs of well operations and pipeline services +7,631 +6,771 +5,501 +Overhead and other production expenses +5,335 +12,691 +12,534 +Total production costs +$ +66,817 +$ +62,103 +$ +75,199 +Lease operating expenses. Lifting costs per Mcfe were $1.11, $0.81 and $1.08 for 2010, 2009 and 2008, respectively. The increase per Mcfe in 2010 from 2009 was in part due to the 9.5% decrease in production volumes compared to volumes produced in 2009, resulting in the fixed portion of our production costs being allocated to a declining volume. A large component of the increase in our 2010 lease operating expenses were well workovers, which include an increase in tubing and casing repairs of $4.7 million and environmental remediation charges of $2.7 million. The decrease per Mcfe in 2009 from 2008 was primarily due to lower third party costs from service providers as a result of pressure by us to reduce costs as natural gas and crude oil prices deteriorated, our own cost reduction initiatives, and increased production, which allows us to spread the fixed portion of our production costs over the increased volume. +Production taxes. Production taxes fluctuate with natural gas, NGL and crude oil sales. The $3.2 million or 36.6% increase in production taxes for 2010 compared to 2009 was primarily related to the 22.4% increase in sales revenues and an increase in ad valorem tax rates for certain Colorado counties. The $8.6 million or 49.3% decrease in 2009 compared to 2008 was directly related to the 43.8% decrease in natural gas and crude oil sales along with a reduction of ad valorem tax rates for certain counties and an increase in the number of Colorado wells exempt from severance taxes due to their re-characterization as stripper wells. +Cost of well operations and pipeline services. The increases in costs of well operations and pipeline services for 2010 and 2009 compared to 2008 were the result of costs related to pipeline systems and compressor maintenance projects, with 2009 being offset in part by lower field services costs. +Overhead and other production expenses. Overhead and other production expenses decreased in 2010 compared to 2009 primarily due to the deconsolidation of PDCM with the remaining decrease resulting from reductions in various other expenses, including pipeline and compressor maintenance as well as a $2.7 million accrual recognized in 2009 for a firm transportation volume shortfall in our Piceance Basin. The slight decrease in 2009 from 2008 was primarily due to lower cost of field services, including vehicles, lower rates from third parties and less work and services being performed in this low commodity price environment, offset in part by a $2.7 million accrual for a firm transportation shortfall in the Piceance Basin. +Commodity Price Risk Management, Net +Commodity price risk management, net, includes realized gains and losses and unrealized changes in the fair value of derivative instruments related to our natural gas and crude oil production. Commodity price risk management, net, does not include derivative transactions related to our natural gas marketing, which are included in sales from and cost of natural gas marketing. See Note 3, Fair Value of Financial Instruments , and Note 4, Derivative Financial Instruments , to our consolidated financial statements included in this report for additional details of our derivative financial instruments. +34 +The following table presents the realized and unrealized derivative gains and losses included in commodity price risk management, net. +Year Ended December 31, +2010 +2009 +2008 +(in thousands) +Commodity price risk management gain (loss), net: +Realized gains (losses): +Natural gas +$ +40,024 +$ +89,464 +$ +12,632 +Crude oil +7,071 +17,881 +(3,145 +) +Total realized gains, net +47,095 +107,345 +9,487 +Unrealized gains (losses): +Reclassification of realized (gains) losses included in prior periods unrealized +(20,148 +) +(84,655 +) +549 +Unrealized gains (losses) for the period +32,944 +(32,743 +) +117,802 +Total unrealized gains (losses), net +12,796 +(117,398 +) +118,351 +Total commodity price risk management gain (loss), net +$ +59,891 +$ +(10,053 +) +$ +127,838 +Realized gains recognized in 2010 are a result of lower natural gas and crude oil spot prices at settlement compared to the respective strike price, offset in part by a $12.1 million realized loss due to the negative basis differential between NYMEX and CIG being narrower than the strike price of our derivative position. During 2010, we recorded unrealized gains of $47.3 million on our natural gas positions offset in part by unrealized losses of $10.6 million on our crude oil positions and $3.8 million on our CIG basis swaps as the forward basis differential between NYMEX and CIG had continued to narrow. +During 2009, realized gains recognized were the result of lower natural gas and crude oil spot prices at settlement compared to the respective strike price. We recorded unrealized losses on our CIG basis swaps of $33.9 million as the forward basis differential between NYMEX and CIG had continued to narrow along with unrealized losses of $15 million on our crude oil positions, offset by unrealized gains of $16.2 million on our natural gas positions. +During the first half of 2008, we experienced both realized and unrealized derivative losses as natural gas and crude oil prices were at or near record prices. During the second half of the year, due to the tumbling commodity prices, we had both significant realized and unrealized derivative gains. The 2008 unrealized gain includes a gain on our natural gas and crude oil positions of $120.5 million and an unrealized loss on our CIG basis swaps of $2.7 million. +We use various derivative instruments to manage fluctuations in natural gas and crude oil prices. We have in place a variety of floors, collars, fixed-price swaps and basis swaps on a portion of our estimated natural gas and crude oil production. Because we sell all of our physical natural gas and crude oil at similar prices to the indexes inherent in our derivative instruments, we ultimately realize a price related to our collars of no less than the floor and no more than the ceiling and, for our commodity swaps, we ultimately realize the fixed price related to our swaps. See Note 4, Derivative Financial Instruments , to our consolidated financial statements included in this report and Item 7A, Quantitative and Qualitative Disclosures About Market Risk , for a discussion of how each derivative type impacts our cash flows and a detailed presentation of our derivative positions as of December 31, 2010. +Natural Gas Marketing +Fluctuations in our natural gas marketing's income contribution are primarily due to fluctuations in commodity prices and realized and unrealized, mark-to-market adjustments, gains and losses on open derivative positions, and, to a lesser extent, volumes sold and purchased. +Derivative instruments related to natural gas marketing include both physical and cash-settled derivatives. We offer fixed-price derivative contracts for the purchase or sale of physical gas and enter into cash-settled derivative positions with counterparties in order to offset those same physical positions. See Note 4, Derivative Financial Instruments , to our consolidated financial statements included in this report and Item 7A, Quantitative and Qualitative Disclosures About Market Risk , for a discussion of how each derivative type impacts our cash flows and detailed presentation of our derivative positions as of December 31, 2010. +35 +Other Costs and Expenses +Exploration Expense +The following table presents the major components of exploration expense. +Year Ended December 31, +2010 +2009 +2008 +(in thousands) +Impairment of individually significant unproved properties +$ +1,477 +$ +982 +$ +9,165 +Amortization of individually insignificant unproved properties +5,004 +3,126 +3,633 +Exploratory dry hole costs +4,199 +1,059 +7,675 +Geological and geophysical costs +2,367 +1,788 +2,121 +Operating, personnel and other +7,219 +11,222 +9,189 +Total exploration expense +$ +20,266 +$ +18,177 +$ +31,783 +Impairment of individually significant unproved properties . In 2010, the impairment expense relates primarily to a leasehold abandoned in the Pennsylvania portion of the Appalachian Basin. In 2008, $7.3 million was related to unproved properties in the Fort Worth Basin. +Amortization of individually insignificant unproved properties . The increase in amortization of individually insignificant unproved properties in 2010 was primarily due to our lack of drilling in the NECO area and the Pennsylvania portion of the Appalachian Basin. +Exploratory dry hole costs . In 2010, exploratory dry hole costs includes the fracturing and testing of several exploratory zones on a well drilled in the Piceance Basin and a crude oil well drilled in the NECO area. In 2008, the exploratory dry hole costs relates primarily to a well in each of New York and Colorado. +Operating, personnel and other . Included in operating, personnel and other is $3.7 million for demobilization of our drilling operations in the Piceance Basin during 2009. +Impairment of Proved Natural Gas and Crude Oil Properties +In 2008, we recognized an impairment loss of $7.5 million on our proved natural gas and crude oil properties in the Fort Worth Basin. +General and Administrative Expense +General and administrative expense decreased $11.8 million in 2010 compared to 2009. The decrease was primarily related to charges recorded during the prior year period: $7.9 million related to the formation of PDCM, $2.9 million related to a separation agreement with a former executive vice president, $1.5 million related to the expensing of previously capitalized 2008 acquisition costs pursuant to the adoption of a new accounting standard and $1.3 million related to corporate relocation costs. The 2010 decrease was offset in part by an increase in payroll and payroll related expenses during 2010. +General and administrative expense for 2009 increased $16.3 million compared to 2008. The increase was primarily related to the formation, acquisition and relocation costs discussed above as well as an increase in staffing and payroll benefits, including stock-based compensation of $3.7 million. +Depreciation, Depletion and Amortization +Natural gas and crude oil properties. DD&A expense related to natural gas and crude oil properties is directly related to proved reserves and production volumes. DD&A expense is primarily based upon year-end proved developed producing reserves. For 2008 and prior, these reserves were valued based on the price of natural gas and crude oil as of December 31 for the respective year. Pursuant to the adoption of the SEC's new reserve estimation and reporting requirements, our 2009 reserve estimation changed from a December 31 single day pricing to a 12-month average of the first day of the month price for each month in the period. If prices increase, as they did from December 31, 2009, to December 31, 2010, the estimated volumes of proved reserves will increase, resulting in decreases in the rate of DD&A per unit of production. If prices decrease, as they did from December 31, 2008, to December 31, 2009, the estimated volumes of proved reserves will decrease, resulting in an increase in the rate of DD&A per unit of production. +36 +The following table presents our DD&A rates for natural gas and crude oil properties by area. +Year Ended December 31, +2010 +2009 +2008 +(per Mcfe) +Rocky Mountain Region: +Wattenberg Field (1) +$ +3.08 +$ +3.81 +$ +3.47 +Grand Valley Field +2.49 +2.35 +2.04 +Weighted average +2.72 +2.92 +2.62 +Permian Basin +2.12 +— +— +Appalachian Basin +2.57 +2.06 +1.55 +Total weighted average +2.70 +2.85 +2.54 +__________ +(1) +Although the Wattenberg Field development costs and DD&A rates are higher than the other fields, the relative value of its crude oil production currently more than offsets this cost difference. The Wattenberg Field has produced volumes in excess of 90% of our total crude oil production in each of the years in the three-year period ended December 31, 2010. +Non-natural gas and crude oil properties. Depreciation expense for non-natural gas and crude oil properties was $7.5 million for 2010 compared to $8.1 million for 2009 and $7.6 million for 2008. +Non-Operating Income/Expense +Interest Expense. The decrease in interest expense in 2010 compared to 2009 is primarily related to the lower average outstanding balances on our credit facility. The increase in interest expense in 2009 compared to 2008 was primarily due to significantly higher average outstanding balances on our credit facility offset in part by lower average interest rates in our bank credit facility. The average long-term debt in 2010 was $286.1 million compared to $392 million in 2009 and $275.9 million in 2008. Interest expense is net of capitalized interest. Interest costs capitalized in 2010, 2009 and 2008 were $0.3 million, $0.8 million and $2.6 million, respectively. We have historically utilized our daily cash balances to reduce our line of credit borrowings, thereby lowering our interest costs and interest income. +Provision/Benefit for Income Taxes +The effective tax rate ("rate") related to income from continuing operations for 2010 of 14.7% is lower than the statutory federal rate of 35% primarily due to the tax benefit associated with the deduction for percentage depletion as well as the $1.7 million discrete tax benefit due to our deferred rate change. The 2009 rate of 36% is a benefit on the loss from continuing operations which was increased by the benefit for current state losses and offset by nondeductible expenditures related to the formation of PDCM. The 2008 rate of 35.1% on income from continuing operations was impacted primarily by state income tax expense, offset by a benefit associated with the implementation of state tax planning strategies. Excluding the effect of discrete items, our 2010, 2009 and 2008 rate was 32.7%, 36.2% and 37.4%, respectively, with 2010 and 2008 representing provision on income and 2009 representing benefit on loss. +Beginning with our 2010 tax year, we were accepted into and have agreed to participate in the IRS Compliance Assurance Process ("CAP") program. As part of this program, we have agreed to an accelerated timeline for the IRS examination of our 2007, 2008 and 2009 tax years. This examination is expected to be completed during the second quarter of 2011. We have accepted an offer for continued participation in the IRS CAP program for our 2011 tax year. +Discontinued Operations +North Dakota . During the fourth quarter of 2010, we developed a plan to divest and began marketing for sale our North Dakota assets. In December 2010, we executed a letter of intent with an unrelated third party, which provides for the sale of 100% of our North Dakota assets. In February 2011, we executed a purchase and sale agreement with the same unrelated third party and expect the transaction to close in March 2011. The operating results related to these assets were immaterial to the financial statements with the following exception. In 2008, we recognized impairment losses on our proved natural gas and crude oil properties in North Dakota of $5.3 million, consisting of $3 million in our Bakken Field and $2.3 million in our Nesson Field. See Note 13, Assets Held for Sale, Divestiture and Discontinued Operations , to our consolidated financial statements included in this report for additional information regarding the divestiture of our North Dakota assets. +Michigan. In July 2010, we completed the sale of our Michigan assets. Operating results related to these assets were immaterial to the financial statements with the following exception. In June 2010, in conjunction with our decision to divest our Michigan assets, we recorded a related pre-tax impairment charge of $4.7 million. See Note 2, Summary of Significant Accounting Polices, Properties and Equipment - Proved Property Impairment , and Note 13, Assets Held for Sale, Divestiture and Discontinued Operations , to our consolidated financial statements included in this report for additional information regarding the divestiture of our Michigan assets. +37 +Natural Gas and Crude Oil Well Drilling Operations. We offered our last partnership drilling program in 2007. Since then, we have not had significant revenue from this segment of our operations. As of June 2009, we had concluded all previous commitments related to partnership well drilling and completion activities and reported our natural gas and crude oil well drilling activities as discontinued operations. +Net Income (Loss) Attributable to Shareholders/Adjusted Net Income (Loss) Attributable to Shareholders +Net income attributable to shareholders for 2010 was $6.2 million compared to a net loss of $79.3 million for 2009 and net income of $113.3 million for 2008. Adjusted net income attributable to shareholders, a non-GAAP financial measure, for 2010 was $0.4 million compared to an adjusted net loss of $5.7 million for 2009 and an adjusted net income of $43.1 million for 2008. The year-over-year changes in net income (loss) attributable to shareholders are discussed above. These same reasons for change similarly impacted adjusted net income (loss) attributable to shareholders, with the exception of the unrealized derivative gains and losses on derivatives, adjusted for taxes. Adjusted net income (loss) attributable to shareholders excludes the impact of a tax adjusted unrealized derivative gain of $7.8 million for 2010, a tax adjusted unrealized loss of $71.9 million for 2009 and a tax adjusted unrealized gain of $72.7 million for 2008. See Reconciliation of Non-GAAP Financial Measures , below, for a more detailed discussion of this non-GAAP financial measure. +Financial Condition, Liquidity and Capital Resources +Historically, our primary sources of liquidity have been cash flows provided by operating activities and our bank credit facility. More recently, as market conditions have permitted, we have utilized the debt and equity markets and engaged in asset monetization transactions as sources of financing. +Our primary source of cash flows provided by operations is the sale of natural gas, NGL and crude oil. Fluctuations in our operating cash flow are substantially driven by commodity prices and changes in our production volumes. Commodity prices have historically been volatile and we manage this volatility through our derivative program, which has also historically been a source of cash from operations. We enter into commodity derivative instruments with maturities of no greater than five years from the date of the instrument. For instruments that mature in two years or less, our debt covenants limit our holdings to 80% of our expected future production on total proved reserves (PDPs, PDNPs and PUDs). For instruments that mature greater than two years but no more than our designated maximum maturity, our debt covenants limit our holdings to 80% of our expected future production on PDPs. Therefore, we may still have significant fluctuations in our cash flows provided by operating activities due to the remaining non-hedged portion. +Our working capital fluctuates for various reasons, including, but not limited to, changes in the fair value of our commodity derivative instruments and due to our practice of utilizing excess cash to reduce the outstanding borrowings under our credit facility. At December 31, 2010, we had a working capital surplus of $16.2 million compared to $32.9 million at December 31, 2009. +We began 2011 with cash and cash equivalents of $54.4 million and availability under our credit facility of $302.5 million, for a total liquidity position of $356.9 million compared to $238.2 million at the beginning of 2010. The increase in liquidity of $118.7 million, or 49.8%, was primarily due to the net proceeds of $236.7 million received in November 2010 through the sale of equity and the issuance of convertible senior notes, as well as cash flows provided by operating activities of $151.8 million and the increase in our credit facility borrowing base of $16.2 million from $305 million. These increases in available liquidity were offset in part by an increase in capital expenditures of $19.7 million, an $80 million pay down of our corporate credit facility and the acquisition of natural gas and crude oil properties totaling $158.1 million. With our current liquidity position and expected cash flow from operations, we believe that we have sufficient capital for operations and our planned uses of capital through 2011. +Capital Expenditures +We establish a capital plan each calendar year based on our development opportunities, liquidity position and the expected cash flows provided by operating activities for that year. We may revise our capital plan during the year as a result of acquisitions, drilling results, commodity prices, changes in our borrowing capacity and/or significant changes in cash flows. In January 2011, our Board of Directors approved our 2011 capital plan of $233 million, exclusive of the potential acquisition of the 2005 partnerships and any other future acquisition, which are expected to be provided through the utilization of our corporate credit facility. The plan provides for $205 million in developmental drilling, including recompletions and refractures, with the remaining $28 million for exploration, leasing and other capital needs. We believe, based on the current commodity price environment and our estimated 2011 production of 44.9 Bcfe, an increase of approximately 19% over 2010 production from continuing operations due to the increase in our 2010 drilling program compared to that of 2009, our cash flows provided by operating activities will fund the majority of our 2011 capital plan. Because natural gas and crude oil produced from our existing properties declines rapidly in the first two years of production, in order to grow our production, we need to continue to commit significant amounts of capital in 2011 and beyond. If capital is not available or is constrained in the future, we will be limited to our cash flows from operations and liquidity under our credit facility as the sources for funding our capital expenditures. We would not be able to maintain our current level of natural gas and crude oil production and cash flows provided by operating activities if capital markets and commodity prices were to become depressed and/or the borrowing base on our credit facility was reduced. The recurrence of such an event may result in our election to defer a substantial portion of our planned capital expenditures for 2011 and beyond and could have a material negative impact on our operations in the future. +38 +Financing Activities +See Note 8, Long-Term Debt , and Note 12, Common Stock , to our consolidated financial statements in this report for detailed discussions of our November 2010 issuance of convertible senior notes and sale of equity, respectively. We have experienced no impediments in our ability to access borrowings under our current bank credit facility or the capital markets, as demonstrated by our November 2010 capital market transactions. We continue to monitor market events and circumstances and their potential impacts on each of the lenders that comprise our bank credit facility. Our $321.2 million bank credit facility borrowing base is subject to size redeterminations each May and November based upon a quantification of our proved reserves at each December 31st and June 30th, respectively. A commodity price deck reflective of the current and future commodity pricing environment is utilized by our lenders to quantify our reserve reports and determine the underlying borrowing base. Our next scheduled redetermination will be in May 2011. While we have continued to add producing reserves through our drilling operations since our last redetermination, we believe a significant decrease in commodity prices could have a negative impact on our future borrowing base redeterminations. +We have a shelf registration statement on Form S-3 with the SEC, filed in November 2008, and declared effective by the SEC in January 2009. The shelf provides for an aggregate of $500 million, through the potential sale of debt securities, common stock or preferred stock, either separately or represented by depository shares, warrants and purchase contracts, as well as units that may include any of these securities or securities of other entities. The shelf registration statement is intended to allow us to be proactive in our ability to raise capital should the need arise, and to have the flexibility to raise such funds in one or more offerings should we perceive the market conditions to be favorable. As of December 31, 2010, we have $315.8 million available on our shelf from which we may utilize to raise future capital. +We are subject to quarterly financial debt covenants on our bank credit facility. Currently, our key credit facility debt covenants require that we maintain: 1) total debt of less than 4.25 times earnings before interest, taxes, DD&A expense and capital expenditures ("EBITDAX") and 2) an adjusted working capital ratio of at least 1.0 to 1.0. Our adjusted working capital ratio is calculated by reducing our current assets and liabilities by any impact of recording the fair value of our natural gas and crude oil derivative instruments and adding our available borrowings on our bank credit facility to our current assets. The impact of any current portion of our debt is eliminated from the current liabilities, therefore any change in our available borrowings under our credit facility impacts our working capital ratio. We were in compliance with all debt covenants at December 31, 2010 , and expect to remain in compliance throughout the next year. +The indenture governing our senior notes contains customary representations and warranties as well as typical restrictive covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: (a) incur additional debt, (b) make certain investments or pay dividends or distributions on our capital stock or purchase or redeem or retire capital stock, (c) sell assets, including capital stock of our restricted subsidiaries, (d) pay dividends or other payments by restricted subsidiaries, (e) create liens that secure debt, (f) enter into transactions with affiliates and (g) merge or consolidate with another company. Additionally, with regard to our 12% senior notes, we are subject to two incurrence covenants: 1) EBITDAX of at least two times interest expense and 2) total debt of less than 4.0 times EBITDAX. We were in compliance with all covenants at December 31, 2010, and expect to remain in compliance throughout the next year. +See Part II, Item 7A, Quantitative and Qualitative Disclosures about Market Risk , for our discussion of credit risk. +Cash Flows +Operating Activities. Our net cash flow provided by operating activities is primarily impacted by commodity prices, production volumes, realized gains and losses from our derivative positions, operating costs and general and administrative expenses. Cash flows provided by operating activities increased in 2010 and 2009 compared to the respective prior year. In 2010, the increase was primarily due to the increase in natural gas, NGL and crude oil sales and the income tax refund of $25.9 million from our 2009 NOL carry-back received during the first half of 2010, offset by a decrease in realized derivative gains related to natural gas and crude oil sales of $60.2 million. In 2009, the increase was primarily due to the increase in realized gains from derivatives related to natural gas and crude oil sales of $97.9 million, the decrease in production costs of $13.1 million, offset by the decrease in natural gas, NGL and crude oil sales of $133.6 million and an increase in general and administrative costs of $16.3 million. The remaining changes in cash flows provided by operating activities were primarily due to changes in our assets and liabilities related to the timing of cash payments and receipts. The key components for the changes in our cash flows provided by operating activities are described in more detail in our Results of Operations above. +Adjusted cash flows from operations and adjusted EBITDA decreased in 2010 and 2009 compared to the respective prior year. These decreases were primarily due to the same factors mentioned above for changes in cash flows provided by operating activities without regard to timing of cash payments and receipts of our assets and liabilities. See Reconciliation of Non-GAAP Financial Measures , below, for a more detailed discussion of these non-GAAP financial measures. +Investing Activities. Cash flows used in investing activities primarily consist of the acquisition, exploration and development of natural gas and crude oil properties net of dispositions of natural gas and crude oil properties. In 2009, based on unstable economic conditions existing early in the year and uncertainty as to when commodity and financial markets would recover to a perceived normal level, we reduced our planned 2009 capital expenditures to approximately 33% of our 2008 level, focusing our investment in the liquids-rich section of our Wattenberg Field. In 2010, as the economic condition showed signs of recovery, we increased our capital spending by $177.7 million, including acquisitions, over that in 2009. Approximately 51% of our investment spending was directed toward organic development and the remaining 49% going toward the acquisition of natural gas and crude oil properties. The monetization of our Michigan asset group provided cash of $22 million. See Part I, Operations - Drilling Activities , for additional details on our drilling activities. +39 +Financing Activities. Cash flows provided by financing activities in 2010 included gross proceeds of $132.5 million and $115 million from our November 2010 sale of equity and issuance of convertible debt, respectively. During 2010, our investing partner in PDCM contributed $35 million, of which our proportionate share was $20.1 million. This capital raise was offset in part by the net repayment of borrowings under our bank credit facility of $80 million. Cash flows used in financing activities in 2009 were primarily related to our efforts to manage our balance sheet during the unstable economic conditions existing in 2009 and the uncertainty as to when the commodity and financial markets would recover to a perceived normal level. As a result, our net borrowings of $159.6 million in 2008 shifted to a net repayment of borrowings of $114.5 million in 2009. In 2009, we raised $48.5 million in capital through an equity offering and monetized a portion of our Appalachian Basin assets, receiving $45 million as return of capital at the closing of the formation of PDCM. See Note 8, Long-Term Debt , Note 12, Common Stock , and Note 15, Noncontrolling Interest in Subsidiaries , to our consolidated financial statements included in this report for further discussion on our debt and equity offerings and the formation of our joint venture. +Contractual Obligations and Contingent Commitments +The table below presents our contractual obligations and contingent commitments as of December 31, 2010 . +Payments due by period +Less than +1-3 +3-5 +More than +Contractual Obligations and Contingent Commitments +Total +1 year +years +years +5 years +(in thousands) +Long-term liabilities reflected on the consolidated balance sheets (1) +Long-term debt (2) +$ +318,000 +$ +— +$ +— +$ +— +$ +318,000 +Derivative contracts (3) +53,465 +16,820 +36,645 +— +— +Derivative contracts - affiliated partnerships (4) +18,956 +6,845 +12,111 +— +— +Production tax liability +32,300 +16,226 +16,074 +— +— +Other liabilities (5) +9,844 +273 +3,669 +604 +5,298 +Asset retirement obligations +28,047 +250 +389 +779 +26,629 +460,612 +40,414 +68,888 +1,383 +349,927 +Commitments, contingencies and other arrangements (6) +Interest on long-term debt (7) +201,634 +30,035 +59,433 +58,999 +53,167 +Operating leases +8,813 +2,226 +3,597 +2,977 +13 +Rig commitment (8) +6,627 +3,693 +2,934 +— +— +Drilling commitment +1,004 +— +— +— +1,004 +Firm transportation and processing agreements (9) +178,961 +19,724 +45,654 +39,442 +74,141 +Other +500 +— +250 +250 +— +397,539 +55,678 +111,868 +101,668 +128,325 +Total +$ +858,151 +$ +96,092 +$ +180,756 +$ +103,051 +$ +478,252 +__________ +(1) +Table does not include deferred income tax liability to taxing authorities of $188 million, due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations. +(2) +Amount presented does not agree with the balance sheet in that it does not include $22.3 million in unamortized debt discount. See Note 8, Long-Term Debt, to our consolidated financial statements included in this report. +(3) +Represents our gross liability related to the fair value of derivative positions, including the fair value of derivative contracts we entered into on behalf of our affiliated partnerships as the managing general partner. We have a related receivable from the partnerships of $14.6 million. +(4) +Represents our affiliated partnerships' designated portion of the fair value of our gross derivative assets. +(5) +Includes funds held from revenue distribution to third party investors for plugging liabilities related to wells we operate and deferred officer compensation. +(6) +Table does not include the annual repurchase obligations to investing partners or termination benefits related to employment agreements with our executive officers, due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations. +(7) +Amounts presented include $20.1 million payable to the holders of our 3.25% convertible senior notes due 2016, $173.6 million to the holders of our 12% senior notes due 2018. Amounts also include $7.9 million payable to the participating banks of our revolving credit facility. As of December 31, 2010, there were no borrowings outstanding on our revolving bank credit facility; however, the $7.9 million represents amounts due on the unutilized commitment at a rate of 0.5% per annum plus a rate of 2.125% per annum related to our outstanding letter of credit. +(8) +Drilling rig commitment in the above table reflects our proportionate share of the maximum obligation for the services of one drilling rig in the Appalachian Basin. +(9) +Represents our gross commitment, including amounts for volumes transported or sold on behalf of our affiliated partnerships and other working interest owners. We will recognize in our financial statements our proportionate share based on our working interest. See Note 11, Commitments and Contingencies - Firm Transportation Agreements, to our consolidated financial statements included in this report. +As the managing general partner of 29 partnerships, we have liability for potential casualty losses in excess of the partnership assets and insurance. We believe that the casualty insurance coverage we and our subcontractors carry is adequate to meet this potential liability. +For information regarding our legal proceedings, see Note 11, Commitments and Contingencies – Litigation , to our consolidated +40 +financial statements included in this report. From time to time we are a party to various other legal proceedings in the ordinary course of business. We are not currently a party to any litigation that we believe would have a materially adverse effect on our business, financial condition, results of operations or liquidity. +Critical Accounting Policies and Estimates +We have identified the following policies as critical to business operations and the understanding of our results of operations. This is not a comprehensive list of all of the accounting policies. In many cases, the accounting treatment of a particular transaction is specifically dictated by accounting principles generally accepted in the U.S., with no need for our judgment in the application. There are also areas in which our judgment in selecting any available alternative would not produce a materially different result. However, certain of our accounting policies are particularly important to the portrayal of our financial position and results of operations and we may use significant judgment in the application; as a result, they are subject to an inherent degree of uncertainty. In applying those policies, we use our judgment to determine the appropriate assumptions to be used in the determination of certain estimates. Those estimates are based on historical experience, observation of trends in the industry, and information available from other outside sources, as appropriate. For a more detailed discussion on the application of these and other accounting policies, see Note 2, Summary of Significant Accounting Policies , to our consolidated financial statements included in this report. Our critical accounting policies and estimates are as follows: +Natural Gas and Crude Oil Properties. We account for our natural gas and crude oil properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and development dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves. +Annually, we engage independent petroleum engineers to prepare reserve and economic evaluations of all our properties on a well-by-well basis as of December 31. We adjust our natural gas and crude oil reserves for major acquisitions, new drilling and divestitures during the year as needed. The process of estimating and evaluating natural gas and crude oil reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur. Although every reasonable effort is made to ensure that reserve estimates reported represent our most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates over time. Because estimates of reserves significantly affect our DD&A expense, a change in our estimated reserves could have an effect on our net income. +Exploration costs, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized but charged to expense if the well is determined to be nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as the well has found a sufficient quantity of reserves to justify our completion as a producing well and we are making sufficient progress assessing our reserves and economic and operating viability. If an in-progress exploratory well is found to be unsuccessful prior to the issuance of the financial statements, the costs incurred, including costs for plugging, prior to the end of the reporting period are expensed to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the well is classified as "suspended well costs" until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time when we are able to make a final determination of a well’s productive status, the well is removed from the suspended well status and the proper accounting treatment is applied. +The acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense when expired, impaired or amortized. Unproved natural gas and crude oil properties with individually significant acquisition costs are periodically assessed, and any impairment in value is charged to exploration expense. The amount of impairment recognized on unproved properties which are not individually significant is determined by amortizing the costs of such properties within appropriate fields based on our historical experience, acquisition dates and average lease terms. The valuation of unproved properties is subjective and requires us to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual realizable values. +We assess our natural gas and crude oil properties for possible impairment by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which we reasonably estimate the commodity to be sold. The estimates of future prices may differ from current market prices of natural gas and crude oil. Any downward revisions in estimates to our reserve quantities, expectations of falling commodity prices or rising operating costs could result in a reduction in undiscounted future net cash flows and an impairment of our natural gas and crude oil properties. Although our cash flow estimates are based on the relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results. +41 +Consolidation and Accounting for Variable Interest Entities. Under applicable accounting guidance, a variable interest entity ("VIE") is consolidated by the entity's primary beneficiary. The primary beneficiary of a VIE has both the following characteristics: (1) the power to direct the activities of the VIE that most significantly impact the entity's economic performance and (2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. +In determining whether we are the primary beneficiary of the VIE, we consider a number of factors, including our ability to direct the activities that most significantly affect the entity's economic success and our contractual rights and responsibilities under the arrangement. These considerations impact the way we account for our existing joint venture relationship. Further, as certain events occur, we reconsider whether those events have caused us to become the primary beneficiary. The consolidation status of our VIE may change if the composition of the board of managers changes or we enter into new or modified contractual arrangements. A reconsideration event may also occur when we acquire new or additional interests in a VIE. +Natural Gas, NGL and Crude Oil Sales Revenue Recognition . Natural gas, NGL and crude oil sales are recognized when production is sold to a purchaser at a determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. We record sales revenue based on an estimate of the volumes delivered at prices tied to market indexes, adjusted based on agreed upon contract terms. We estimate our sales volumes based on company measured volume readings. We then adjust our natural gas, NGL and crude oil sales in subsequent periods based on the data received from our purchasers that reflects actual volumes received. We receive payment for sales from one to three months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded up to two months later. Historically, differences have been immaterial. +Fair Value of Financial Instruments. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as: +Level 1 – Quoted prices (unadjusted) in active markets for identical assets or liabilities. Included in Level 1 are our commodity derivative instruments for NYMEX-based natural gas swaps. +Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including (i) quoted prices for similar assets or liabilities in active markets, (ii) quoted prices for identical or similar assets or liabilities in inactive markets, (iii) inputs other than quoted prices that are observable for the asset or liability and (iv) inputs that are derived from observable market data by correlation or other means. +Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Included in Level 3 are our commodity derivative instruments for CIG and PEPL-based natural gas swaps, oil swaps, natural gas and oil collars, and physical sales and purchases and our natural gas basis protection derivative instruments. +Derivative Financial Instruments. We measure fair value of our derivatives based upon quoted market prices, where available. Our valuation determination includes: (1) identification of the inputs to the fair value methodology through the review of counterparty statements and other supporting documentation, (2) determination of the validity of the source of the inputs, (3) corroboration of the original source of inputs through access to multiple quotes, if available, or other information and (4) monitoring changes in valuation methods and assumptions. The methods described above may produce a fair value calculation that may not be indicative of future fair values. Our valuation determination also gives consideration to our nonperformance risk on our own liabilities as well as the credit standing of our counterparties. We primarily use three investment grade financial institutions as our counterparties to our derivative contracts. We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the impact of the nonperformance of our counterparties on the fair value of our derivative instruments is insignificant. Furthermore, while we believe these valuation methods are appropriate and consistent with that used by other market participants, the use of different methodologies, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value. +Deferred Income Tax Asset Valuation Allowance. Deferred income tax assets are recognized for deductible temporary differences, net operating loss carry-forwards and credit carry-forwards if it is more likely than not that the tax benefits will be realized. To the extent a deferred tax asset is not expected to be realized under the preceding criteria, we establish a valuation allowance. The factors which we consider in assessing whether we will realize the value of deferred income tax assets involve judgments and estimates of both amount and timing, which could differ from actual results, achieved in future periods. +42 +The judgments used in applying the above policies are based on our evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results may differ from those estimates. +Accounting for Acquisitions Using Purchase Accounting. We utilize the purchase method to account for acquisitions. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. The purchase price allocations are based on appraisals, discounted cash flows, quoted market prices and estimates by management. When appropriate, we review comparable purchases and sales of natural gas and crude oil properties within the same regions, and use that data as a basis for fair market value; for example, the amount a willing buyer and seller would enter into an exchange for such properties. +In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped, unproved natural gas and crude oil properties and other non-natural gas and crude oil properties. To estimate the fair values of these properties, we prepare estimates of natural gas and crude oil reserves. We estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired, and estimates of future operating and development costs, to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted average cost of capital rate is subject to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors. +We record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. +Recent Accounting Standards +See Note 2, Summary of Significant Accounting Policies - Recent Accounting Standards , to our consolidated financial statements included in this report. +Reconciliation of Non-GAAP Financial Measures +Adjusted cash flow from operations. We define adjusted cash flow from operations as the cash flow earned or incurred from operating activities without regard to the collection or payment of associated receivables or payables. We believe it is important to consider adjusted cash flow from operations as well as cash flow from operations, as we believe it often provides more transparency into what drives the changes in our operating trends, such as production, prices, operating costs, and related operational factors, without regard to whether the earned or incurred item was collected or paid during the period. We also use this measure because the collection of our receivables or payment of our obligations has not been a significant issue for our business, but merely a timing issue from one period to the next, with fluctuations generally caused by significant changes in commodity prices. See the Consolidated Statements of Cash Flows in this report. +Adjusted net income (loss) attributable to shareholders. We define adjusted net income (loss) attributable to shareholders as net income (loss) attributable to shareholders plus unrealized derivative losses, provisions for underpayment of natural gas sales, minus unrealized derivative gains, each adjusted for tax effect. We believe it is important to consider adjusted net income (loss) attributable to shareholders as well as net income (loss) attributable to shareholders. We believe it often provides more transparency into our operating trends, such as production, prices, operating costs, realized gains and losses from derivatives and related factors, without regard to changes in our net income (loss) attributable to shareholders from our mark-to-market adjustments resulting from unrealized gains and losses from derivatives. Additionally, other items, such as the provision for underpayment of natural gas sales, which are not indicative of future results, may be excluded to clearly identify operational trends. +Adjusted EBITDA. We define adjusted EBITDA as net income (loss) plus unrealized derivative loss, interest expense, net of interest income, income taxes, and depreciation, depletion and amortization for the period minus unrealized derivative gain. We believe adjusted EBITDA is relevant because it is a measure of cash available to fund our capital expenditures and service our debt and is a widely used industry metric which allows comparability of our results with our peers. +43 +The following table presents a reconciliation of each of our non-GAAP financial measures to its nearest GAAP measure. +Year Ended December 31, +2010 +2009 +2008 +(in thousands) +Adjusted cash flow from operations: +Adjusted cash flow from operations +$ +132,257 +$ +170,214 +$ +199,919 +Changes in assets and liabilities +19,556 +(26,319 +) +(60,818 +) +Net cash provided by operating activities +$ +151,813 +$ +143,895 +$ +139,101 +Adjusted net income (loss) attributable to shareholders: +Adjusted net income (loss) attributable to shareholders +$ +402 +$ +(5,735 +) +$ +43,102 +Unrealized gain (loss) on derivatives, net +12,625 +(116,623 +) +117,536 +Provision for underpayment of natural gas sales +(3,252 +) +(2,706 +) +(4,025 +) +Tax effect of above adjustments +(3,561 +) +45,787 +(43,304 +) +Net income (loss) attributable to shareholders +$ +6,214 +$ +(79,277 +) +$ +113,309 +Adjusted EBITDA: +Adjusted EBITDA +$ +138,268 +$ +159,668 +$ +189,413 +Unrealized gain (loss) on derivatives, net +12,625 +(116,623 +) +117,536 +Interest expense, net +(33,179 +) +(36,954 +) +(27,541 +) +Income tax benefit (expense) +(438 +) +45,636 +(61,459 +) +Depreciation, depletion and amortization +(111,062 +) +(131,004 +) +(104,640 +) +Net income (loss) attributable to shareholders +$ +6,214 +$ +(79,277 +) +$ +113,309 +44 +ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK +Market-Sensitive Instruments and Risk Management +We are exposed to market risks associated with interest rates, commodity prices and credit exposure. Management has established risk management processes to monitor and manage these market risks. +Interest Rate Risk +Changes in interest rates affect the amount of interest we earn on our cash, cash equivalents and restricted cash and the interest we pay on borrowings under our bank credit facility. All of our other long-term indebtedness have a fixed rate and, therefore, near-term changes in interest rates do not expose us to risk of earnings or cash flow loss; however, near-term changes in interest rates may affect the fair value of our fixed-rate debt. +As of December 31, 2010, our interest-bearing deposit accounts included money market accounts, certificates of deposit and checking and savings accounts with various banks. The amount of our interest-bearing cash and cash equivalents as of December 31, 2010, was $76.8 million with an average interest rate of 0.5%. The $76.8 million represents our aggregate bank balances, which includes checks issued and outstanding. Based on a sensitivity analysis of our interest bearing deposits as of December 31, 2010, it was estimated that if market interest rates were to increase or decrease by 1% in 2011, the impact on our annual interest income would be $0.8 million. +As of December 31, 2010, with the exception of our $18.7 million irrevocable standby letter of credit, we had no outstanding borrowings on our bank credit facility. Assuming our weighted average borrowing rate in 2010 averaged 1% higher (lower) in 2010, we estimate that our annual interest expense, would have increased (decreased) by approximately $0.7 million. +Commodity Price Risk +We are exposed to commodity price risk, the potential risk of loss from adverse changes in the market price of natural gas and crude oil commodities. We employ established policies and procedures to manage a portion of the risks associated with these market fluctuations using derivative instruments. These instruments allow us to predict with greater certainty the effective natural gas and crude oil prices to be received for our hedged production as it is produced. We believe that our established derivative policies and procedures are effective in achieving our risk management objectives. +45 +The following table presents our derivative positions (excluding the derivative positions designated to our affiliated partnerships) related to natural gas and crude oil sales in effect as of December 31, 2010 . +Floors +Collars +Fixed-Price Swaps +CIG +Basis Protection Swaps +Commodity/ Index/ +Maturity Period +Quantity +(Oil - MBbls) +Weighted +Average +Contract +Price +Quantity +(Gas - +BBtu (1) +Oil - MBbls) +Weighted Average +Contract Price +Quantity +(Gas - +BBtu (1) +Oil - MBbls) +Weighted +Average +Contract +Price +Quantity +(BBtu) (1) +Weighted +Average +Contract +Price +Fair Value +December 31, +2010 (2) +(in thousands) +Floors +Ceilings +Natural Gas +NYMEX +2011 +— +$ +— +866.2 +$ +6.03 +$ +9.37 +10,579.9 +$ +6.90 +8,916.5 +$ +(1.81 +) +$ +13,988 +2012 +— +— +4,831.4 +6.00 +8.27 +5,545.7 +7.04 +9,042.5 +(1.80 +) +4,501 +2013 +— +— +4,438.0 +6.10 +8.60 +4,659.7 +7.09 +8,156.4 +(1.80 +) +2,790 +CIG +2011 +— +— +1,128.5 +4.75 +9.45 +959.7 +5.81 +— +— +2,495 +2012 +— +— +— +— +— +— +— +— +— +— +2013 +— +— +— +— +— +— +— +— +— +— +PEPL +2011 +— +— +390.0 +5.76 +9.56 +2,117.4 +6.18 +— +— +4,599 +2012 +— +— +— +— +— +1,355.8 +6.18 +— +— +1,886 +2013 +— +— +— +— +— +990.4 +6.18 +— +— +1,190 +Total Natural Gas +— +11,654.1 +26,208.6 +26,115.4 +31,449 +Crude Oil +NYMEX +2011 +155.0 +74.03 +231.5 +73.00 +99.80 +545.2 +75.88 +— +— +(10,606 +) +2012 +36.0 +65.38 +368.6 +75.00 +101.20 +231.0 +83.11 +— +— +(3,870 +) +2013 +— +— +317.6 +75.00 +104.30 +186.9 +84.15 +— +— +(2,363 +) +Total Crude Oil +191.0 +917.7 +963.1 +— +(16,839 +) +Total Natural Gas and Crude Oil +$ +14,610 +__________ +(1 +) +A standard unit of measurement for natural gas (one BBtu equals one MMcf). +(2 +) +Approximately 34% of the fair value of our derivative assets and 100% of our derivative liabilities were measured using significant unobservable inputs (Level 3); see Note 3, Fair Value Measurements, to the accompanying financial statements. +46 +The following table presents our derivative positions related to our natural gas marketing in effect as of December 31, 2010 . +Collars +Fixed-Price Swaps +NYMEX +Basis Protection Swaps +Commodity/ Derivative +Instrument/ Maturity Period +Quantity +(BBtu) (1) +Weighted Average +Contract Price +Quantity +(BBtu) (1) +Weighted +Average +Contract +Price +Quantity +(BBtu) (1) +Weighted +Average +Contract +Price +Fair Value +December 31, +2010 (2) +(in thousands) +Floors +Ceilings +Natural Gas +Sales +Physical +2011 +— +$ +— +$ +— +49.4 +$ +5.02 +159.0 +$ +0.63 +$ +73 +2012 +— +— +— +— +— +53.3 +1.04 +37 +2013 - 2014 +Financial +2011 +52.5 +4.53 +7.16 +1,048.2 +6.14 +— +— +1,754 +2012 +62.5 +4.56 +(30 +) +2013 - 2014 +Purchases +Physical +2011 +52.5 +4.53 +7.14 +1,049.7 +6.11 +— +— +(1,450 +) +2012 +— +— +— +62.5 +4.50 +— +— +46 +2013 - 2014 +Financial +2011 +— +— +— +47.9 +4.38 +102.6 +0.19 +9 +2012 +— +— +— +— +— +30.4 +0.13 +— +2013 - 2014 +Total Natural Gas +105.0 +2,320.2 +345.3 +$ +439 +__________ +(1 +) +A standard unit of measurement for natural gas (one BBtu equals one MMcf). +(2 +) +Approximately 12% of the fair value of our derivative assets and 98% of our derivative liabilities were measured using significant unobservable inputs (Level 3); see Note 3, Fair Value Measurements, to the accompanying financial statements. +The following table presents monthly average NYMEX and CIG closing prices for natural gas and crude oil for the years ended December 31, 2010 and 2009, as well as average sales prices we realized for the respective commodities. +Year Ended December 31, +2010 +2009 +Average Index Closing Price +Natural Gas (per MMBtu) +CIG +$ +3.92 +$ +3.07 +NYMEX +4.39 +3.99 +Crude Oil (per Bbl) +NYMEX +77.32 +58.36 +Average Sales Price Realized (1) +Excluding realized derivative gains/(losses) +Natural Gas (per Mcf) +$ +3.61 +$ +3.09 +Crude Oil (per Bbl) +74.03 +55.07 +Including realized derivative gains/(losses) +Natural Gas (per Mcf) +5.12 +5.72 +Crude Oil (per Bbl) +79.62 +69.44 +__________ +(1) +Prior to 2010, NGLs were included in natural gas, which impacts the comparability for 2010 to 2009. +47 +Based on a sensitivity analysis as of December 31, 2010 , it was estimated that a 10% increase in natural gas and crude oil prices, inclusive of basis, over the entire period for which we have derivatives then in place, including those designated to our affiliated partnerships, would result in a decrease in fair value of $34.7 million; whereas a 10% decrease in prices would result in an increase in fair value of $34.8 million. Excluding the derivatives designated to our affiliated partnerships, the same 10% increase or decrease in natural gas and crude oil prices would result in a decrease in fair value of $29.5 million and an increase in fair value of $29.6 million, respectively. +See Note 3, Fair Value of Financial Instruments , and Note 4, Derivative Financial Instruments , to our consolidated financial statements included in this report for a summary of our open derivative positions as well as a discussion of how we determine the fair value and account for our derivative contracts. +Credit Risk +Credit risk represents the loss that we would incur if a counterparty fails to perform under its contractual obligations. We attempt to reduce credit risk by diversifying our counterparty exposure and entering into transactions with high-quality counterparties. When exposed to credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis. +With regard to our natural gas and crude oil sales segment, inherent to our industry is the concentration of natural gas, NGL and crude oil sales to a few customers. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions. As for our natural gas marketing segment, our receivables are from a diverse group of companies, including major energy companies, both upstream and mid-stream, financial institutions and end-users in various industries. We monitor their creditworthiness through credit reports and rating agency reports. To date, we have had no material counterparty default losses in either of our natural gas and crude oil sales segment or natural gas marketing segment. See Note 5, Concentration of Risk , to our consolidated financial statements included in this report. +Our derivative financial instruments expose us to the credit risk of nonperformance by the counterparty to the contracts. We primarily use financial institutions, which are also major lenders in our credit facility, as counterparties to our derivative contracts. We have evaluated the credit risk of the counterparties holding our derivative assets using relevant credit market default rates, giving consideration to amounts outstanding from each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the impact of the nonperformance of our counterparties on the fair value of our derivative instruments is insignificant. +Disruption in the credit market may have a significant adverse impact on a number of financial institutions. We monitor the creditworthiness of the financial institutions with which we transact, giving consideration to the reports of credit agencies and their related ratings. While we believe that our monitoring procedures are sufficient and customary, no amount of analysis can guarantee performance by a financial institution. +Disclosure of Limitations +Because the information above included only those exposures that exist at December 31, 2010 , it does not consider those exposures or positions which could arise after that date. As a result, our ultimate realized gain or loss with respect to interest rate and commodity price fluctuations will depend on the exposures that arise during the period, our commodity price risk management strategies at the time, and interest rates and commodity prices at the time. +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +The response to this Item is set forth herein in a separate section of this report, beginning on Page F-1. +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 +As of December 31, 2010 , we carried out an evaluation under the supervision and with the participation of 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 pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e). Based on the results of this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2010 . +Changes in Internal Control over Financial Reporting +During the fourth quarter of 2010 , we made no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) that have materially affected or are reasonably likely to materially affect our internal control over financial reporting. +48 +ITEM 9B. OTHER INFORMATION +None. +PART III +ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +The information called for by this Item is incorporated by reference from information under the captions entitled Corporate Governance, Section 16(a) Beneficial Ownership Reporting Compliance, Election of Directors and Executive Compensation and other relevant portions of our definitive proxy statement to be filed pursuant to Regulation 14A no later than 120 days after the close of our fiscal year. +ITEM 11. EXECUTIVE COMPENSATION +The information called for by this Item is incorporated by reference from information under the caption entitled Executive Compensation and other relevant portions of our definitive proxy statement to be filed pursuant to Regulation 14A no later than 120 days after the close of our fiscal year. +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +The information called for by this Item is incorporated by reference from information under the caption entitled Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters and other relevant portions of our definitive proxy statement to be filed pursuant to Regulation 14A no later than 120 days after the close of our fiscal year. +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE +The information called for by this Item is incorporated by reference from information under the captions entitled Certain Relationships and Related Transactions and Director Independence in our definitive proxy statement to be filed pursuant to Regulation 14A no later than 120 days after the close of our fiscal year. +ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES +The information called for by this Item is incorporated by reference from information under the caption entitled Principal Accountant Fees and Services and other relevant portions of our definitive proxy statement to be filed pursuant to Regulation 14A no later than 120 days after the close of our fiscal year. +PART IV +ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES +(a) +(1 +) +Financial Statements: +See Index to Financial Statements and Schedules on page F-1. +(2 +) +Financial Statement Schedules: +See Index to Financial Statements and Schedules on page F-1. +Schedules and Financial Statements Omitted +All other financial statement schedules are omitted because they are not required, inapplicable, or the information is included in the Financial Statements or Notes thereto. +(3 +) +Exhibits: +See Exhibits Index on the following page. +49 +Exhibits Index +Incorporated by Reference +Exhibit +SEC File +Filed +Number +Exhibit Description +Form +Number +Exhibit +Filing Date +Herewith +3.1 +Second Amended and Restated Certificate of Incorporation of Petroleum Development Corporation. +8-K +000-07246 +3.1 +7/23/2008 +3.2 +Bylaws of Petroleum Development Corporation, amended and restated, effective October 11, 2007. +8-K +000-07246 +3.2 +10/17/2007 +4.1 +Rights Agreement by and between Petroleum Development Corporation and Transfer Online, Inc., as Rights Agent, dated as of September 11, 2007, including the forms of Rights Certificates and Summary of Stockholder Rights Plan attached thereto as Exhibits A and B. +8-K +000-07246 +4.1 +9/14/2007 +4.2 +Indenture dated as of February 8, 2008, by and among Petroleum Development Corporation and The Bank of New York. +8-K +000-07246 +4.1 +2/12/2008 +4.3 +First Supplemental Indenture dated as of February 8, 2008, by and among Petroleum Development Corporation and the Bank of New York. +8-K +000-07246 +4.2 +2/12/2008 +4.4 +Form of 12% Senior Note due 2018. +8-K +000-07246 +4.3 +2/12/2008 +10.1 +Purchase Agreement dated as of February 1, 2008, by and among Petroleum Development Corporation and the Initial Purchasers of 12% senior notes due 2018 named therein. +8-K +000-07246 +10.1 +2/7/2008 +10.2 +Registration Rights Agreement dated as of February 8, 2008, by and among Petroleum Development Corporation and the Initial Purchasers of 12% senior notes due 2018 named therein. +8-K +000-07246 +10.1 +2/12/2008 +10.3 +Underwriting Agreement dated August 11, 2009 among the Company and J.P. Morgan Securities Inc., as representative of the several Underwriters named therein. +8-K +000-07246 +1.1 +8/11/2009 +10.4* +2006 Long-Term Equity Compensation Grants to Executive Officers. +8-K +000-07246 +10.20 +4/10/2007 +10.5* +Indemnification Agreement with Directors. +10-Q +000-07246 +10.1 +8/9/2007 +10.6* +The Petroleum Development Corporation 401(k) & Profit Sharing Plan. +X +10.7* +2005 Non-Employee Director Restricted Stock Plan, amended and restated as of March 8, 2008. +S-8 +333-126444 +10.1 +2/26/2009 +10.8 +Contribution Agreement by and among PDC Mountaineer, LLC, as the Company, Petroleum Development Corporation, as the Contributor, and LR-Mountaineer Holdings, L.P., as the Investor, dated October 29, 2009. +8-K +000-07246 +2.1 +11/4/2009 +10.9 +Limited Liability Company Agreement of PDC Mountaineer, LLC, dated October 29, 2009. +8-K +000-07246 +10.1 +11/4/2009 +10.10* +Non-Employee Director Deferred Compensation Plan. +S-8 +333-118222 +99.1 +8/13/2004 +10.11* +2004 Long-Term Equity Compensation Plan amended and restated as of March 8, 2008. +10-K +000-07246 +10.26 +2/27/2009 +10.12* +2010 Short-Term Incentive Compensation Performance Metrics for Executive Officers. +8-K +000-07246 +3/18/2010 +10.13* +Non-Employee Director Compensation for the 2010-2011 Term. +8-K +000-07246 +4/23/2010 +10.14* +Executive Compensation and Short-Term Incentive Targets for 2010. +8-K +000-07246 +4/23/2010 +10.15* +Employment Agreement with Richard W. McCullough, Chief Executive Officer, dated as of April 19, 2010. +8-K +000-07246 +10.1 +4/23/2010 +10.16* +Employment Agreement with Gysle R. Shellum, Chief Financial Officer, dated as of April 19, 2010. +8-K +000-07246 +10.2 +4/23/2010 +10.17* +Employment Agreement with Daniel W. Amidon, General Counsel and Corporate Secretary, dated as of April 19, 2010 +8-K +000-07246 +10.3 +4/23/2010 +50 +Incorporated by Reference +ExhibitNumber +Exhibit Description +Form +SEC File +Number +Exhibit +Filing Date +Filed +Herewith +10.18* +Employment Agreement with Lance A. Lauck, Senior Vice President of Business Development, dated as of April 19, 2010. +8-K +000-07246 +10.4 +4/23/2010 +10.19* +Employment Agreement with Barton R. Brookman, Jr., Senior Vice President of Exploration and Production, dated as of April 19, 2010. +8-K +000-07246 +10.5 +4/23/2010 +10.20* +2010 Long-Term Equity Compensation Plan. +S-8 +333-167945 +99.1 +7/1/2010 +10.21 † +Domestic Crude Oil Purchase Agreement between Suncor Energy Marketing, Inc. and PDC, dated May 18, 2009. +10-Q +000-53201 +10.1 +5/18/2009 +10.22 † +Gas Purchase Agreement between Williams Production RMT Company, Riley Natural Gas and Petroleum Development Corporation, dated as of March 31, 2009. +10/A No. 3 +000-53201 +10.7 +3/31/2009 +10.23 † +Gas Purchase and Processing Agreement between Duke Energy Field Services, Inc.; United States Exploration, Inc.; and Petroleum Development Corporation, dated as of October 28, 1999. +10/A No. 3 +000-53201 +10.3 +3/31/2009 +10.24 +Second Amended and Restated Credit Agreement dated as of November 5, 2010, Petroleum Development Corporation, as borrower and JPMorgan Chase Bank, N.A. and BNP Paribas, as lenders. +8-K +000-07246 +10.1 +11/12/2010 +10.25 +Underwriting Agreement dated November 18, 2010, among Petroleum Development Corporation and Wells Fargo Securities, LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representatives of the several underwriters. +8-K +000-07246 +1.1 +11/24/2010 +10.26 +Purchase Agreement, dated as of November 18, 2010, among Petroleum Development Corporation and Wells Fargo Securities, LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representatives of the initial purchasers. +8-K +000-07246 +1.1 +11/24/2010 +10.27 +Indenture, dated November 23, 2010, between the Company and The Bank of New York Mellon. +8-K +000-07246 +4.1 +11/24/2010 +10.28 +Form of 3.25% Convertible Senior Note due 2016 +8-K +000-07246 +4.1 +11/24/2010 +10.29 +First Amendment to Second Amended and Restated Credit Agreement. +X +12.1 +Computation of Ratio of Earnings to Fixed Charges. +X +14.1 +Code of Business Conduct and Ethics. +10-Q +000-17246 +14.1 +8/10/2009 +21.1 +Subsidiaries. +X +23.1 +Consent of PricewaterhouseCoopers LLP. +X +23.2 +Consent of Ryder Scott Company, L.P., Petroleum Consultants. +X +31.1 +Certification by Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. +X +31.2 +Certification by Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. +X +32.1 +Certifications by Chief Executive Officer and Chief Financial Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002. +X +99.1 +Report of Independent Petroleum Consultants - Ryder Scott Company, L.P. +X +*Management contract or compensatory plan or arrangement. +† Confidential portions of this document have been omitted and will be filed separately with the SEC pursuant to Exchange Act Rule 24b-2 on or before March 4, 2011. +51 +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. +PETROLEUM DEVELOPMENT CORPORATION +By /s/ Richard W. McCullough +Richard W. McCullough, +Chairman and Chief Executive Officer +February 24, 2011 +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/ Richard W. McCullough +Chairman and Chief Executive Officer +February 24, 2011 +Richard W. McCullough +(principal executive officer) +/s/ Gysle R. Shellum +Chief Financial Officer +February 24, 2011 +Gysle R. Shellum +(principal financial officer) +/s/ R. Scott Meyers +Chief Accounting Officer +February 24, 2011 +R. Scott Meyers +(principal accounting officer) +/s/ Daniel W. Amidon +General Counsel and Corporate Secretary +February 24, 2011 +Daniel W. Amidon +/s/ Joseph E. Casabona +Director +February 24, 2011 +Joseph E. Casabona +/s/ Anthony J. Crisafio +Director +February 24, 2011 +Anthony J. Crisafio +/s/ Larry F. Mazza +Director +February 24, 2011 +Larry F. Mazza +/s/ David C. Parke +Director +February 24, 2011 +David C. Parke +/s/ Jeffrey C. Swoveland +Director +February 24, 2011 +Jeffrey C. Swoveland +/s/ James M. Trimble +Director +February 24, 2011 +James M. Trimble +/s/ Kimberly Luff Wakim +Director +February 24, 2011 +Kimberly Luff Wakim +52 +Index to Consolidated Financial Statements and Financial Statement Schedule +Management's Report on Internal Control Over Financial Reporting +F- 2 +Financial Statements: +Report of Independent Registered Public Accounting Firm +F- 3 +Consolidated Balance Sheets - December 31, 2010 and 2009 +F- 4 +Consolidated Statements of Operations - Years Ended December 31, 2010, 2009 and 2008 +F- 5 +Consolidated Statements of Cash Flows - Years Ended December 31, 2010, 2009 and 2008 +F- 6 +Consolidated Statements of Equity - Years Ended December 31, 2010, 2009, and 2008 +F- 8 +Notes to Consolidated Financial Statements +Note 1. Nature of Operations and Basis of Presentation +F- 9 +Note 2. Summary of Significant Accounting Policies +F- 9 +Note 3. Fair Value of Financial Instruments +F- 14 +Note 4. Derivative Financial Instruments +F- 16 +Note 5. Concentration of Risk +F- 18 +Note 6. Properties and Equipment +F- 19 +Note 7. Income Taxes +F- 20 +Note 8. Long-Term Debt +F- 22 +Note 9. Asset Retirement Obligations +F- 25 +Note 10. Employee Benefit Plans +F- 25 +Note 11. Commitments and Contingencies +F- 25 +Note 12. Common Stock +F- 28 +Note 13. Assets Held for Sale, Divestiture and Discontinued Operations +F- 32 +Note 14. Acquisitions +F- 34 +Note 15. Noncontrolling Interest in Subsidiaries +F- 35 +Note 16. Transactions with Affiliates +F- 35 +Note 17. Business Segments +F- 36 +Supplemental Information - Unaudited +Natural Gas and Crude Oil Information +F- 38 +Quarterly Financial Information +F- 43 +Financial Statement Schedule +Schedule II - Valuation and Qualifying Accounts +F- 46 +F- 1 +Management's Report on Internal Control Over Financial Reporting +Management is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. 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. 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 policies or procedures may deteriorate. +Management has assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2010, based upon the criteria established in "Internal Control – Integrated Framework" issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). Based on this evaluation, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2010 . +The effectiveness of Petroleum Development Corporation's internal control over financial reporting as of December 31, 2010 , has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein. +PETROLEUM DEVELOPMENT CORPORATION +/s/ Richard W. McCullough +Richard W. McCullough +Chairman and Chief Executive Officer +/s/ Gysle R. Shellum +Gysle R. Shellum +Chief Financial Officer +/s/ R. Scott Meyers +R. Scott Meyers +Chief Accounting Officer +F- 2 +Report of Independent Registered Public Accounting Firm +To the Board of Directors and Shareholders of Petroleum Development Corporation: +In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, equity, and cash flows present fairly, in all material respects, the financial position of Petroleum Development Corporation and its subsidiaries at 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. In addition, in our opinion, the financial statement schedule appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting 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 (COSO). The Company's management is responsible for these financial statements and financial statement schedule, 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 opinions on these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated 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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. +As discussed in Note 2 to the consolidated financial statements, the Company changed the manner in which it accounts for the consolidation of variable interest entities in 2010. +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 (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 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. +/s/ PricewaterhouseCoopers LLP +Pittsburgh, Pennsylvania +February 24, 2011 +F- 3 +Petroleum Development Corporation +(dba PDC Energy) +Consolidated Balance Sheets +(in thousands, except share and per share data) +As of December 31, +2010 +2009 +Assets +Current assets: +Cash and cash equivalents +$ +54,372 +$ +31,944 +Accounts receivable, net +53,978 +56,491 +Accounts receivable affiliates +11,448 +7,956 +Fair value of derivatives +42,953 +42,223 +Income tax receivable +1,339 +27,728 +Prepaid expenses and other current assets +12,733 +11,028 +Total current assets +176,823 +177,370 +Properties and equipment, net +1,120,038 +973,658 +Assets held for sale +5,191 +34,535 +Fair value of derivatives +44,464 +20,228 +Accounts receivable affiliates +8,478 +15,473 +Other assets +34,041 +29,063 +Total Assets +$ +1,389,035 +$ +1,250,327 +Liabilities and Equity +Liabilities +Current liabilities: +Accounts payable +$ +47,271 +$ +36,845 +Accounts payable affiliates +9,605 +13,015 +Production tax liability +16,226 +24,849 +Fair value of derivatives +29,998 +20,208 +Funds held for distribution +29,755 +28,256 +Accrued interest payable +10,051 +9,782 +Other accrued expenses +17,723 +11,479 +Total current liabilities +160,629 +144,434 +Long-term debt +295,695 +280,657 +Deferred income taxes +187,999 +178,012 +Asset retirement obligation +27,797 +29,314 +Fair value of derivatives +36,644 +48,779 +Accounts payable affiliates +12,111 +5,996 +Other liabilities +25,919 +24,542 +Total liabilities +746,794 +711,734 +Commitments and contingent liabilities +Equity +Shareholders' equity: +Preferred shares, par value $0.01 per share; authorized 50,000,000 shares; +issued: none +— +— +Common shares, par value $0.01 per share; authorized 100,000,000 shares; +issued: 23,462,326 in 2010 and 19,242,219 in 2009 +235 +192 +Additional paid-in capital +209,198 +64,406 +Retained earnings +432,843 +426,629 +Treasury shares, at cost: 2,938 in 2010 and 8,273 in 2009 +(111 +) +(312 +) +Total shareholders' equity +642,165 +490,915 +Noncontrolling interest in subsidiaries +76 +47,678 +Total equity +642,241 +538,593 +Total Liabilities and Equity +$ +1,389,035 +$ +1,250,327 +See accompanying Notes to Consolidated Financial Statements +F- 4 +Petroleum Development Corporation +(dba PDC Energy) +Consolidated Statements of Operations +(in thousands, except per share data) +Year Ended December 31, +2010 +2009 +2008 +Revenues: +Natural gas, NGL and crude oil sales +$ +209,644 +$ +171,242 +$ +304,867 +Sales from natural gas marketing +69,071 +59,595 +129,015 +Commodity price risk management gain (loss), net +59,891 +(10,053 +) +127,838 +Well operations, pipeline income and other +9,041 +10,092 +10,781 +Total revenues +347,647 +230,876 +572,501 +Costs, expenses and other: +Production costs +66,817 +62,103 +75,199 +Cost of natural gas marketing +68,015 +57,618 +128,073 +Exploration expense +20,266 +18,177 +31,783 +Impairment of proved natural gas and crude oil properties +— +926 +7,579 +General and administrative expense +42,188 +53,985 +37,715 +Depreciation, depletion, and amortization +109,243 +126,755 +101,443 +Gain on sale of leaseholds +(174 +) +(470 +) +— +Total cost, expenses and other +306,355 +319,094 +381,792 +Income (loss) from operations +41,292 +(88,218 +) +190,709 +Interest income +71 +254 +591 +Interest expense +(33,250 +) +(37,208 +) +(28,132 +) +Income (loss) from continuing operations before income taxes +8,113 +(125,172 +) +163,168 +Provision (benefit) for income taxes +1,192 +(45,054 +) +57,337 +Income (loss) from continuing operations +6,921 +(80,118 +) +105,831 +Income (loss) from discontinued operations, net of tax +(987 +) +(975 +) +7,413 +Net income (loss) +5,934 +(81,093 +) +113,244 +Less: net loss attributable to noncontrolling interests +(280 +) +(1,816 +) +(65 +) +Net income (loss) attributable to shareholders +$ +6,214 +$ +(79,277 +) +$ +113,309 +Amounts attributable to Petroleum Development Corporation shareholders: +Income (loss) from continuing operations +$ +7,201 +$ +(78,302 +) +$ +105,896 +Income (loss) from discontinued operations, net of tax +(987 +) +(975 +) +7,413 +Net income (loss) attributable to shareholders +$ +6,214 +$ +(79,277 +) +$ +113,309 +Earnings (loss) per share attributable to shareholders: +Basic +Income (loss) from continuing operations +$ +0.37 +$ +(4.76 +) +$ +7.19 +Income (loss) from discontinued operations +(0.05 +) +(0.06 +) +0.50 +Net income (loss) attributable to shareholders +$ +0.32 +$ +(4.82 +) +$ +7.69 +Diluted +Income (loss) from continuing operations +$ +0.36 +$ +(4.76 +) +$ +7.13 +Income (loss) from discontinued operations +(0.05 +) +(0.06 +) +0.50 +Net income (loss) attributable to shareholders +$ +0.31 +$ +(4.82 +) +$ +7.63 +Weighted average common shares outstanding +Basic +19,674 +16,448 +14,736 +Diluted +19,821 +16,448 +14,848 +See accompanying Notes to Consolidated Financial Statements +F- 5 +Petroleum Development Corporation +(dba PDC Energy) +Consolidated Statements of Cash Flows +(in thousands) +Year Ended December 31, +2010 +2009 +2008 +Cash flows from operating activities: +Net income (loss) +$ +5,934 +$ +(81,093 +) +$ +113,244 +Adjustments to net income (loss) to reconcile to net cash provided by operating activities: +Unrealized (gain) loss on derivatives, net +(12,625 +) +116,623 +(117,536 +) +Depreciation, depletion and amortization +111,062 +131,004 +104,640 +Impairment of proved natural gas and oil properties +4,666 +926 +22,091 +Expired and abandoned leases +6,481 +7,279 +3,633 +Exploratory dry hole costs +4,199 +1,059 +6,504 +Accretion of asset retirement obligation +1,423 +1,368 +1,230 +Stock-based compensation +5,314 +5,935 +6,702 +Excess tax benefits from stock-based compensation +(293 +) +— +(1,031 +) +Loss (gain) from sale of leaseholds/assets +299 +(105 +) +19 +Amortization of debt issuance costs +4,618 +5,302 +1,344 +Deferred income taxes +1,179 +(18,084 +) +59,079 +Total adjustments to net income (loss) to reconcile to net cash provided by operating activities: +126,323 +251,307 +86,675 +Changes in current assets and liabilities: +Decrease (increase) in restricted cash +219 +15,564 +(4,257 +) +Decrease (increase) in accounts receivable +2,122 +13,197 +(9,664 +) +Decrease (increase) in accounts receivable - affiliates +(450 +) +14,282 +(7,631 +) +Decrease (increase) in income taxes receivable +26,389 +(27,728 +) +— +Decrease (increase) in other current assets +(2,348 +) +16,478 +(7,855 +) +Increase (decrease) in production tax liability +(6,818 +) +(4,541 +) +9,857 +Increase (decrease) in accounts payable and accrued expenses +1,172 +(22,482 +) +2,790 +Increase (decrease) in accounts payable - affiliates +(3,812 +) +(7,566 +) +10,282 +Increase (decrease) in advances for future drilling contracts +— +(1,675 +) +(66,742 +) +Increase (decrease) in federal and state income taxes payable +402 +(2,580 +) +1,721 +Increase (decrease) in funds held for future distribution +2,018 +(22,105 +) +10,538 +Other +662 +2,837 +143 +Total changes in current assets and liabilities +19,556 +(26,319 +) +(60,818 +) +Net cash provided by operating activities +151,813 +143,895 +139,101 +Cash flows from investing activities: +Capital expenditures +(162,723 +) +(143,033 +) +(323,153 +) +Acquisition of oil and gas properties, net of cash acquired +(158,051 +) +— +— +Deconsolidation/change in ownership effect on cash and cash equivalents +(3,527 +) +— +— +Decrease (increase) in restricted cash +— +— +(874 +) +Proceeds from sale of leases to partnerships +— +— +448 +Proceeds from sale of leaseholds/assets +23,369 +755 +538 +Net cash used in investing activities +(300,932 +) +(142,278 +) +(323,041 +) +Cash flows from financing activities: +Proceeds from credit facility +414,500 +285,086 +419,000 +Proceeds from senior notes +115,000 +— +200,101 +Payment of credit facility +(494,500 +) +(399,586 +) +(459,500 +) +Payment of debt issuance costs +(8,541 +) +(9,249 +) +(5,571 +) +Proceeds from sale of equity, net of issuance costs +125,506 +48,490 +— +Proceeds from exercise of stock options +— +— +627 +Excess tax benefits from stock-based compensation +293 +— +1,031 +Contribution from noncontrolling interest +20,077 +55,000 +— +Purchase of treasury stock +(788 +) +(364 +) +(5,549 +) +Net cash provided by (used in) financing activities +171,547 +(20,623 +) +150,139 +Net increase (decrease) in cash and cash equivalents +22,428 +(19,006 +) +(33,801 +) +Cash and cash equivalents, beginning of year +31,944 +50,950 +84,751 +Cash and cash equivalents, end of year +$ +54,372 +$ +31,944 +$ +50,950 +See accompanying Notes to Consolidated Financial Statements +F- 6 +Petroleum Development Corporation +(dba PDC Energy) +Consolidated Statements of Cash Flows - Continued +(in thousands) +Year Ended December 31, +2010 +2009 +2008 +Supplemental cash flow information: +Cash payments (receipts) for: +Interest, net of capitalized interest +$ +28,335 +$ +32,014 +$ +19,200 +Income taxes, net of refunds +(27,322 +) +(3,355 +) +(530 +) +Non-cash investing activities: +Change in accounts payable related to purchases of properties and equipment +$ +15,787 +$ +(36,765 +) +$ +8,197 +Change in asset retirement obligation, with a corresponding increase to natural gas and crude oil properties, net of disposals +3,624 +5,110 +1,153 +Non-cash financiang activities: +Change in paid-in capital related to convertible debt, net of tax of $7,873 +$ +12,850 +$ +— +$ +— +See accompanying Notes to Consolidated Financial Statements +F- 7 +Petroleum Development Corporation +(dba PDC Energy) +Consolidated Statements of Equity +(in thousands, except share and per share data) +Year Ended December 31, +2010 +2009 +2008 +Common shares, issued: +Shares beginning of year +19,242,219 +14,871,870 +14,907,679 +Adjust prior conversion of predecessor shares +— +— +100 +Shares issued pursuant to sale of equity +4,140,000 +4,312,500 +— +Exercise of stock options +— +— +25,699 +Issuance of stock awards, net of forfeitures +110,680 +79,246 +21,863 +Retirement of treasury shares +(30,573 +) +(21,397 +) +(83,471 +) +Shares end of year +23,462,326 +19,242,219 +14,871,870 +Treasury shares: +Shares beginning of year +(8,273 +) +(7,066 +) +(5,894 +) +Purchase of treasury shares +(30,573 +) +(21,397 +) +(83,471 +) +Retirement of treasury shares +30,573 +21,397 +83,471 +Non-employee directors' deferred compensation plan +5,335 +(1,207 +) +(1,172 +) +Shares end of year +(2,938 +) +(8,273 +) +(7,066 +) +Common shares outstanding +23,459,388 +19,233,946 +14,864,804 +Equity: +Shareholders' equity +Preferred shares, par value $0.01 per share: +Balance beginning and end of year +$ +— +$ +— +$ +— +Common shares, par value $0.01 per share: +Balance beginning of year +192 +149 +149 +Shares issued pursuant to sale of equity +41 +43 +— +Issuance of stock awards, net of forfeitures +2 +— +— +Balance end of year +235 +192 +149 +Additional paid-in capital: +Balance beginning of year +64,406 +5,818 +2,559 +Proceeds from sale of equity, net of issuance costs of $6,974 +125,465 +48,447 +— +Convertible debt discount, net of issuance costs of $685 and tax of $7,873 +12,165 +— +— +Issuance of stock awards, net of forfeitures +(2 +) +— +— +Exercise of stock options +— +— +627 +Stock-based compensation expense +5,314 +5,935 +6,702 +Retirement of treasury shares +(788 +) +(364 +) +(5,101 +) +Tax benefit (detriment) of stock-based compensation +(164 +) +(1,630 +) +1,031 +Contribution from noncontrolling interest +20,077 +55,000 +— +Effect of PDCM deconsolidation/change in ownership interest +(17,275 +) +(48,800 +) +— +Balance end of year +209,198 +64,406 +5,818 +Retained earnings: +Balance beginning of year +426,629 +505,906 +393,044 +Retirement of treasury shares +— +— +(447 +) +Net income (loss) attributable to shareholders +6,214 +(79,277 +) +113,309 +Balance end of year +432,843 +426,629 +505,906 +Treasury shares, at cost: +Balance beginning of year +(312 +) +(292 +) +(226 +) +Purchase of treasury shares +(788 +) +(364 +) +(5,549 +) +Retirement of treasury shares +788 +364 +5,549 +Non-employee directors' deferred compensation plan +201 +(20 +) +(66 +) +Balance end of year +(111 +) +(312 +) +(292 +) +Total shareholders' equity +642,165 +490,915 +511,581 +Noncontrolling interests in subsidiaries +Balance beginning of year +47,678 +694 +759 +Noncontrolling interest in PDC Mountaineer, LLC +(47,322 +) +48,800 +— +Net loss attributed to noncontrolling interest in subsidiary +(280 +) +(1,816 +) +(65 +) +Balance end of year +76 +47,678 +694 +Total noncontrolling interests in subsidiaries +76 +47,678 +694 +Total Equity +$ +642,241 +$ +538,593 +$ +512,275 +See accompanying Notes to Consolidated Financial Statements +F- 8 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +NOTE 1 - NATURE OF OPERATIONS AND BASIS OF PRESENTATION +Petroleum Development Corporation ("PDC," "PDC Energy," "we," "us" or "the Company") is a domestic independent natural gas and crude oil company engaged in the exploration for and the acquisition, development, production and marketing of natural gas, natural gas liquids ("NGLs") and crude oil. As of December 31, 2010 , we owned an interest in and operated approximately 5,000 gross wells located primarily in the Rocky Mountain Region and the Permian and Appalachian Basins. We are engaged in two business segments: (1) natural gas and crude oil sales and (2) natural gas marketing. +The consolidated financial statements include the accounts of PDC, our wholly owned subsidiaries, an entity in which we have a controlling financial interest and our proportionate share of PDC Mountaineer, LLC ("PDCM") and 29 of our affiliated partnerships. Pursuant to the proportionate consolidation method, our accompanying consolidated financial statements include our pro rata share of assets, liabilities, revenues and expenses of the entities which we proportionately consolidate. All material intercompany accounts and transactions have been eliminated in consolidation. +On January 1, 2010, pursuant to the adoption of new accounting changes related to variable interest entities, PDCM, a variable interest entity, was deconsolidated from 100% and proportionately consolidated at 67.4%, representing only our ownership interest. On April 1 and November 1, 2010, our joint venture partner made cash capital contributions to PDCM of $28 million and $7 million, respectively. The contributions resulted in our original ownership interest decreasing from 67.4% to 57.8% then to 55.8%. Each change in our ownership interest resulted in a decrease in our proportionate share of net assets and future earnings. As of December 31, 2010, PDCM was consolidated at 55.8% and the 29 partnerships were consolidated at varying percentages. See Notes 2 and 15 for the impact of new accounting changes on the consolidation of PDCM on January 1, 2010. +The preparation of our consolidated financial statements in accordance with generally accepted accounting principles in the United States of America ("U.S.") requires us to make estimates and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to our consolidated financial statements include estimates of natural gas, NGL and crude oil sales revenue, natural gas, NGL and crude oil reserves, future cash flows from natural gas and crude oil properties, valuation of derivative instruments and valuation of deferred income tax assets. +Certain reclassifications have been made to prior period financial statements to conform to the current year presentation. The reclassifications are directly related to our discontinued operations. The reclassifications had no impact on previously reported cash flows, net income, earnings per share or shareholders' equity. See Note 13 for additional information regarding our discontinued operations. +NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Consolidation and Accounting for Variable Interest Entities. A variable interest entity ("VIE") is consolidated if it is determined that we are the entity's primary beneficiary. The primary beneficiary of a VIE has both the following characteristics: (1) the power to direct the activities of the VIE that most significantly impact the entity's economic performance and (2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. In determining whether we are the primary beneficiary of a VIE, we consider a number of factors, including our ability to direct the activities that most significantly affect the entity's economic success and our contractual rights and responsibilities under arrangements with the entity. As certain events occur, we may reconsider whether those events have caused us to become the primary beneficiary. A reconsideration event may also occur when we acquire new or additional interests in a VIE. As of December 31, 2010, we were not the primary beneficiary of a VIE. As of December 31, 2009, we consolidated PDCM, a VIE, as we had determined, prior to the adoption of new accounting changes, that we were the primary beneficiary. See Recent Accounting Standards below and Note 15 for the impact of new accounting changes on the deconsolidation of PDCM on January 1, 2010. +F- 9 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the carrying amount and classification of our proportionate share of PDCM's assets and liabilities included in our balance sheets. +As of December 31, +2010 +2009 +(in thousands) +Cash and cash equivalents +$ +1,560 +$ +9,428 +Other current assets +3,206 +4,504 +Property, plant and equipment, net +101,679 +158,788 +Other assets +1,986 +1,499 +Total assets +$ +108,431 +$ +174,219 +Other current liabilities +$ +4,641 +$ +12,224 +Asset retirement obligation +8,681 +14,769 +Other liabilities +1,370 +2,068 +Noncontrolling interest +— +47,322 +Equity +93,739 +97,836 +Total liabilities and equity +$ +108,431 +$ +174,219 +Cash Equivalents. We consider all highly liquid investments with original maturities of three months or less to be cash equivalents. +Inventory. Inventory consists of crude oil, stated at the lower of cost to produce or market, and other production supplies intended to be used in our natural gas and crude oil operations. As of December 31, 2010 and 2009, inventory of $1.4 million and $0.8 million, respectively, is included in prepaid expense and other current assets on the balance sheets. +Derivative Financial Instruments. We are exposed to the effect of market fluctuations in the prices of natural gas and crude oil. We employ established policies and procedures to manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. Our policy prohibits the use of natural gas and crude oil derivative instruments for speculative purposes. +All derivative assets and liabilities are recorded on the balance sheets at fair value. We have elected not to designate any of our derivative instruments as hedges. Classification of realized and unrealized gains and losses resulting from maturities and changes in fair value of open derivatives depends on the purpose for issuing or holding the derivative. Accordingly, changes in the fair value of our derivative instruments are recorded in the statements of operations, with the exception of changes in fair value related to those derivatives we designated to our affiliated partnerships. Changes in the fair value of derivative instruments related to our natural gas and crude oil sales are recorded in commodity price risk management, net. Changes in the fair value of derivative instruments related to our natural gas marketing segment are recorded in sales from and cost of natural gas marketing. Changes in the fair value of the derivative instruments designated to our affiliated partnerships are recorded on the balance sheets in accounts payable affiliates and accounts receivable affiliates. As positions designated to our affiliated partnerships settle, the realized gains and losses are netted for distribution. Net realized gains are paid to the partnerships and net realized losses are deducted from the partnerships’ cash distributions from production. The affiliated partnerships bear their designated share of counterparty risk. +The validation of the derivative instrument's fair value is performed internally and while we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. See Notes 3 and 4 for a discussion of our derivative fair value measurements and a summary fair value table of our open positions as of December 31, 2010 and 2009, respectively. +Properties and Equipment. Significant accounting polices related to our properties and equipment are discussed below. +Natural Gas and Crude Oil Properties. We account for our natural gas and crude oil properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves. We calculate quarterly depreciation, depletion and amortization ("DD&A") expense by using our estimated prior period-end reserves as the denominator, with the exception of our fourth quarter where we use the year-end reserve estimate adjusted to add back fourth quarter production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized in the statement of operations as a gain or loss. Upon the sale of individual wells, the proceeds are credited to accumulated DD&A. +F- 10 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Exploration costs, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized but charged to expense if the well is determined to be nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as the well has found a sufficient quantity of reserves to justify our completion as a producing well and we are making sufficient progress assessing our reserves and economic and operating viability. If an in-progress exploratory well is found to be unsuccessful prior to the issuance of the financial statements, the costs incurred, including costs for plugging, prior to the end of the reporting period are expensed to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the costs associated with the well are classified as "suspended well costs" until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time we are able to make a final determination of a well’s productive status, the same well is removed from the suspended well status and the proper accounting treatment is recorded. See Note 6 for disclosure related to changes in our capitalized exploratory well costs from January 1, 2008, to December 31, 2010 . +Proved Property Impairment. We assess our producing natural gas and crude oil properties for possible impairment, upon a triggering event, by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which we reasonably estimate the commodity to be sold. The estimates of future prices may differ from current market prices of natural gas and crude oil. Certain events, including but not limited to, downward revisions in estimates to our reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event and, therefore, a possible impairment of our proved natural gas and crude oil properties. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis and is measured by the amount by which the net capitalized costs exceed their fair value. In May 2010, pursuant to our entry into an agreement to sell our Michigan assets, we reclassified our Michigan assets as held for sale. See Note 13. The agreement to sell these assets, a triggering event, required us to perform an impairment test as long lived assets held for sale are required to be measured at the lower of carrying value or fair value less costs to sell. We compared the transactional sales price, considered a Level 3 input, less costs to sell to the carrying value of our Michigan net assets. Since the net carrying value exceeded the net sales price, we were required to recognize an impairment charge by reducing the carrying value of the net assets to reflect the net sales price. As a result, in the second quarter of 2010, we recorded an impairment charge of $4.7 million related to the sale of our Michigan assets. The impairment charge is reflected in discontinued operations in the statement of operations. +Unproved Property Impairment. The acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense when expired, impaired or amortized. Unproved natural gas and crude oil properties with individually significant acquisition costs are periodically assessed, and any impairment in value is charged to exploration expense. +The amount of impairment recognized on unproved properties which are not individually significant is determined by amortizing the costs of such properties within appropriate fields based on our historical experience, acquisition dates and average lease terms. Impairment charges are recorded in the statements of operations as a component of exploration expense. +The following table presents expiration, impairment and amortization charges recorded for unproved properties. +As of December 31, +2010 +2009 +2008 +(in thousands) +Individually significant unproved properties (1) +$ +1,477 +$ +982 +$ +9,165 +Insignificant unproved properties (2) +5,004 +3,126 +3,633 +Total +$ +6,481 +$ +4,108 +$ +12,798 +__________ +(1) +2008 includes an impairment of $7.3 million related to our properties in the Fort Worth Basin. +(2) +The increase in amortization of insignificant unproved properties in 2010 was primarily due to our lack of drilling in the NECO area and the Pennsylvania portion of the Appalachian Basin. +Other Property and Equipment. The following table presents the estimated useful lives of our other property and equipment. +Pipelines and related facilities +10 - 17 years +Transportation and other equipment +3 - 20 years +Buildings +20 - 30 years +Other property and equipment are carried at cost. Depreciation is provided principally on the straight-line method over the assets estimated useful lives. We review these long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying +F- 11 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds our estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. Impairments recognized in 2010 and 2009 were immaterial. No impairments were recorded in 2008. +Maintenance and repairs on other property and equipment are charged to expense as incurred. Major renewals and improvements are capitalized. Upon the sale or other disposition of assets, the cost and related accumulated DD&A are removed from the accounts, the proceeds are applied thereto and any resulting gain or loss is reflected in income. Total depreciation expense related to other property and equipment was $7.5 million, $8.1 million and $7.6 million in 2010 , 2009 and 2008, respectively. +Capitalized Interest. Interest costs are capitalized as part of the historical cost of acquiring assets. Investments in unproved natural gas and crude oil properties and major development projects, on which DD&A is not currently recorded and on which exploration or development activities are in progress, qualify for capitalization of interest. Major construction projects also qualify for interest capitalization until the asset is ready for service. Capitalized interest is calculated by multiplying our weighted-average interest rate on our debt outstanding by the qualifying costs. Interest capitalized may not exceed gross interest expense for the period. As the qualifying asset is moved to the DD&A pool, the related capitalized interest is also transferred and is amortized over the useful life of the asset. Capitalized interest totaled $0.3 million, $0.8 million and $2.6 million in 2010 , 2009 and 2008, respectively. +Production Tax Liability. Production tax liability represents estimated taxes, primarily severance, ad valorem and property, to be paid to the states and counties in which we produce natural gas, NGLs and crude oil, including the production of our affiliated partnerships. Our share of these taxes is expensed to production costs. The partnerships' share, not owned by us, is recognized as a receivable in accounts receivable affiliates on the balance sheets. +Income Taxes. We account for income taxes under the asset and liability method. We recognize deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. If we determine that it is more likely than not that some portion or all of the deferred tax assets will not be realized, we record a valuation allowance thereby reducing the deferred tax assets to what we consider realizable. As of December 31, 2010, we had no valuation allowance. As of December 31, 2009, we had a valuation allowance of $0.7 million. +Debt Issuance Costs. Debt issuance costs are capitalized and amortized over the life of the respective borrowings using the effective interest method. As of December 31, 2010 and 2009, included in other assets was $14.6 million and $10.7 million, respectively, related to debt issuance costs. The December 31, 2010, amount included $3.1 million in costs related to the issuance of our 3.25% convertible senior notes due 2016, $3.9 million related to our 12% senior notes due 2018 and $7.6 million related to our bank credit facilities. +Asset Retirement Obligations. We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the well is completely drilled. Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the long-lived asset by the same amount as the liability. Over time, the liabilities are accreted for the change in their present value, through charges to production costs. The initial capitalized costs are depleted over the useful lives of the related assets, through charges to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from changes in retirement costs or the estimated timing of settling asset retirement obligations. See Note 9 for a reconciliation of the changes in our asset retirement obligation from January 1, 2009, to December 31, 2010 . +Retirement of Treasury Shares. We have historically retired all treasury share purchases, with the exception of shares purchased in accordance with our non-employee deferred compensation plan for non-employee directors; see Note 12. As treasury shares are retired, we charge any excess of cost over the par value entirely to additional paid-in-capital, to the extent we have amounts in additional paid-in-capital, with any remaining excess cost being charged to retained earnings. +Revenue Recognition. Significant accounting polices related to our revenue recognition are discussed below. +Natural gas, NGL and crude oil sales. Natural gas, NGL and crude oil revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. We currently use the "net-back" method of accounting for transportation arrangements of our natural gas sales. We sell gas at the wellhead and collect a price and recognize revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by the customers and reflected in the wellhead price. The majority of our natural gas and NGLs in Colorado are sold on a long-term basis ranging from 15 years to the life of the lease. Sales of natural gas and NGLs in other regions, along with crude oil, are sold under contracts with terms ranging from one month to three years. Virtually all of our contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the natural gas and prevailing supply and demand conditions. +F- 12 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Well operations and pipeline income . We are paid a monthly operating fee for each well we operate and the natural gas transported for outside owners including the limited partnerships we sponsored. Well operations and pipeline income is recognized when persuasive evidence of an arrangement exists, services have been rendered, collection of revenues is reasonably assured and the sales price is fixed or determinable. +Natural gas marketing. Natural gas marketing is reported on the gross method of accounting, based on the nature of the agreements between Riley Natural Gas ("RNG"), our suppliers and our customers. RNG, our marketing subsidiary, purchases gas from many small producers and bundles the gas together to sell in larger amounts to purchasers of natural gas for a price advantage. RNG has latitude in establishing price and discretion in supplier and purchaser selection. Natural gas marketing revenues and expenses reflect the full cost and revenue of those transactions because RNG takes title to the gas it purchases from the various producers and bears the risks and rewards of that ownership. Both the realized and unrealized gains and losses of the RNG commodity-based derivative transactions for natural gas marketing are included in sales from or cost of natural gas marketing, as applicable. +Stock-Based Compensation. Stock-based compensation is recognized in our financial statements based on the fair value, on the date of grant or modification, of the equity instrument awarded. Stock-based compensation expense is recognized in the financial statements on a straight-line basis over the vesting period for the entire award. To the extent compensation cost relates to employees directly involved in natural gas and crude oil exploration and development activities, such amounts may be capitalized to properties and equipment. Amounts not capitalized to properties and equipment are recognized in the related cost and expense line item in the statement of operations. No amounts for stock-based compensation were capitalized in 2010 , 2009 or 2008. +Earnings Per Share. Basic earnings (loss) per common share ("EPS") is computed by dividing net income (loss), the numerator, by the weighted-average number of common shares outstanding for the period, the denominator. Diluted EPS is similarly computed except that the denominator includes the effect, using the treasury stock method, of our unamortized portion of restricted stock, outstanding stock appreciation rights ("SARs"), stock options, convertible notes and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive. +The following table presents a reconciliation of the weighted average diluted shares outstanding. +Year Ended December 31, +2010 +2009 +2008 +(in thousands) +Weighted average common shares outstanding - basic +19,674 +16,448 +14,736 +Dilutive effect of share-based compensation: +Restricted stock +119 +— +71 +SARs +21 +— +— +Stock options +— +— +35 +Non employee director deferred compensation +7 +— +6 +Weighted average common and common share equivalents outstanding - diluted +19,821 +16,448 +14,848 +For 2009, the weighted average common shares outstanding for both basic and diluted were the same, as the effect of dilutive securities were anti-dilutive due to our net loss. The following table presents the weighted average common share equivalents excluded from the calculation of diluted earnings (loss) per share due to their anti-dilutive effect. +Year Ended December 31, +2010 +2009 +2008 +(in thousands) +Weighted average common share equivalents excluded from diluted earnings +per share due to their anti-dilutive effect: +Restricted stock +204 +284 +73 +Stock options +10 +10 +— +Non employee director deferred compensation +— +8 +— +Total anti-dilutive common share equivalents +214 +302 +73 +In November 2010, we issued 115,000 convertible senior notes, $1,000 principal amount, that give the holders the right to convert the principal amount into 2.7 million common shares at a conversion price of $42.40 per share. These convertible notes could have a dilutive impact on our earnings per share if the average market share price exceeds the conversion price. The table above does not include those shares issuable upon conversion as the average share price of our common stock did not exceed the conversion price during the period. +F- 13 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Recent Accounting Standards. The following standards have been recently adopted: +Consolidation - Variable Interest Entities. In June 2009, the Financial Accounting Standards Board ("FASB") issued changes regarding an entity's analysis to determine whether any of its variable interests constitute controlling financial interests in a variable interest entity. This analysis identifies the primary beneficiary of a variable interest entity as the enterprise that has both of the following characteristics: +• +the power to direct the activities of a variable interest entity that most significantly impact the entity's economic performance; and +• +the obligation to absorb losses of the entity that could potentially be significant to the variable interest entity or the right to receive benefits from the entity that could potentially be significant to the variable interest entity. +Additionally, the entity is required to assess whether it has an implicit financial responsibility to ensure that a variable interest entity operates as designed when determining whether it has the power to direct the activities of the variable interest entity that most significantly impact the entity's economic performance. The guidance also requires ongoing reassessments of whether an enterprise is the primary beneficiary of a variable interest entity. We adopted these changes effective January 1, 2010. Upon adoption, we deconsolidated PDCM as we determined that we were not the primary beneficiary based upon the fact that power over the activities that significantly impact this joint venture is equally shared with our investment partner. No cumulative effect adjustment to retained earnings was recognized upon adoption. See Note 15 for the impact of adoption on our financial statements. +Fair Value Measurements and Disclosures. In January 2010, the FASB issued changes clarifying existing disclosure requirements related to fair value measurements. The update also added a new requirement to disclose fair value transfers in and out of Levels 1 and 2 and describe the reasons for the transfers. The adoption of these changes as of January 1, 2010, did not have a material impact on our financial statements. +The following standards have recently been issued: +Fair Value Measurements and Disclosures. In January 2010, the FASB issued changes related to fair value measurements requiring gross presentation of activities within the Level 3 roll forward, whereby entities must present separately information about purchases, sales, issuances and settlements. These changes will be effective for our financial statements issued for annual reporting periods beginning after December 15, 2010. We do not expect the adoption of this change to have a material impact on our financial statements. +NOTE 3 - FAIR VALUE OF FINANCIAL INSTRUMENTS +Derivative Financial Instruments +Determination of fair value. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as: +Level 1 – Quoted prices (unadjusted) in active markets for identical assets or liabilities. Included in Level 1 are our commodity derivative instruments for NYMEX-based natural gas swaps. +Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including (i) quoted prices for similar assets or liabilities in active markets, (ii) quoted prices for identical or similar assets or liabilities in inactive markets, (iii) inputs other than quoted prices that are observable for the asset or liability and (iv) inputs that are derived from observable market data by correlation or other means. +Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Included in Level 3 are our commodity derivative instruments for CIG and PEPL-based natural gas swaps, crude oil swaps, natural gas and crude oil collars, physical sales and purchases and our natural gas basis protection derivative instruments. +Derivative Financial Instruments. We measure the fair value of our derivative instruments based upon quoted market prices, where available. Our valuation determination includes: (1) identification of the inputs to the fair value methodology through the review of counterparty statements and other supporting documentation, (2) determination of the validity of the source of the inputs, (3) corroboration of the original source of inputs through access to multiple quotes, if available, or other information and (4) monitoring changes in valuation methods and assumptions. The methods described above may produce a fair value calculation that may not be indicative of future fair values. Our valuation determination also gives consideration to nonperformance risk on our own liabilities as well as the credit standing of our counterparties. We primarily use financial institutions, who are also major lenders in our credit facility agreement, as counterparties to our derivative contracts. We have evaluated the credit risk of the counterparties holding our derivative assets using relevant credit market default +F- 14 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the impact of the nonperformance of our counterparties on the fair value of our derivative instruments is insignificant. Validation of our contracts’ fair value is performed internally and while we use common industry practices to +develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. While we believe these valuation methods are appropriate and consistent with those used by other market participants, the use of different methodologies, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value. +The following table presents, for each hierarchy level, our assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis as of December 31, 2010 and 2009. +As of December 31, +2010 +2009 +Quoted Prices in +Active Markets +(Level 1) +Significant +Unobservable +Inputs +(Level 3) +Total +Quoted Prices in +Active Markets +(Level 1) +Significant +Unobservable +Inputs +(Level 3) +Total +(in thousands) +Assets: +Commodity based derivatives +$ +64,138 +$ +23,168 +$ +87,306 +$ +25,598 +$ +36,796 +$ +62,394 +Basis protection derivative contracts +— +111 +111 +— +57 +57 +Total assets +64,138 +23,279 +87,417 +25,598 +36,853 +62,451 +Liabilities: +Commodity based derivatives +51 +20,011 +20,062 +3,140 +9,932 +13,072 +Basis protection derivative contracts +— +46,580 +46,580 +— +55,915 +55,915 +Total liabilities +51 +66,591 +66,642 +3,140 +65,847 +68,987 +Net asset (liability) +$ +64,087 +$ +(43,312 +) +$ +20,775 +$ +22,458 +$ +(28,994 +) +$ +(6,536 +) +The following table presents a reconciliation of our Level 3 fair value measurements. +2010 +2009 +(in thousands) +Fair value, net asset (liability) beginning of year, January 1 +$ +(28,994 +) +$ +134,849 +Changes in fair value included in statement of operations line item: +Commodity price risk management gain (loss), net +14,999 +(23,243 +) +Sales from natural gas marketing +580 +(380 +) +Cost of natural gas marketing +(5,113 +) +3,718 +Changes in fair value included in balance sheet line item (1): +Accounts receivable affiliates +2,544 +(18,960 +) +Accounts payable affiliates +(5,826 +) +(29,292 +) +Settlements included in statement of operations line items: +Commodity price risk management gain (loss), net +(26,487 +) +— +Sales from natural gas marketing +(484 +) +(95,678 +) +Cost of natural gas marketing +5,469 +(8 +) +Fair value, net liability end of year, December 31 +$ +(43,312 +) +$ +(28,994 +) +Changes in unrealized gains (losses) relating to assets (liabilities) still held +as of December 31, 2010, included in statement of operations line item: +Commodity price risk management gain (loss), net +$ +8,040 +$ +(38,634 +) +Sales from natural gas marketing +54 +29 +Cost of natural gas marketing +(997 +) +(1,083 +) +$ +7,097 +$ +(39,688 +) +__________ +(1) Represents the change in fair value related to derivative instruments entered into by us and designated to our affiliated partnerships. +F- 15 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +See Note 4 for additional disclosure related to our derivative financial instruments. +Non-Derivative Financial Assets and Liabilities +The carrying values of the financial instruments comprising current assets and current liabilities approximate fair value due to the short-term maturities of these instruments. +The portion of our long-term debt related to our credit facility approximates fair value due to the variable nature of its related interest rate. We have not elected to account for the portion of our long-term debt related to our senior notes under the fair value option; however, as of December 31, 2010, we estimate the fair value of the portion of our long-term debt related to the 3.25% convertible senior notes due 2015 to be $137.3 million or 119.4% of par value and the portion related to our 12% senior notes due 2018 to be $226.5 million or 111.6% of par value as of December 31, 2010 . We determined these valuations based upon measurements of trading activity and broker/dealer quotes, respectively. +See Note 2, subsections Property and Equipment, Natural Gas and Crude Oil Properties and Asset Retirement Obligations for a discussion of how we determined fair value for these obligations. +NOTE 4 - DERIVATIVE FINANCIAL INSTRUMENTS +Our results of operations and operating cash flows are affected by changes in market prices for natural gas and crude oil. To mitigate a portion of our exposure to adverse market changes, we utilize the following economic hedging strategies for each of our business segments. +• +For natural gas and crude oil sales, we enter into derivative contracts to protect against price declines in future periods. While we structure these derivatives to reduce our exposure to changes in price associated with the derivative commodity, they also limit the benefit we might otherwise have received from price increases in the physical market. +• +For natural gas marketing, we enter into fixed-price physical purchase and sale agreements that qualify as derivative contracts. In order to offset the fixed-price physical derivatives in our natural gas marketing, we enter into financial derivative instruments that have the effect of locking in the prices we will receive or pay for the same volumes and period, offsetting the physical derivative. +We believe our derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. As of December 31, 2010 , we had derivative instruments in place for a portion of our anticipated production through 2013 for a total of 37,862.9 BBtu of natural gas and 2,071.7 MBbls of crude oil. +As of December 31, 2010 , our derivative instruments were comprised of commodity floors, collars and swaps, basis protection swaps and physical sales and purchases. +• +Floor options (puts) are arrangements where, if the index price falls below the fixed put strike price, we receive the market price from the purchaser and receive the difference between the put strike price and index price from the counterparty. If the index price exceeds the fixed put strike price, then no payment is due from us to the counterparty. +• +Collars contain a fixed floor price and ceiling price (call). If the index price falls below the fixed put strike price, we receive the market price from the purchaser and receive the difference between the put strike price and index price from the counterparty. If the index price exceeds the fixed call strike price, we receive the market price from the purchaser and pay the difference between the call strike price and index price to the counterparty. If the index price is between the put and call strike price, no payments are due to or from the counterparty. +• +Swaps are arrangements that guarantee a fixed price. If the index price is below the fixed contract price, we receive the market price from the purchaser and receive the difference between the index price and the fixed contract price from the counterparty. If the index price is above the fixed contract price, we receive the market price from the purchaser and pay the difference between the index price and the fixed contract price to the counterparty. If the index price and contract price are the same, no payment is due to or from the counterparty. +• +Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point. For CIG-basis protection swaps, which have negative differentials to NYMEX, we receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract. If the market price and contract price are the same, no payment is due to or from the counterparty. +• +Physical sales and purchases are derivatives for fixed-priced physical transactions where we sell or purchase third party supply at fixed rates. These physical derivatives are offset by financial swaps: for a physical sale the offset is a swap purchase and for a physical purchase the offset is a swap sale. +F- 16 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the location and fair value amounts of our derivative instruments on the balance sheets as of December 31, 2010 and 2009. +Fair Value As of December 31, +Derivatives instruments not designated as hedges (1): +Balance sheet line item +2010 +2009 +(in thousands) +Derivative assets: (2) +Current +Commodity contracts +Related to natural gas and crude oil sales +Fair value of derivatives +$ +41,068 +$ +39,107 +Related to natural gas marketing +Fair value of derivatives +1,811 +3,077 +Basis protection contracts +Related to natural gas marketing +Fair value of derivatives +74 +39 +42,953 +42,223 +Non Current +Commodity contracts +Related to natural gas and crude oil sales +Fair value of derivatives +44,381 +19,680 +Related to natural gas marketing +Fair value of derivatives +46 +530 +Basis protection contracts +Related to natural gas marketing +Fair value of derivatives +37 +18 +44,464 +20,228 +Total derivative assets +$ +87,417 +$ +62,451 +Derivative liabilities: (3) +Current +Commodity contracts +Related to natural gas and crude oil sales +Fair value of derivatives +$ +12,312 +$ +2,451 +Related to natural gas marketing +Fair value of derivatives +1,492 +2,626 +Basis protection contracts +Related to natural gas and crude oil sales +Fair value of derivatives +16,187 +15,127 +Related to natural gas marketing +Fair value of derivatives +7 +4 +29,998 +20,208 +Non Current +Commodity contracts +Related to natural gas and crude oil sales +Fair value of derivatives +6,228 +7,572 +Related to natural gas marketing +Fair value of derivatives +30 +423 +Basis protection contracts +Related to natural gas and crude oil sales +Fair value of derivatives +30,386 +40,784 +36,644 +48,779 +Total derivative liabilities +$ +66,642 +$ +68,987 +__________ +(1) As of December 31, 2010 , and December 31, 2009, none of our derivative instruments were designated as hedges. +(2) Includes derivative positions that have been designated to our affiliated partnerships; accordingly, our accompanying balance sheets include a corresponding payable to our affiliated partnerships of $20.3 million and $13.4 million as of December 31, 2010 , and December 31, 2009, respectively, representing their proportionate share of the derivative assets. +(3) Includes derivative positions that have been designated to our affiliated partnerships; accordingly, our accompanying balance sheets include a corresponding receivable from our affiliated partnerships of $14.6 million and $21 million as of December 31, 2010 , and December 31, 2009, respectively, representing their proportionate share of the derivative liabilities. +F- 17 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the impact of our derivative instruments on our statements of operations. +Year Ended December 31, +2010 +2009 +2008 +Statement of operations line item +Reclassification +of Realized +Gains (Losses) +Included in Prior Periods +Unrealized +Realized and Unrealized +Gains +(Losses) For +the +Current +Period +Total +Reclassification +of Realized +Gains (Losses) +Included in Prior Periods +Unrealized +Realized and Unrealized +Gains +(Losses) For +the +Current +Period +Total +Reclassification +of Realized +Gains (Losses) +Included in Prior Periods +Unrealized +Realized and Unrealized +Gains +(Losses) For +the +Current +Period +Total +(in thousands) +Commodity price risk management gain (loss), net +Realized gains (losses) +$ +20,148 +$ +26,947 +$ +47,095 +$ +84,655 +$ +22,690 +$ +107,345 +$ +(549 +) +$ +10,036 +$ +9,487 +Unrealized gains (losses) +(20,148 +) +32,944 +12,796 +(84,655 +) +(32,743 +) +(117,398 +) +549 +117,802 +118,351 +Total commodity price risk management gain (loss), net (1) +$ +— +$ +59,891 +$ +59,891 +$ +— +$ +(10,053 +) +$ +(10,053 +) +$ +— +$ +127,838 +$ +127,838 +Sales from natural gas marketing +Realized gains (losses) +$ +2,390 +$ +3,991 +$ +6,381 +$ +4,798 +$ +3,744 +$ +8,542 +$ +1,447 +$ +(3,213 +) +$ +(1,766 +) +Unrealized gains (losses) +(2,390 +) +1,745 +(645 +) +(4,798 +) +1,295 +(3,503 +) +(1,447 +) +6,061 +4,614 +Total sales from natural gas marketing (2) +$ +— +$ +5,736 +$ +5,736 +$ +— +$ +5,039 +$ +5,039 +$ +— +$ +2,848 +$ +2,848 +Cost of natural gas marketing +Realized gains (losses) +$ +(1,905 +) +$ +(3,996 +) +$ +(5,901 +) +$ +(4,719 +) +$ +(4,127 +) +$ +(8,846 +) +$ +(898 +) +$ +3,996 +$ +3,098 +Unrealized gains (losses) +1,905 +(1,431 +) +474 +4,719 +(441 +) +4,278 +898 +(6,327 +) +(5,429 +) +Total cost of natural gas marketing (2) +$ +— +$ +(5,427 +) +$ +(5,427 +) +$ +— +$ +(4,568 +) +$ +(4,568 +) +$ +— +$ +(2,331 +) +$ +(2,331 +) +____________ +(1) Represents realized and unrealized gains and losses on derivative instruments related to natural gas and crude oil sales. +(2) Represents realized and unrealized gains and losses on derivative instruments related to natural gas marketing. +NOTE 5 - CONCENTRATION OF RISK +Accounts Receivable. The following table presents the components of accounts receivable, net. +As of December 31, +2010 +2009 +(in thousands) +Natural gas, NGL and crude oil sales +$ +27,730 +$ +19,527 +Derivative counterparties +2,020 +12,887 +Joint interest billings +12,142 +10,260 +Natural gas marketing +8,279 +9,297 +Other +4,493 +5,068 +Allowance for doubtful accounts +(686 +) +(548 +) +Accounts receivable, net +$ +53,978 +$ +56,491 +Our accounts receivable are primarily from purchasers of our natural gas, NGL and crude oil production, derivative counterparties and other third parties which own working interests in the properties that we operate. Inherent to our industry is the concentration of natural gas, NGL and crude oil sales to a few customers. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions. We record an allowance for doubtful accounts for receivables that we estimate to be uncollectible. In making our +F- 18 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +estimate, we consider, among other things, our historical write-offs and overall creditworthiness of our customers. Further, consideration is given to well production data for receivables related to well operations. It is reasonably possible that our estimate of uncollectible amounts will change periodically. As of December 31, 2010 , Suncor Energy Marketing, Inc. represented 13.7% of our accounts receivable balance. +Major Customers. The following table presents the individual customers constituting 10% or more of total revenues. +Percent of Total Revenues +Year Ended December 31, +Customer +2010 +2009 +2008 +Suncor Energy Marketing, Inc. +19.6 +% +18.6 +% +0.2 +% +Williams Production RMT Company +12.5 +% +16.1 +% +12.4 +% +DCP Midstream, LP +9.6 +% +11.9 +% +6.6 +% +Teppco Crude Oil, LLC +0.6 +% +2.1 +% +10.8 +% +Derivative Counterparties. A significant portion of our liquidity is concentrated in derivative instruments that enable us to manage a portion of our exposure to price volatility from producing natural gas and crude oil. These arrangements expose us to credit risk of nonperformance by our counterparties. We primarily use financial institutions, who are also major lenders in our credit facility agreement, as counterparties to our derivative contracts. To date, we have had no counterparty default losses. We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, the impact of the nonperformance of our counterparties on the fair value of our derivative instruments is not significant. +The following table presents the counterparties that expose us to credit risk as of December 31, 2010 , with regard to our derivative assets. +Fair Value of +Derivative Assets +Counterparty Name +As of December 31, 2010 +(in thousands) +JPMorgan Chase Bank, N.A. (1) +$ +39,914 +Crèdit Agricole CIB (1) +28,301 +Wells Fargo Bank, N.A. (1) +15,665 +Various (2) +3,537 +Total +$ +87,417 +________________________ +(1) Major lender in our credit facility, see Note 8. +(2) Represents a total of 16 counterparties, including two lenders in our credit facility. +NOTE 6 - PROPERTIES AND EQUIPMENT +As of December 31, +2010 +2009 +(in thousands) +Properties and equipment, net: +Natural gas and crude oil properties +Proved +$ +1,429,667 +$ +1,266,921 +Unproved +79,053 +36,858 +Total natural gas and crude oil properties +1,508,720 +1,303,779 +Pipelines and related facilities +34,262 +36,910 +Transportation and other equipment +32,410 +33,432 +Land and buildings +13,379 +14,699 +Construction in progress +42,128 +9,131 +1,630,899 +1,397,951 +Accumulated DD&A +(510,861 +) +(424,293 +) +Properties and equipment, net (1) +$ +1,120,038 +$ +973,658 +F- 19 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +__________ +(1) In 2010, as a result of the deconsolidation of and our change in ownership interest in PDCM, properties and equipment were reduced by $51.8 million, net of accumulated DD&A of $15.7 million, from December 31, 2009. See Note 15. +Suspended Well Costs +The following table presents the capitalized exploratory well costs pending determination of proved reserves and included in properties and equipment on the balance sheets. +2010 +2009 +2008 +(in thousands, except for number of wells) +Balance beginning of year, January 1 +$ +1,174 +$ +1,180 +$ +2,300 +Deconsolidation of PDCM and change in ownership interest +(462 +) +— +— +Additions to capitalized exploratory well costs +pending the determination of proved reserves +4,353 +10,226 +15,644 +Reclassifications to wells, facilities and equipment +based on the determination of proved reserves +(2,231 +) +(9,914 +) +(10,259 +) +Capitalized exploratory well costs charged to expense +(537 +) +(318 +) +(6,505 +) +Balance end of year, December 31 +$ +2,297 +$ +1,174 +$ +1,180 +Number of wells pending determination at December 31 +3 +2 +6 +As of December 31, 2010 , none of the three suspended wells awaiting the determination of proved reserves have been capitalized for a period greater than one year after the completion of drilling. +NOTE 7 - INCOME TAXES +The table below presents the components of tax expense (benefit) from continuing operations for the years presented. +Year Ended December 31, +2010 +2009 +2008 +(in thousands) +Current: +Federal +$ +(1,119 +) +$ +(29,071 +) +$ +172 +State +947 +312 +(4,258 +) +Total current income taxes +(172 +) +(28,759 +) +(4,086 +) +Deferred: +Federal +3,990 +(11,546 +) +57,637 +State +(2,626 +) +(4,749 +) +3,786 +Total deferred income taxes +1,364 +(16,295 +) +61,423 +Income tax provision (benefit) from continuing operations +$ +1,192 +$ +(45,054 +) +$ +57,337 +For the years ended December 31, 2010 , 2009 and 2008, we elected to currently expense approximately $8.5 million, $80 million and $30 million, respectively, of intangible drilling costs ("IDC"). We also continued to utilize other tax deferral strategies such as statutory bonus and accelerated depreciation, special partnership formation statutes and regulations and Internal Revenue Code ("IRC") Section 1031 like-kind exchange ("LKE") strategies to reduce our current tax expense, resulting in a correspondingly higher deferred tax expense. As a result of these elections and deferral strategies, we have generated a federal tax loss, which may be carried back to 2008. This benefit is reflected in the 2010 current federal provision. The Worker, Homeownership, and Business Assistance Act of 2009 increased the statutory carry-back from two years to five years for losses incurred in 2008 and 2009. We carried back our 2009 tax loss to the 2005 and 2006 tax years, generating a benefit of $25.9 million, which was received in the second quarter of 2010. The benefit is reflected in the 2009 current federal provision. +F- 20 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents a reconciliation of the statutory rate to the effective tax rate. +Year Ended December, 31, +2010 +2009 +2008 +Statutory tax rate +35.0 +% +35.0 +% +35.0 +% +State income tax, net +1.6 +% +3.3 +% +3.1 +% +Percentage depletion +(9.3 +)% +0.5 +% +(0.7 +)% +Non-deductible compensation +3.6 +% +0.1 +% +— +% +State deferred rate change (discrete) +(21.6 +)% +(0.9 +)% +(0.6 +)% +Unrecognized tax benefits +2.0 +% +0.7 +% +0.3 +% +State tax credits +(2.7 +)% +0.3 +% +(0.2 +)% +2007-2009 federal return examination adjustments +3.9 +% +— +% +— +% +Non-decuctible expenditures - PDCM +— +% +(1.8 +)% +— +% +Other +2.2 +% +(1.2 +)% +(1.8 +)% +Effective tax rate +14.7 +% +36.0 +% +35.1 +% +The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2010 and 2009, are presented below. +As of December 31, +2010 +2009 +(in thousands) +Deferred tax assets: +Allowance for lease impairment +$ +5,502 +$ +5,751 +Provision for underpayment of natural gas sales +2,711 +1,130 +Deferred compensation +3,986 +3,277 +Asset retirement obligations +6,716 +5,189 +State NOL and tax credit carryforwards, net +4,624 +4,664 +Percentage depletion - carryforward +2,422 +811 +Alternative minimum tax - credit carryforward +2,069 +— +Dry hole costs +1,707 +— +Other +2,247 +1,657 +Total gross deferred tax assets +31,984 +22,479 +Less valuation allowance +— +(747 +) +Deferred tax assets +31,984 +21,732 +Deferred tax liabilities: +Properties and equipment +(171,795 +) +(170,161 +) +Investment in PDCM +(31,149 +) +(23,935 +) +Unrealized gains - derivatives +(3,082 +) +(230 +) +Convertible debt +(7,873 +) +— +Future state liabilities +— +(270 +) +Total gross deferred tax liabilities +(213,899 +) +(194,596 +) +Net deferred tax liability +$ +(181,915 +) +$ +(172,864 +) +Classification in the Consolidated Balance Sheets: +Prepaid expenses and other current assets +$ +6,084 +$ +5,148 +Deferred income taxes +(187,999 +) +(178,012 +) +Net deferred tax liability +$ +(181,915 +) +$ +(172,864 +) +Deferred tax liabilities for properties and equipment increased in 2010, primarily as a result of our election to expense $8.5 million of IDC for income tax purposes, and also due to our continued utilization of statutory provisions for bonus and accelerated tax depreciation. In addition, the application of LKE provisions to our sale of Michigan properties resulted in a $6.5 million of tax deferral. The remaining 2010 increase in total deferred tax liabilities was primarily due to the deferred tax liability for the equity component of our convertible debt and an increase in our deferred liability associated with our joint venture investment due to additional tax losses incurred by PDCM. +F- 21 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +As of December 31, 2010, we have state NOL carryforwards of $3.3 million that begin to expire beginning in 2029, and state credit carryforwards of $1.3 million that begin to expire in 2020. +In assessing whether a valuation allowance for the deferred tax assets should be recorded, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible or tax credits become utilizable. Based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible or utilizable, we have not recorded any valuation allowance as of December 31, 2010. The amount of the deferred tax asset considered realizable, however, could be reduced in the near term if estimates of future taxable income during the carry-forward period are reduced. +The following table presents a reconciliation of the total amounts of unrecognized tax benefits. +2010 +2009 +2008 +(in thousands) +Balance beginning of year, January 1 +$ +566 +$ +1,271 +$ +888 +Additions for tax positions of prior years +253 +43 +216 +Additions for tax positions of current year +274 +7 +167 +Reductions due to settlements +— +(406 +) +— +Reductions due to lapse of statute of limitations +— +(349 +) +— +Balance end of year, December 31 +$ +1,093 +$ +566 +$ +1,271 +Interest and penalties related to uncertain tax positions are recognized in income tax expense. Accrued interest and penalties related to uncertain tax positions were immaterial for each of the years in the three-year period ended December 31, 2010 . The total amount of unrecognized tax benefits that would affect the effective tax rate, if recognized, was $1 million as of December 31, 2010 and $0.6 million as of December 31, 2009. As of December 31, 2010 , it is reasonably possible that the unrecognized tax benefit could decrease up to $1 million in the next twelve months due to the conclusion of the current IRS examination and the lapse of an applicable statute of limitation. +The IRS is currently conducting an examination of our 2007 through 2009 tax years and an examination of the 2010 tax year in accordance with the Compliance Assurance Process ("CAP"). The CAP audit employs a real-time review of our books and tax records by the IRS that is intended to permit issue resolution prior to the filing of the tax returns. The examinations are expected to be completed in 2011. The statute of limitation for most of our state tax jurisdictions is open from 2006 forward. +NOTE 8 - LONG-TERM DEBT +Long-term debt consists of the following: +As of December 31, +2010 +2009 +(in thousands) +Senior notes +3.25% Convertible senior notes due 2016: +Principal amount +$ +115,000 +$ +— +Unamortized discount +(20,252 +) +— +3.25% Convertible senior notes due 2016, net of discount +94,748 +— +12% Senior notes due 2018: +Principal amount +203,000 +203,000 +Unamortized discount +(2,053 +) +(2,343 +) +12% Senior notes due 2018, net of discount +200,947 +200,657 +Total senior notes +295,695 +200,657 +Credit facility +— +80,000 +Total long-term debt +$ +295,695 +$ +280,657 +F- 22 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Senior Notes +3.25% Convertible Senior Notes Due 2016. In November 2010, including the overallotment option that allowed the underwriters to purchase an additional principal amount of $15 million, we issued $115 million of 3.25% convertible senior notes due 2016 in a private placement to qualified institutional buyers pursuant to Rule 144A of the Securities Act of 1933, as amended ("Securities Act"). The convertible notes and the common stock issuable upon conversion of the convertible notes, if any, have not been registered under the Securities Act or any state securities laws, nor are we required to register such convertible notes or common shares. The convertible notes are governed by an indenture dated November 23, 2010, between the Company and the Bank of New York Mellon, as trustee. The maturity for the payment of principal is May 15, 2016. Interest at the rate of 3.25% per year is payable in cash semiannually in arrears on each May 15 and November 15, commencing on May 15, 2011. The convertible notes are senior, unsecured obligations and rank senior in right of payment to our existing and future indebtedness that is expressly subordinated in right of payment to the convertible notes; equal in right of payment to our existing and future unsecured indebtedness that is not so subordinated (including our 12% senior notes due 2018); effectively junior in right of payment to any of our secured indebtedness (including our obligations under our senior secured credit facility) to the extent of the value of the assets securing such indebtedness; and structurally junior to all existing and future indebtedness (including trade payables) incurred by our subsidiaries. +The convertible notes will be convertible prior to November 15, 2015, only upon specified events and during specified periods and, thereafter, at any time, in each case at an initial conversion rate of 23.5849 per $1,000 principal amount of the convertible notes, which is equal to a conversion price of approximately $42.40 per share. The conversion rate is subject to adjustment upon certain events. Upon conversion, the convertible notes may be settled, at our election, in shares of our common stock, cash or a combination of cash and shares of our common stock. We have initially elected a net-settlement method to satisfy our conversion obligation, which allows us to settle the $1,000 principal amount of the convertible notes in cash and to settle the excess conversion value in shares, as well as cash in lieu of fractional shares. +We may not redeem the convertible notes prior to the maturity date of the convertible notes. If we undergo a fundamental change, as defined in the indenture, subject to certain conditions, holders of the convertible notes may require us to repurchase for cash all or part of the convertible notes at a repurchase price equal to 100% of the principal amount of the convertible notes to be repurchased, plus any accrued and unpaid interest to, but excluding, the fundamental change repurchase date. +We allocated the gross proceeds of the convertible notes between the liability and equity components of the debt. The initial $94.3 million liability component was determined based on the fair value of similar debt instruments excluding the conversion feature for similar terms and priced on the same day we issued our convertible notes. The initial $20.7 million equity component represents the debt discount and was calculated as the difference between the fair value of the debt and the gross proceeds of the convertible notes. As of December 31, 2010, the unamortized debt discount will be amortized over the remaining contractual term to maturity of the convertible notes of 5.4 years using an effective interest rate of 7.4%. For 2010, interest expense related to the indebtedness and the amortization of the discount were $0.4 million and $0.5 million, respectively. As of December 31, 2010, notwithstanding the inability to convert, assuming conversion, the value of the convertible notes did not exceed the principal amount. +12% Senior Notes Due 2018. In 2008, we issued $203 million of 12% senior notes due 2018 in a private placement. The notes have not been registered under the Securities Act or any state securities laws, nor are we required to register such notes. The notes are governed by an indenture dated February 8, 2008, between the Company and the Bank of New York, as trustee, as supplemented by the first supplement indenture dated said date. The maturity for the payment of principal is February 15, 2018. Interest at the rate of 12% per year is payable in cash semiannually in arrears on each February 15 and August 15. The senior notes were issued at a discount, 98.572% of the principal amount. The notes are senior unsecured obligations and rank, in right of payment, equally with all of our existing and future senior unsecured indebtedness and senior to any of our existing and future subordinated indebtedness. The notes are effectively subordinated to any of our existing or future secured indebtedness to the extent of the assets securing such indebtedness. +The indenture governing the notes contains customary representations and warranties as well as typical restrictive covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: (a) incur additional debt, (b) make certain investments or pay dividends or distributions on our capital stock or purchase or redeem or retire capital stock, (c) sell assets, including capital stock of our restricted subsidiaries, (d) pay dividends or other payments by restricted subsidiaries, (e) create liens that secure debt, (f) enter into transactions with affiliates, and (g) merge or consolidate with another company. Additionally, we are subject to two incurrence covenants: 1) earnings before interest, taxes, DD&A expense and capital expenditures ("EBITDAX") of at least two times interest expense and 2) total debt of less than 4.0 times EBITDAX. We were in compliance with all covenants as of December 31, 2010 , and expect to remain in compliance throughout the next year. +The notes are not initially guaranteed by any of our subsidiaries. However, subsidiaries may be obligated to guarantee the notes if a subsidiary becomes a guarantor under our senior credit facility and the subsidiary has consolidated tangible assets that constitute 10% or more of our consolidated tangible assets. Subject to specified exceptions, any subsidiary guarantor will be restricted from entering into certain transactions including the disposition of all or substantially all of its assets or merging with or into another entity. Subsidiary guarantors may be released from a guarantee under circumstances specified in the indenture. As of December 31, 2010 , none of our subsidiaries were obligated as guarantors of our senior notes. +F- 23 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The indenture provides that at any time, which may be more than once, before February 15, 2011, we may redeem up to 35% of the outstanding notes with proceeds from one or more equity offerings at a redemption price of 112% of the principal amount of the notes redeemed, plus accrued and unpaid interest, as long as at least 65% of the aggregate principal amount of the notes issued on February 8, 2008, remains outstanding after each such redemption and the redemption occurs within 180 days after the closing of the equity offering. As of the date of issuance of these financial statements, this provision expired without any redemptions having occurred. +The indenture provides that we may, at our option, redeem all or part of the notes at any time prior to February 15, 2013, at the make-whole price set forth in the indenture, and on or after February 15, 2013, at fixed redemption prices, plus accrued and unpaid interest, if any, to the date of redemption. Further, the indenture provides that upon a change of control, we must give holders of the notes the opportunity to put their notes to us for repurchase at a repurchase price of 101% of the principal amount, plus accrued and unpaid interest. +Bank Credit Facilities +Corporate Credit Facility. Prior to November 5, 2010, we operated under a secured credit facility dated as of November 4, 2005, as amended last on December 18, 2009, with an aggregate revolving commitment of $305 million and was due to expire on May 22, 2012. This credit facility was replaced on November 5, 2010, with a new credit facility. Our senior secured credit facility dated as of November 5, 2010, amended last on December 22, 2010, has an initial aggregate revolving commitment or borrowing base of $321.2 million. The maximum allowable facility amount is $600 million. The credit facility is with certain commercial lending institutions and is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes, and to support letters of credit. +Our credit facility borrowing base is subject to size redetermination semiannually based on a quantification of our reserves at December 31 and June 30 and is also subject to a redetermination upon the occurrence of certain events. The borrowing base of the credit facility will be the loan value assigned to the proved reserves attributable to our and our subsidiaries’ natural gas and crude oil interests. The credit facility is secured by a pledge of the stock of certain of our subsidiaries, mortgages of certain producing natural gas and crude oil properties and substantially all of our and such subsidiaries’ other assets. Neither PDCM nor the various limited partnerships for which we have sponsored and continue to serve as the managing general partner are guarantors of the credit facility. +Our outstanding principal amount accrues interest at a varying interest rate that fluctuates with an alternate base rate (equal to the greater of JPMorgan Chase Bank, N.A.'s prime rate, the federal funds rate plus a premium and 1-month LIBOR plus a premium), or at our election, a rate equal to the rate for dollar deposits in the London interbank market for certain time periods. Additionally, commitment fees, interest margin and other bank fees, charged as a component of interest, vary with our utilization of the facility. No principal payments are required until the credit agreement expires on November 5, 2015, or in the event that the borrowing base would fall below the outstanding balance. +The credit facility contains covenants customary for agreements of this type, including, but not limited to, limitations on our ability to: (a) incur additional indebtedness and guarantees, (b) create liens and other encumbrances on our assets, (c) consolidate, merge or sell assets, (d) pay dividends and other distributions, (e) make certain investments, loans and advances, (f) enter into sale/leaseback transactions, and (g) engage in hedging activities unless certain requirements are satisfied. The credit facility also requires us to execute and deliver specified mortgages and other evidences of security and to deliver specified opinions of counsel and other evidences of title. Further, we are required to comply with certain financial tests and maintain certain financial ratios on a quarterly basis. The financial tests and ratios include requirements to: (a) maintain a minimum current ratio, as defined per credit facility, of 1.00 to 1.00 and (b) not exceed a maximum leverage ratio of 4.25 to 1.00 through December 31, 2011, and 4.00 to 1.00 thereafter. +We have outstanding an $18.7 million irrevocable standby letter of credit in favor of a third party transportation service provider to secure the construction of certain additions and/or replacements to its facilities to provide firm transportation of the natural gas produced by us and others for whom we market their production in the West Virginia and Southwestern Pennsylvania areas. The letter of credit reduces the amount of available funds under our credit facility by an equal amount. We pay a fronting fee of 0.125% per annum and an additional quarterly maintenance fee equivalent to the spread over Eurodollar loans (2.0% per annum as of December 31, 2010 ) for the period the letter of credit remains outstanding. The letter of credit expires on May 22, 2012. +As of December 31, 2010 , we had no outstanding draws on our credit facility compared to $80 million as of December 31, 2009. We pay a fee of 0.5% per annum on the unutilized commitment on our available funds under our credit facility. As of December 31, 2010 , the available funds under our credit facility were $302.5 million. The weighted average borrowing rate on our credit facility, exclusive of the letter of credit, was 4.9% and 4.1% in 2010 and 2009, respectively. We were in compliance with all covenants at December 31, 2010 , and expect to remain in compliance throughout the next year. +PDCM Credit Facility. PDCM has a credit facility dated as of April 30, 2010, with an initial borrowing base of $10 million. The maximum allowable facility amount is $100 million. PDCM is required to pay a commitment fee of 0.5% per annum on the unutilized portion of the activated credit facility. Based upon PDCM's discretion, interest accrues at either an alternative base rate ("ABR") or an adjusted LIBOR. The ABR is the greater of BNP Paribas' prime rate, the federal funds effective rate plus 0.5% or the adjusted LIBOR for a three month interest period plus 1%. ABR and adjusted LIBOR borrowings are assessed an additional margin based upon the outstanding balance as a percentage of the available balance. ABR borrowings are assessed an additional margin of 1.5% to 2.25%. Adjusted LIBOR borrowings are assessed an additional margin spread of 2.5% to 3.25%. No principal payments are required until the credit agreement expires on April 30, 2014, or in the event that the borrowing base would fall below the outstanding balance. The credit facility is subject to and secured by +F- 24 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +PDCM's properties, with no recourse to us. The credit facility borrowing base is subject to size redetermination semiannually based upon a quantification of PDCM's reserves at December 31 and June 30; further, either PDCM or the lenders may request a redetermination upon the occurrence of certain events. Pursuant to the interests of the joint venture, the credit facility will be utilized by PDCM for the exploration and development of its Appalachian assets. +The credit facility contains covenants customary for agreements of this type, including, but not limited to, limitations on PDCM's ability to: (a) incur additional indebtedness and guarantees, (b) create liens and other encumbrances on their assets, (c) consolidate, merge or sell assets, (d) pay dividends and other distributions, (e) make certain investments, loans and advances, (f) enter into sale/leaseback transactions, and (g) engage in hedging activities unless certain requirements are satisfied. The credit facility also requires PDCM to execute and deliver specified mortgages and other evidences of security and to deliver specified opinions of counsel and other evidences of title. Further, PDCM is required to comply with certain financial tests and maintain certain financial ratios, as defined by the credit facility, on a quarterly basis. The financial tests and ratios include requirements to: (a) maintain a minimum current ratio of 1.0 to 1.0, (b) not to exceed a debt to EBITDAX ratio of 3.5 to 1.0 and (c) maintain a minimum interest coverage ratio of 2.5 to 1.0. +As of December 31, 2010, there were no amounts outstanding related to this credit facility and PDCM was in compliance with all covenants. +NOTE 9 - ASSET RETIREMENT OBLIGATIONS +The following table presents the changes in carrying amounts of the asset retirement obligations associated with our working interest in natural gas and crude oil properties. +2010 +2009 +(in thousands) +Balance beginning of year, January 1 +$ +29,564 +$ +23,086 +Deconsolidation of PDCM and change in ownership interest +(6,564 +) +— +Obligations incurred with development activites and assumed with acquisitions +4,549 +883 +Accretion expense +1,423 +1,368 +Obligations discharged with disposal of properties and asset retirements +(925 +) +(52 +) +Revisions in estimated cash flows +— +4,279 +Balance end of year, December 31 (1) +28,047 +29,564 +Less current portion +(250 +) +(250 +) +Long-term portion +$ +27,797 +$ +29,314 +__________ +(1) Includes $0.2 million and $1 million as of December 31, 2010 and 2009, respectively, related to assets held for sale. +NOTE 10 - EMPLOYEE BENEFIT PLANS +We sponsor a qualified retirement plan covering substantially all of our employees. The plan consists of both a traditional and a Roth 401(k) component as well as a profit sharing component. The 401(k) components enable eligible employees to contribute a portion of their compensation through payroll deductions in accordance with specific guidelines. We provide a discretionary matching contribution based on a percentage of the employees' contributions up to certain limits. Our contribution to the profit sharing component is discretionary. Our total combined expense for plan in 2010, 2009 and 2008, was $2.6 million, $1.7 million and $1.9 million, respectively. +We provide a supplemental retirement benefit of deferred compensation under terms of the various employment agreements with certain executive officers. During 2010, 2009 and 2008, we charged $0.2 million, $0.3 million and $0.2 million, respectively, related to this plan to general and administrative expenses. As of December 31, 2010 and 2009, the liability related to this benefit was $2.3 million and $2.4 million, respectively, which was included in other liabilities on the balance sheets, with the exception of $0.3 million included in other accrued expenses as of December 31, 2010 and 2009. +We offer a supplemental health care benefit covering certain former executive officers and their spouses in accordance with each officer's employment agreement. Expenses incurred during 2010, 2009 and 2008 related to this plan were immaterial. As of December 31, 2010 and 2009, included in other liabilities on the balance sheets was a related liability of $0.6 million and $0.5 million, respectively. +We maintain a non-qualified deferred compensation plan for our non-employee directors. The amount of compensation deferred by each participant is based on participant elections. The amounts deferred pursuant to the plan are invested in our common stock, maintained in a rabbi trust and are classified in the balance sheets as treasury shares as a component of shareholders' equity. The plan may be settled in either cash or shares as requested by the participant. As of December 31, 2010 and 2009, the liability related to this plan was $0.1 million and $0.2 million, respectively, which was included in other liabilities on the balance sheets. +F- 25 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 11 - COMMITMENTS AND CONTINGENCIES +Merger Agreements. In November 2010, we entered into separate merger agreements with each of PDC 2005-A Limited Partnership, PDC 2005-B Limited Partnership and the Rockies Region Private Limited Partnership ("2005 Partnerships"). Pursuant to each merger agreement, if the merger is approved by the holders of a majority of the limited partnership units held by limited partners of that partnership not owned by us (the "investor partners"), as well as the satisfaction of other customary closing conditions, then the applicable partnership will merge with and into us. If all three partnerships are acquired, we will pay an aggregate of approximately $43.3 million for the limited partnership units of the investor partners of these partnerships. Definitive proxy statements for each of the partnerships requesting approval from the applicable investor partners for, among other things, the merger agreements were mailed to investors on February 7, 2011. The special meetings whereby investor partners will have an opportunity to vote and approve the applicable merger agreement are currently scheduled for March 25, 2011, for each of the partnerships. Funding for these acquisitions is expected to be provided through the utilization of our corporate credit facility. +Drilling Rig Contract. In order to secure the services of a drilling rig, PDCM entered into a commitment with a drilling contractor for the services of a drilling rig. The commitment expires in October 2012. As of December 31, 2010, our proportionate share of PDCM's related maximum commitment was $6.6 million,. +Firm Transportation Agreements. We have entered into contracts that provide firm transportation, sales and processing charges on pipeline systems through which we transport or sell our natural gas and the natural gas of working interest owners, PDCM, our affiliated partnerships and other third parties. These contracts require us to pay these transportation and processing charges whether the required volumes are delivered or not. Satisfaction of the volumes requirements include volumes produced by us, volumes purchased from third parties, volumes produced by our joint venture and affiliated partnerships; however, all shortfalls are borne by us. As of December 31, 2010, we have a liability in the amount of $3.1 million included in other liabilities on the balance sheet related to an agreement in our Piceance Basin. We are currently working with the third party to renegotiate the terms and timing of our volume requirements under this agreement. If we are not able to renegotiate this agreement or meet all expected future volumes, an additional liability may result. +The following table presents gross volume information related to our long-term firm sales, processing and transportation agreements for pipeline capacity. These agreements require a demand charge whether volumes are delivered or not. We record in our financial statements only our share of costs based upon our working and net revenue interest in the wells. If the volumes below are not met, we will bear all costs related to the volume shortfall. +Year Ending December 31, +Area +2011 +2012 +2013 +2014 +2015 +Through +Expiration +Total +Expiration +Date +Volume (MMcf) +Piceance +32,288 +32,786 +30,458 +25,116 +71,610 +192,258 +May 31, 2021 +Appalachian Basin (1) +4,054 +9,551 +16,287 +16,287 +120,633 +166,812 +August 31, 2022 +NECO +3,650 +1,825 +1,825 +1,825 +3,650 +12,775 +December 31, 2016 +Total +39,992 +44,162 +48,570 +43,228 +195,893 +371,845 +Dollar commitment +(in thousands) +$ +19,724 +$ +21,667 +$ +23,987 +$ +21,183 +$ +92,400 +$ +178,961 +_____________ +(1) +Includes a precedent agreement that becomes effective when the planned pipeline is placed in service, currently estimated to be 2012 and represents 10,629 MMcf of the total MMcf presented for each of the years ending December 31, 2013 and 2014, and 81,536 MMcf thereafter. This agreement will be null and void if the pipeline is not completed. In August 2009, we issued a letter of credit related to this agreement, see Note 8. +Litigation. The Company is involved in various legal proceedings that it considers normal to its business. The Company reviews the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in the best interests of the Company. There are no assurances that settlements can be reached on acceptable terms or that adverse judgments, if any, in the remaining litigation will not exceed the amounts reserved. +Royalty Owner Class Action +Gobel et al v. Petroleum Development Corporation, Case No. 09-C-40 in U. S. District Court, Northern District of West Virginia, filed on January 27, 2009 +David W. Gobel, individually and allegedly as representative of all royalty owners in the Company's West Virginia oil and gas wells, filed a lawsuit against the Company alleging that we failed to properly pay royalties (the "Gobel lawsuit"). The allegations state that the Company improperly deducted certain charges and costs before applying the royalty percentage. Punitive damages are requested in addition to breach of contract, tort and fraud allegations. On August 31, 2010, the federal judge issued an order remanding the case to state +F- 26 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +court. On October 27, 2010, the state court set a trial date of April 2012. The Company and the plaintiff have been engaged in settlement discussions. In 2010, the Company recorded a charge to natural gas, NGL and crude oil sales in the statement of operations of $3.3 million. As of December 31, 2010, the Company has a total accrual of $6.2 million related to this suit. Given the inherent uncertainty in actions of this nature, the Company is unable to predict the ultimate outcome of this case at this time; however, it could result in a loss in excess of the amount accrued. +We are involved in various other legal proceedings that we consider normal to our business. Although the results cannot be known with certainty, we believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position, results of operations or liquidity. +Environmental. Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures to avoid environmental contamination and mitigate the risks from environmental contamination. We conduct periodic reviews to identify changes in our environmental risk profile. Liabilities are accrued when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. As of December 31, 2010, we have accrued environmental liabilities in the amount of $1.7 million included in other accrued liabilities on the balance sheet. We are not aware of any environmental claims existing as of December 31, 2010, which have not been provided for or would otherwise have a material impact on our financial statements. However, there can be no assurance that current regulatory requirements will not change or unknown past non-compliance with environmental laws will not be discovered on our properties. +In July 2008, the Company self-reported to the Colorado Department of Public Health and Environment (the "CDPHE") certain non-compliance with air laws at a compressor station in the Piceance Basin. The CDPHE subsequently initiated a review and inspection of air compliance at this station. In November and December 2009, the Company received related compliance advisories for alleged non-compliance. On May 27, 2010, we entered into a settlement agreement providing for a civil penalty of $163,000, which was accrued in periods prior to settlement and paid in the second quarter of 2010. +In December 2008, we received a Notice of Violation/Cease and Desist Order (the "Notice") from the CDPHE, related to the stormwater permit for the Garden Gulch Road. The Company manages this private road for Garden Gulch LLC. The Company is one of eight users of this road, all of which are natural gas and oil companies operating in the Piceance region of Colorado. Operating expenses, including this fine, if any, are allocated among the users of the road based upon their respective usage. The Notice alleges a deficient and/or incomplete stormwater management plan, failure to implement best management practices and failure to conduct required permit inspections. The Notice requires corrective action and states that the recipient shall cease and desist such alleged violations. The Notice states that a violation could result in civil penalties up to $10,000 per day. In 2009, the Company submitted responses and entered into negotiations with the CDPHE regarding this notice. In November 2010, the Company entered into a settlement for a total of $160,920, a portion of which was provided directly to a local municipality for a supplemental environmental project. The $160,920 was paid in January 2011. +Partnership Repurchase Provision. Substantially all of our drilling programs contain a repurchase provision where investing partners may request that we purchase their partnership units at any time beginning with the third anniversary of the first cash distribution. The provision provides that we are obligated to purchase an aggregate of 10% of the initial subscriptions per calendar year (at a minimum price of four times the most recent 12 months' cash distributions from production), if repurchase is requested by investors, subject to our financial ability to do so. As of December 31, 2010 , the maximum annual repurchase obligation for 2011, based upon the minimum price described above, was approximately $7.1 million. We believe we have adequate liquidity to meet this obligation. During 2010 , 2009 and 2008, we paid $0.6 million, $1.7 million and $1.8 million, respectively, under this provision for the repurchase of partnership units. +Lease Agreements. We entered into operating leases principally for the leasing of natural gas compressors, office space in Denver and Bridgeport, and general office equipment. The following table presents the minimum future lease payments under the non-cancelable operating leases as of December 31, 2010 . +Year Ending December 31, +2011 +2012 +2013 +2014 +2,015 +Thereafter +Total +(in thousands) +Minimum Lease Payments +$ +2,226 +$ +1,900 +$ +1,697 +$ +1,508 +$ +1,469 +$ +13 +$ +8,813 +Operating lease expense for the years ended December 31, 2010 , 2009 and 2008, was $4.9 million, $4.3 million and $2.6 million, respectively. +Employment Agreements with Executive Officers. We have employment agreements with our Chief Executive Officer, Chief Financial Officer and other executive officers. The employment agreements provide for annual base salaries, eligibility for performance bonus compensation and other various benefits, including retirement and severance benefits. +F- 27 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +If within two years following a change of control of the Company ("change in control period") either the Company terminates the executive officer without cause or the executive officer terminates employment for good reason, then the severance benefits owed equals two or three times, specific to the executive officer, the sum of the executive's highest annual base salary during the previous two years of employment immediately preceding the termination date and the executive's highest annual bonus paid or payable during the same two-year period. For one executive, in this calculation, the target bonus will be used as the minimum value for the first two years of employment. Where the Company terminates the executive officer without cause or the executive officer terminates employment for good reason outside of the change in control period, the severance benefits also range from two times to three times the benefits noted above. For this purpose, a change of control and good reason correspond to the respective definitions of change of control and good reason under Section 409A of the Internal Revenue Code of 1986 (IRC) and the supporting treasury regulations, with some differences. Under any of the above circumstances, the executive officer is also entitled under his employment agreement to (i) vesting of any unvested equity compensation (excluding all long-term performance shares), (ii) reimbursement for any unpaid expenses, (iii) retirement benefits earned under the current and/or previous agreements, (iv) continued coverage under our medical plan for the federal COBRA health continuation coverage period and (v) payment of any earned and unpaid bonus amounts. In addition, the executive officer is entitled to receive any benefits that he would have otherwise been entitled to receive under our qualified retirement plan, although those benefits are not increased or accelerated. +In the event that an executive officer is terminated for just cause, we are required to pay the executive officer his base salary through the termination date plus a partial year bonus; incentive, deferred, retirement or other compensation; and to provide any other benefits, which have been earned or become payable as of the termination date. +In the event that an executive officer voluntarily terminates his employment for other than good reason, he is entitled to receive (i) his base salary and bonus, provided, however, that with respect to the bonus, for certain executive officers, there will be no proration of the bonus if such executive leaves prior to the last day of the year and, with respect to the remaining executive officers, there will be no proration of the bonus in the event such executive officer leaves prior to March 31 in the year of his termination, (ii) any incentive, deferred or other compensation which has been earned or has become payable, but which has not yet been paid under the schedule originally contemplated in the agreement under which they were granted, (iii) any unpaid expense reimbursement upon presentation by the executive officer of an accounting of such expenses in accordance with our normal practices and (iv) any other payments for benefits earned under the employment agreement or our plans. +In the event of death or disability, the executive is entitled to receive certain benefits. For this purpose, the definition of "disability" corresponds to the definition under IRC 409A and the supporting treasury regulations. The benefits will (i) in the case of death be equal to the base salary that would otherwise have been paid for a six-month period following the termination date and (ii) in the case of disability be up to thirteen weeks of ongoing base salary plus a lump sum equal to six months of base salary. +Partnership Casualty Losses. As Managing General Partner of 29 partnerships, we have liability for potential casualty losses in excess of the partnership assets and insurance. We believe the casualty insurance coverage that we and our subcontractors carry is adequate to meet this potential liability. +NOTE 12 - COMMON STOCK +Sale of Equity Securities +The following offerings were made pursuant to an effective shelf registration statement on Form S-3 filed with the SEC on November 26, 2008, and declared effective on January 30, 2009. +• +In November 2010, we sold 4,140,000 shares of our common stock in an underwritten public offering at a price of $32.00 per share. The net proceeds of $125.5 million are being used, together with other proceeds, to fund an acquisition of additional assets in the Wolfberry Trend in the Permian Basin of West Texas, which closed in November 2010; our acquisition of the 2004 partnerships, which closed in December 2010 for $34.8 million, and will be used for the anticipated acquisition of the 2005 partnerships and other acquisitions and for general corporate purposes. Pending such uses, we applied the net proceeds from this offering and other proceeds to temporarily repay the entire outstanding amount under our credit facility, with the remaining balance being deposited in an interest bearing account and held as cash and cash equivalents until utilized as contemplated above. +• +In August 2009, we sold 4,312,500 shares of our common stock in an underwritten public offering at a price of $12.00 per share. We used the net proceeds of $48.5 million to pay down our credit facility and for general corporate purposes. +Stock-Based Compensation Plans +2010 Long-Term Equity Compensation Plan. In June 2010, our shareholders approved a long-term equity compensation plan for our employees and non-employee directors (the "2010 Plan"). In accordance with the 2010 Plan, up to 1,400,000 new shares of our common stock are authorized for issuance. Shares issued may be either authorized but unissued shares, treasury shares or any combination of these shares. Additionally, the 2010 Plan permits the reuse or reissuance of shares of common stock which were canceled, expired, forfeited or, in the case of stock appreciation rights ("SARs"), paid out in the form of cash. Awards may be issued to our employees in the form of stock options, SARs, restricted stock, restricted stock units ("RSUs"), performance shares and performance units and to our non-employee directors in the form of non-qualified stock options, SARs, restricted stock and RSUs. Awards may vest over periods set at the discretion of the +F- 28 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Compensation Committee of our Board of Directors (the "Compensation Committee") with certain minimum vesting periods. With regard to options and SARs, awards have a maximum exercisable period of ten years. In no event may an award be granted under the 2010 Plan on or after April 1, 2020. As of December 31, 2010, 1,181,288 shares remain available for issuance pursuant to the 2010 Plan. +Other Long-Term Equity Compensation Plan. As approved by the shareholders in June 2004, we maintain a long-term equity compensation plan for our officers and certain key employees (the "2004 Plan"). Awards pursuant to the plan vest over periods set at the discretion of the Compensation Committee and, with regard to options, have a maximum exercisable period of ten years. We also maintain a restricted stock plan for our non-employee directors approved by the shareholders in June 2005 (the "2005 Plan"). As of December 31, 2010, shares remaining available for issuance pursuant to these plans were de minimis and we have no intent to issue such shares. As of December 31, 2010, there were no awards outstanding pursuant to the 2005 Plan. All outstanding and non-vested awards pursuant to the 2004 Plan will continue to be outstanding and vest pursuant to their original terms on or before April 19, 2020. +The following table presents summary data related to our outstanding stock-based compensation plans. +Year Ended December 31, +2010 +2009 +2008 +(in thousands) +Total stock-based compensation +$ +5,314 +$ +5,935 +$ +6,702 +Income tax benefit +(2,019 +) +(2,277 +) +(2,557 +) +Net income (loss) impact +$ +3,295 +$ +3,658 +$ +4,145 +Stock Option Awards +We have granted stock options pursuant to various stock compensation plans. Outstanding options expire ten years from the date of grant and become exercisable ratably over a four year period. We have not issued any new stock options awards since 2006. As of December 31, 2010, all compensation cost related to stock options has been fully recognized in our statement of operations. +The following table presents the changes in our stock option awards for the year ended December 31, 2010 . +Number of +Shares +Underlying +Options +Weighted +Average +Exercise +Price +Per Share +Weighted +Average +Remaining +Contractual +Term +(years) +Outstanding at December 31, 2009 +10,306 +$ +41.90 +6 +Outstanding at December 31, 2010 +10,306 +41.90 +5 +Vested and expected to vest at December 31, 2010 +10,306 +41.90 +5 +Exercisable at December 31, 2010 +10,306 +41.90 +5 +As of/Year Ended December 31, +2010 +2009 +2008 +(in thousands, except market price) +Total intrinsic value of options exercised +$ +— +$ +— +$ +659 +Total intrinsic value of options outstanding +18 +— +— +Total intrinsic value of options exercisable +18 +— +— +Market price per common share as of December 31 +42.25 +18.21 +24.07 +SARs +In April 2010, our Compensation Committee granted SARs to our executive officers. The SARs will vest over a three-year period and may be exercised at any point after vesting through April 2020. Pursuant to the terms of the awards, upon exercise, the executives will receive in shares of common stock the excess of the market price of the award on the date of exercise over the market price of the award on the date of issuance. +F- 29 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The fair value of each SAR award was estimated on the date of grant using a Black-Scholes pricing model using the assumptions presented in the table below. The expected life of the award was estimated using historical stock option exercise behavior data. The risk-free interest rate was based on the U.S. Treasury yields approximating the expected life of the award in effect at the time of grant. Expected volatilities were based on our historical volatility. We do not expect to pay dividends, nor do we expect to declare dividends in the foreseeable future. +Year Ended +December 31, 2010 +Expected term of the award +5 years +Risk-free interest rate +2.5 +% +Volatility +62.0 +% +Weighted average grant date fair value per share +$ +13.26 +The following table presents the changes in our SARs for the year ended December 31, 2010 . +Number of +Shares +Underlying +SARs +Grant Date Market Price +Per Share +Average Remaining Contractual +Term +(in years) +Aggregate Intrinsic +Value +(in thousands) +Outstanding at December 31, 2009 +— +$ +— +— +$ +— +Awarded +57,282 +24.44 +9.3 +— +Outstanding at December 31, 2010 +57,282 +24.44 +9.3 +1,020 +Vested and expected to vest at December 31, 2010 +51,554 +24.44 +9.3 +918 +Exercisable at December 31, 2010 +— +— +— +— +The total compensation cost related to SARs granted and not yet recognized in our statement of operations as of December 31, 2010, was $0.5 million. The cost is expected to be recognized over a weighted average period of 2.3 years. +Restricted Stock Awards +Time-Based Awards. The fair value of the time-based awards is amortized ratably over the requisite service period, generally over three or four years, and, in connection with a one-time grant to executive officers in March 2008, five years . Time-based awards for non-employee directors prior to 2010 generally vested on July 1 of the year following the date of the grant. Non-employee director awards pursuant to the 2010 Plan vest ratably over three years. +The following table presents the changes in non-vested time-based awards for the year ended December 31, 2010 . +Shares +Weighted Average +Grant-Date +Fair Value +Non-vested at December 31, 2009 +305,328 +$ +27.55 +Granted +367,641 +25.04 +Vested +(125,646 +) +28.65 +Forfeited +(21,608 +) +27.60 +Non-vested at December 31, 2010 +525,715 +25.53 +F- 30 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +As of/Year Ended December 31, +2010 +2009 +2008 +(in thousands, except per share data) +Total intrinsic value of time-based awards vested +$ +3,219 +$ +1,731 +$ +6,710 +Total intrinsic value of time-based awards non-vested +22,211 +5,560 +5,249 +Market price per common share as of December 31 +42.25 +18.21 +24.07 +Weighted average grant date fair value per share +25.04 +14.02 +57.64 +The total compensation cost related to non-vested time-based awards expected to vest and not yet recognized in our statements of operations as of December 31, 2010 , was $9.5 million. This cost is expected to be recognized over a weighted average period of 2.4 years. +Market-Based Awards. The fair value of the market-based awards is amortized ratably over the requisite service period, primarily three years. Generally, the market-based shares vest if the participant is continuously employed throughout the performance period and certain per share price thresholds are attained as of the last day of each performance period, with a maximum vesting period of five years. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. +The weighted average grant date fair value per market-based share, including shares modified in 2008 pursuant to agreements with our former president and our former chief executive officer, was computed using the Monte Carlo pricing model using the weighted average assumptions presented in the table below. +Year Ended December 31, +2009 +2008 +Expected term of award +3 years +3 years +Risk-free interest rate +2.0 +% +2.7 +% +Volatility +59.0 +% +45.6 +% +Weighted average grant date fair value per share +$ +6.47 +$ +43.61 +For 2009, expected volatility was based on a blend of our historical and implied volatility and, for 2008, was based on our historical volatility. The expected lives of the awards were based on the requisite service period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant or modification and extrapolated to approximate the life of the award. We do not expect to pay dividends, nor do we expect to declare dividends in the foreseeable future. +There were 79,550 shares of non-vested market-based awards, with a weighted average grant-date fair value of $32.52 per share, outstanding as of December 31, 2010 and 2009. There was no activity related to these shares during 2010. The total compensation cost related to non-vested market-based awards expected to vest and not yet recognized in our statement of operations as of December 31, 2010 , was immaterial. This cost is expected to be recognized over a weighted average period of one year. +Treasury Share Purchases +Treasury shares purchased pursuant to our non-employee director deferred compensation plan are purchased in the open market at fair value and held in a rabbi trust. +Pursuant to our stock-based compensation plans, we purchase shares from employees for their payment of tax liabilities related to the vesting of securities. Shares are purchased at fair market value based on the closing price on the date of purchase and subsequently retired. +In 2006, our Board approved a purchase program authorizing us to purchase up to 10% (1,477,109 shares) of our then outstanding common stock through April 2008. Stock purchases under this program were made in 2007 and 2008 in the open market or in private transactions, at times and in amounts that we deemed appropriate. Total shares purchased pursuant to the purchase program were 76,283 common shares at a cost of $5 million ($65.73 average price paid per share), including 68,943 shares from our executive officers at a cost of $4.6 million ($67.22 price paid per share). The authorization to purchase the remaining 1,400,826 shares effectively expired on April 30, 2008. All shares purchased in accordance with the program were subsequently retired. +Pursuant to our senior notes indenture executed in February 2008, any future treasury purchases are restricted, see Note 8 . +F- 31 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Shareholders’ Rights Agreement +In 2007, we entered into a rights agreement. The rights agreement is designed to improve the ability of our Board to protect the interest of our shareholders in the event of an unsolicited takeover attempt. Our Board declared a dividend of one right for each outstanding share of our common stock. The right dividend was paid to shareholders of record on September 14, 2007. A "distribution date," as defined in the rights agreement, can occur after any individual shareholder exceeds 15% ownership of our outstanding common stock. After the occurrence of a "distribution date," the right entitles each registered holder (other than the acquiring shareholder who triggered the "distribution date"), to purchase shares of our common stock (or, in certain circumstances, cash, property or other securities) having a then-current value equal to two times the exercise price of the right (i.e., for the $240 exercise price, the rights holder receives $480 worth of common stock). The exercise price is subject to adjustment for various corporate actions which affect all shareholders, such as a stock split. The rights agreement and all rights will expire on September 11, 2017. +Preferred stock +We are authorized, pursuant to shareholder approval in 2008, to issue 50,000,000 shares of Company preferred stock, par value $0.01, which may be issued in one or more series, with such rights, preferences, privileges and restrictions as shall be fixed by our Board from time to time. As of December 31, 2010 , no preferred shares had been issued. +NOTE 13 - ASSETS HELD FOR SALE, DIVESTITURE AND DISCONTINUED OPERATIONS +Selected financial information related to assets held for sale, divested and discontinued operations . The tables below set forth selected financial and operational information related to net assets divested, net assets related to discontinued operations and operating results related to discontinued operations. Net assets held for sale represents the assets that were or are expected to be sold net of liabilities that were or are expected to be assumed by the purchaser. Net assets related to discontinued operations presents those assets that were or are expected to be sold less liabilities that were or are expected to be assumed by the purchaser, as well as all other related assets and liabilities, consisting of accounts receivable and production tax liability, which were not sold. While the reclassification of revenues and expenses related to discontinued operations for prior periods had no impact upon previously reported net earnings, the statement of operations and operational tables present the revenues, expenses and production volumes that were reclassified from the specified statement of operations line items to discontinued operations. +The following table presents statement of operations data related to our discontinued operations. +Year Ended December 31, +Statement of Operations - Discontinued Operations +2010 +2009 +2008 +(dollars in thousands) +Revenues +Natural gas, NGL and crude oil sales +$ +6,515 +$ +7,851 +$ +17,010 +Sales from natural gas marketing +3,328 +5,040 +11,248 +Natural gas and crude oil well drilling +— +193 +7,615 +Well operations, pipeline income and other +549 +951 +986 +Total revenues +10,392 +14,035 +36,859 +Costs, expenses and other +Production costs +2,358 +2,643 +4,155 +Cost of natural gas marketing +3,265 +4,916 +11,161 +Cost of natural gas and oil well drilling +— +— +1,068 +Exploration expense +25 +3,784 +497 +Impairment of proved natural gas and oil properties +4,666 +— +5,246 +Depreciation, depletion and amortization +1,819 +4,249 +3,197 +Total costs, expenses and other +12,133 +15,592 +25,324 +Income (loss) from discontinued operations +(1,741 +) +(1,557 +) +11,535 +Provision (benefit) for income taxes +(754 +) +(582 +) +4,122 +Income (loss) from discontinued operations, net of tax +$ +(987 +) +$ +(975 +) +$ +7,413 +Operational Data +Production +Natural gas (MMcf) +801.8 +1,446.4 +1,658.7 +Crude oil (MBbls) +42.5 +47.5 +24.7 +Natural gas equivalent (MMcfe) +1,057.0 +1,731.6 +1,806.6 +F- 32 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents balance sheet data related to assets held for sale. +As of December 31, +2010 +2009 +Balance Sheet +Net Assets Held for Sale (1) +Net Assets +Related to Discontinued Operations +Net Assets Held for Sale (1) +Net Assets +Related to Discontinued Operations +(in thousands) +Assets +Current assets +Accounts receivable, net +$ +— +$ +347 +$ +— +$ +1,499 +Total current assets +— +347 +— +1,499 +Properties and equipment, net +16,578 +16,578 +65,996 +65,996 +Accumulated DD&A +(11,387 +) +(11,387 +) +(31,461 +) +(31,461 +) +Total assets +$ +5,191 +$ +5,538 +$ +34,535 +$ +36,034 +Liabilities +Current liabilities +Production tax liability +$ +— +$ +— +$ +— +$ +37 +Total current liabilities +— +— +— +37 +Asset retirement obligation +199 +199 +957 +957 +Total liabilities +$ +199 +$ +199 +$ +957 +$ +994 +Net Assets +$ +4,992 +$ +5,339 +$ +33,578 +$ +35,040 +_____________ +(1) +See Note 9 for additional information regarding the asset retirement obligation related to assets held for sale and divested in July 2010. +Assets Held for Sale +North Dakota . During the fourth quarter of 2010, we developed a plan to divest and began marketing for sale our North Dakota assets. The assets include producing wells, undeveloped leaseholds and related facilities primarily located in Burke County. The plan received board approval and the sale is expected to occur within one year of approval. In December 2010, we executed a letter of intent with an unrelated third party, which provides for the sale of 100% of our North Dakota assets. On February 7, 2011, we executed a purchase and sale agreement with the same unrelated party and we expect the transaction to close early March 2011. Following the sale to the unrelated party, we will not have significant continuing involvement in the operations of or cash flows from these assets; accordingly, the North Dakota assets were reclassified as held for sale and the results of operations related to the those assets have been separately reported as discontinued operations in the consolidated financial statements for all periods presented. +Michigan . On July 30, 2010, we divested our Michigan asset group and related liabilities for net cash proceeds of $22 million and realized a loss on sale of $4.7 million in the form of an impairment charge recorded during the year ended 2010 (see Note 2 regarding the impairment charge). We do not have significant continuing involvement in the operations of or cash flows from this asset group. Accordingly, the Michigan assets were reclassified as held for sale and the results of operations related to the those assets have been separately reported as discontinued operations in the consolidated financial statements for all periods presented. +Natural Gas and Crude Oil Well Drilling Activities +We offered our last sponsored drilling partnership in October 2007. In January 2008, we first announced that we had no plans to sponsor a new drilling partnership in 2008 and this decision was upheld again in 2009. As of June 30, 2009, all remaining contractual drilling and completion obligations were completed for all partnerships. The unused advance for future drilling contracts of $1.7 million as of December 31, 2008, was fully utilized as of June 30, 2009, with $0.2 million recognized in revenue and $0.3 million refunded to the partnerships. +As all partnership well drilling and completion activities have been completed and we currently do not have any plans in the foreseeable future to sponsor a drilling partnership, we believe it was appropriate to treat our natural gas and crude oil well drilling activities as discontinued operation for all periods presented. Prior period financial statements have been restated to present the activities of our natural gas and crude oil well drilling operations as discontinued operations. +F- 33 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 14 - ACQUISITIONS +The following table presents the adjusted purchase price and the preliminary allocations thereof, based on our estimates of fair value, for the acquisition of natural gas and crude oil properties in the Permian Basin and the 2004 partnerships. +Permian Acquisitions +2004 Partnerships +November 2010 +July 2010 +December 2010 +(in thousands) +Cash consideration paid to seller +$ +39,364 +$ +74,650 +$ +34,768 +Payable to seller +— +259 +— +Total consideration for net assets +$ +39,364 +$ +74,909 +$ +34,768 +Recognized amounts of identifiable assets acquired and liabilities assumed: +Proved natural gas and oil properties +$ +18,063 +$ +27,529 +$ +32,730 +Unproved natural gas and oil properties +21,507 +50,140 +— +Fair value of derivative instruments +— +— +1,682 +Other assets +— +— +1,714 +Asset retirement obligation +(177 +) +(2,174 +) +(912 +) +Environmental liability +(29 +) +(586 +) +(126 +) +Other liabilities +— +— +(320 +) +Total identifiable net assets +$ +39,364 +$ +74,909 +$ +34,768 +Pro Forma Information . The results of operations for the above acquisitions have been included in our consolidated financial statements from the date of acquisition. The pro forma effect of their inclusion in our consolidated statement of operations of the results of operations of these assets as if the acquisitions had occurred as of January 1, 2009, are not presented as the pro forma results would not be materially different from the information presented in the accompanying statements of operations. +Permian Basin. In July 2010, we acquired various producing assets located in the Wolfberry oil trend in the Permian Basin in West Texas. In conjunction with the divestiture of our Michigan asset group we entered into a like-kind exchange agreement, in accordance with Internal Revenue Code Section 1031 ("IRC 1031"), with a qualified intermediary. The Wolfberry assets were identified as our replacement property in accordance with IRC 1031. Sales proceeds in the amount of $19.3 million from the Michigan divestiture were transferred directly to the qualified intermediary and used, along with $55.7 million from our credit facility, to fund our Wolfberry acquisition. The sale of our Michigan assets resulted in a gain for income tax purposes of $19.2 million, which then resulted in a tax liability of $7.3 million. With the favorable deferral aspects of IRC 1031, we were able to defer $6.5 million of this tax liability. +In November 2010, we acquired for $39.4 million in cash a second position in the Wolfberry oil trend including 100% of the interest in producing assets and undeveloped acreage. The assets included seven producing wells that are located on a primarily contiguous 5,760 net acre block. We believe that these Permian acquisitions will support our strategic goal of diversifying our commodity mix to include a larger percentage of liquids. +2004 Partnerships. In December 2010, we acquired the remaining working interest in four of our affiliated partnerships: PDC 2004-A Limited Partnership, PDC 2004-B Limited Partnership, PDC 2004-C Limited Partnership and PDC 2004-D Limited Partnership. We purchased these partnerships for an aggregate amount of $36.5 million, which includes $1.7 million paid to our unaffiliated partners for operating results between the valuation date and date of closing. These purchases included the remaining working interests in a total of 122 gross, 88.6 net, wells located in our Wattenberg and Grand Valley Fields. The acquisitions allow us the opportunity, assuming favorable capital and commodity markets, to accelerate the pace of refracturing the wells acquired, thus allowing us to optimize revenue opportunities. +F- 34 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 15 - NONCONTROLLING INTEREST IN SUBSIDIARIES +PDC Mountaineer, LLC +In October 2009, we entered into a joint venture arrangement to form PDCM. At that time, the joint venture was determined to be a variable interest entity due to the disproportionate voting rights compared to our ownership interest; accordingly, we consolidated 100% of the joint venture as we were the primary beneficiary as of and for the period ended December 31, 2009. As of January 1, 2010, pursuant to the adoption of new accounting changes related to variable interest entities (see Note 2), the joint venture was deconsolidated from 100% and proportionately consolidated at 67.4%, representing only our ownership interest. +The assets we contributed consist of (i) approximately 115,000 net acres in the Appalachian Basin, of which approximately 55,000 acres are in the Marcellus fairway, (ii) 12 MMcf per day of existing production from primarily the shallow Devonian sands and (iii) total proved reserves of 113 Bcfe, also from the shallow Devonian sands. With the exception of our capital contribution, we have not entered into any arrangement that would require us to provide financial support to the joint venture. Further, we are not liable for any debts, obligations and liabilities of the joint venture and its creditors have no recourse against our general credit in the event of default. None of our affiliated partnerships’ wells were included in the joint venture. +The following table presents the impact on our balance sheet resulting from the deconsolidation of PDCM on January 1, 2010. The changes below are non-cash items with the exception of the changes in cash and cash equivalents, which are reflected in the statement of cash flows. +As of January 1, 2010 +(decrease/(increase), in thousands) +Assets +Liabilities and Equity +Current assets +Current liabilities +Cash and and cash equivalents +$ +3,074 +Accounts payable +$ +813 +Accounts receivable, net +1,335 +Production tax liability +17 +Accounts receivable affiliates +(2,399 +) +Fair value of derivatives +434 +Fair value of derivatives +2 +Funds held for distribution +322 +Prepaid expenses and other current assets +131 +Other accrued expenses +— +Total current assets +2,143 +Total current liabilities +1,586 +Properties and equipment, net +51,765 +Fair value of derivatives +83 +Fair value of derivatives +70 +Asset retirement obligation +4,815 +Other assets +419 +Other liabilities +591 +Total assets +$ +54,397 +Total liabilities +7,075 +Shareholders' equity +— +Noncontrolling interest +47,322 +Total equity +47,322 +Total liabilities and equity +$ +54,397 +WWWV, LLC +In 2007, we contributed $0.8 million for a 50% interest in WWWV, LLC (the "LLC"), a limited liability company for which we serve as the managing member. The LLC's only asset is an aircraft and the LLC was formed for the purpose of owning and operating the aircraft. We consolidate the entity based on a controlling financial interest. In 2010, we commenced activities to divest the asset and dissolve the entity, which will not have a material impact on our financial statements. +NOTE 16 - TRANSACTIONS WITH AFFILIATES +Amounts due from/to the affiliated partnership are primarily related to derivative positions and, to a lesser extent, unbilled well lease operating expenses, and costs resulting from audit and tax preparation services. We enter into derivative instruments for our own production as well as for our 29 affiliated partnerships' production. As of December 31, 2010, we had a payable to affiliates of $20.3 million representing their designated portion of the fair value of our gross derivative assets and a receivable from affiliates of $14.6 million representing their designated portion of the fair value of our gross derivative liabilities. +F- 35 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Our natural gas marketing segment manages the marketing of natural gas for PDCM and our affiliated partnerships with production in the Appalachian Basin. Our sales from natural gas marketing include $0.7 million, $0.5 million and $1.5 million in 2010 , 2009 and 2008, respectively, related to the marketing of natural gas on behalf of PDCM and our affiliated partnerships. Our cost of natural gas marketing include $0.6 million, $0.5 million and $1.5 million for 2010 , 2009 and 2008, respectively, related to these sales. +We provide certain well operating and administrative services for PDCM. Amounts billed to PDCM for these services were $11.1 million in 2010. Our statements of operations include only our proportionate share of these billings: $3.9 million, $0.9 million and $1.9 million is reflected in production costs, exploration expense and general and administrative expense, respectively. +Through June 2009, we provided natural gas and crude oil well drilling services to our affiliated partnerships. As part of these services, we sold to them at cost the natural gas and crude oil leases upon which the wells were drilled. For the year ended December 31, 2008, we sold to our affiliated partnerships leases in the amount of $0.5 million. Further, we provide well operations and pipeline services to our affiliated partnerships. The majority of all of our revenue and expenses related to well operations and pipeline income are associated with services provided to our affiliated partnerships. See Note 13 for the natural gas and crude oil well drilling revenue recognized in 2009 and 2008. +NOTE 17 - BUSINESS SEGMENTS +We separate our operating activities into two segments: natural gas and crude oil sales and natural gas marketing. All material inter-company accounts and transactions between segments have been eliminated. +Natural Gas and Crude Oil Sales. Our natural gas and crude oil sales segment includes all of our natural gas and crude oil properties. The segment represents revenues and expenses from the production and sale of natural gas, NGL and crude oil. Segment revenue includes natural gas, NGL and crude oil sales, commodity price risk management, net and well operation and pipeline income. Segment income (loss) consists of segment revenue less production cost, exploration expense, impairment of proved natural gas and crude oil properties, direct general and administrative expense and DD&A expense. Segment DD&A expense was $105.9 million for 2010 , $123.2 million for 2009 and $98.9 million for 2008. +Natural Gas Marketing. Our natural gas marketing segment purchases, aggregates and resells natural gas produced by us and others. Segment income (loss) primarily represents sales from natural gas marketing and direct interest income less costs of natural gas marketing and direct general and administrative expense. +Unallocated amounts. Unallocated income includes unallocated other revenue less corporate general administrative expense, corporate DD&A expense, interest income and interest expense. +F- 36 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following tables present our segment information. +2010 +2009 +2008 +(in thousands) +Year Ended December 31, +Revenues: +Natural gas and crude oil sales +$ +278,576 +$ +171,262 +$ +443,193 +Natural gas marketing +69,071 +59,595 +129,015 +Unallocated +— +19 +293 +Total +$ +347,647 +$ +230,876 +$ +572,501 +Segment income (loss) before income taxes: +Natural gas and crude oil sales +$ +85,810 +$ +(34,382 +) +$ +229,772 +Natural gas marketing +1,063 +1,967 +1,242 +Unallocated +(78,760 +) +(92,757 +) +(67,846 +) +Total +$ +8,113 +$ +(125,172 +) +$ +163,168 +Expenditures for segment long-lived assets: +Natural gas and crude oil sales +$ +319,268 +$ +140,431 +$ +316,959 +Unallocated +1,506 +2,602 +6,194 +Total +$ +320,774 +$ +143,033 +$ +323,153 +As of December 31, +Segment assets: +Natural gas and crude oil sales +$ +1,313,805 +$ +1,117,625 +Natural gas marketing +16,338 +22,614 +Unallocated +53,701 +75,553 +Assets held for sale +5,191 +34,535 +Total +$ +1,389,035 +$ +1,250,327 +F- 37 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +SUPPLEMENTAL INFORMATION - UNAUDITED +NATURAL GAS AND CRUDE OIL INFORMATION - UNAUDITED +Net Proved Reserves +All of our natural gas, NGL and crude oil reserves are located in the U.S. We utilized the services of independent petroleum engineers to estimate our natural gas, crude oil, condensate and NGL reserves. As of December 31, 2010 , substantially all of our reserve estimates were based on reserve reports prepared by Ryder Scott Company, L.P. ("Ryder Scott"). For our Appalachian Basin reserves, our internal reserve engineers estimated approximately three percent of the total proved developed natural gas reserves and approximately one percent of total proved undeveloped natural gas reserves. For each of the years in the two-year period ended December 31, 2009, our reserve estimates for the Rocky Mountain Region and Fort Worth Basin were prepared by Ryder Scott and our reserve estimates for the Appalachian and Michigan Basins were based on reserve reports prepared by Wright & Company. These reserve estimates have been prepared in compliance with professional standards and the reserves definitions prescribed by the SEC. +Proved reserves estimates may change, either positively or negatively, as additional information becomes available and as contractual, economic and political conditions change. Our net proved reserve estimates have been adjusted as necessary to reflect all contractual agreements, royalty obligations and interests owned by others at the time of the estimate. Proved developed reserves are the quantities of natural gas, NGL and crude oil expected to be recovered through existing wells with existing equipment and operating methods. In some cases, proved undeveloped reserves may require substantial new investments in additional wells and related facilities. +The price used to estimate our reserves, by commodity, are presented below. +Price Used to Estimate Reserves +As of December 31, +Crude Oil +Natural Gas (1) +NGLs (1) +2010 (2) +$ +71.95 +$ +3.54 +$ +34.12 +2009 (2) +54.64 +3.17 +— +2008 (3) +37.85 +4.98 +— +__________ +(1) Prior to 2010, NGLs were included in natural gas, which impacts the comparability for 2010 to 2009 and 2008. +(2) For 2010 and 2009, represents a 12-month average price calculated as the unweighted arithmetic average of the price on the first day of each month, January through December. +(3) For 2008, represents the price in effect as of December 31 for the respective commodity. +F- 38 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +The following tables present the changes in our estimated quantities of proved reserves. +Natural Gas +(MMcf) +Crude Oil, Condensate and NGLs (MBbls) (1) +Total +(MMcfe) +Proved Reserves: +Proved reserves, January 1, 2008 +593,563 +15,338 +685,591 +Revisions of previous estimates +(25,216 +) +(1,538 +) +(34,444 +) +Extensions, discoveries and other additions +Rocky Mountain Region +100,323 +2,354 +114,447 +Appalachian Basin +24,875 +— +24,875 +Purchases of reserves +Rocky Mountain Region +1,712 +106 +2,348 +Appalachian Basin +83 +— +83 +Other +46 +— +46 +Dispositions +(769 +) +(63 +) +(1,147 +) +Production +(31,760 +) +(1,160 +) +(38,720 +) +Proved reserves, December 31, 2008 +662,857 +15,037 +753,079 +Revisions of previous estimates +(101,923 +) +2,957 +(84,181 +) +Extensions, discoveries and other additions +Rocky Mountain Region +79,574 +1,322 +87,506 +Appalachian Basin +3,190 +— +3,190 +Purchases of reserves +Rocky Mountain Region +648 +47 +930 +Appalachian Basin +59 +— +59 +Other +63 +— +63 +Dispositions +(7 +) +(1 +) +(13 +) +Production +(35,536 +) +(1,292 +) +(43,288 +) +Proved reserves, December 31, 2009 +608,925 +18,070 +717,345 +Revisions of previous estimates +6,504 +8,823 +59,442 +Extensions, discoveries and other additions +Rocky Mountain Region +56,524 +3,058 +74,872 +Appalachian Basin +35,092 +— +35,092 +Purchases of reserves +Rocky Mountain Region +15,781 +1,322 +23,713 +Permian Basin +5,139 +4,576 +32,595 +Appalachian Basin +220 +— +220 +Dispositions +(43,690 +) +(55 +) +(44,020 +) +Production +(27,189 +) +(1,909 +) +(38,643 +) +Proved reserves, December 31, 2010 +657,306 +33,885 +860,616 +__________ +(1) +Prior to 2010, NGLs were included in natural gas, which impacts the comparability for 2010 to 2009 and 2008. In 2010, NGLs represented 7.4% of total proved reserves. +Proved Developed Reserves, as of: +January 1, 2008 +286,570 +5,219 +317,884 +December 31, 2008 +297,041 +5,438 +329,669 +December 31, 2009 +258,375 +6,244 +295,839 +December 31, 2010 +227,341 +12,300 +301,141 +Proved Undeveloped Reserves, as of: +January 1, 2008 +306,993 +10,119 +367,707 +December 31, 2008 +365,816 +9,599 +423,410 +December 31, 2009 +350,550 +11,826 +421,506 +December 31, 2010 +429,965 +21,585 +559,475 +F- 39 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +Developed +Undeveloped +Total +(MMcfe) +Beginning proved reserves, January 1, 2009 +329,669 +423,410 +753,079 +Undeveloped reserves transferred to developed +14,952 +(14,952 +) +— +Revisions of previous estimates +(943 +) +(83,238 +) +(84,181 +) +Extensions, discoveries and other additions +(5,163 +) +95,859 +90,696 +Purchases of reserves +625 +427 +1,052 +Dispositions +(13 +) +— +(13 +) +Production +(43,288 +) +— +(43,288 +) +Ending proved reserves, December 31, 2009 +295,839 +421,506 +717,345 +Undeveloped reserves transferred to developed +17,967 +(17,967 +) +— +Revisions of previous estimates +16,782 +42,660 +59,442 +Extensions, discoveries and other additions +21,572 +88,392 +109,964 +Purchases of reserves +28,728 +27,800 +56,528 +Dispositions +(41,104 +) +(2,916 +) +(44,020 +) +Production +(38,643 +) +— +(38,643 +) +Ending proved reserves, December 31, 2010 +301,141 +559,475 +860,616 +2010 Activity. In 2010, we revised our previous estimate of proved reserves upward by 59.4 Bcfe. The revision was primarily due to an increase of 55.6 Bcfe due to asset performance, 35.9 Bcfe due to higher commodity pricing, 28.1 Bcfe due to the impact of evaluating NGLs as a separate stream and 1.5 Bcfe due to interest adjustments. This was partially offset by a decrease of 58.7 Bcfe due to adjustments for reserve decreases for geological reasons or reclassification of prior period proved undeveloped reserves to probable reserves due to aging and 3 Bcfe due to increased operating costs. New discoveries and extensions of 110 Bcfe in 2010 are due to drilling of 213 gross wells and the addition of new proved undeveloped reserves: 35.1 Bcfe were added in the Appalachian Basin and 74.9 Bcfe were added in the Rocky Mountain Region (29.4 Bcfe in Wattenberg Field, 36.2 Bcfe in Grand Valley Field, 9.1 Bcfe in the NECO area and 0.2 Bcfe in North Dakota) and West Texas. We acquired 56.5 Bcfe of proved reserves, approximately 32.6 Bcfe through two acquisitions in the Permian Basin and 23.9 Bcfe in the Rocky Mountains and the Appalachian basin due to the repurchase of the 2004 Partnerships as well as the purchase of interest in some of our other existing properties. Of the 23.9 Bcfe, 12.8 Bcfe were acquired in the Wattenberg Field, 10.9 Bcfe were acquired in the Piceance Basin with the remaining 0.2 Bcfe split between the Appalachian Basin and North Dakota. Total dispositions of 44 Bcfe in 2010 includes the deconsolidation of PDCM, or 28.9 Bcfe, and the sale of all of our Michigan assets, or 15.1 Bcfe, to an unaffiliated third party. +2009 Activity. In 2009, we revised our previous estimate of proved reserves downward by 84.2 Bcfe. The revision was primarily due to a decrease of 99.5 Bcfe due to lower commodity pricing and 45.1 Bcfe due to adjustments to reserves removed or reclassified due to new rules limiting proved undeveloped reserves locations to those scheduled to be drilled within the next five years. The downward adjustments were partially offset by an increase of 41.4 Bcfe due to decreased operating costs, 1 Bcfe due to interest adjustments and 17.9 Bcfe due to asset performance. New discoveries and extensions of 90.7 Bcfe in 2009 were due to drilling of 100 gross wells and the addition of new proved undeveloped reserves: 3.2 Bcfe in the Appalachian Basin and 87.5 Bcfe in the Rocky Mountain Region (13.7 Bcfe in Wattenberg Field, 73.3 Bcfe in Grand Valley Field, and 0.5 Bcfe in North Dakota). We acquired 1.1 Bcfe of proved reserves through the purchase of interest in some of our existing properties. We acquired reserves primarily in the Wattenberg Field with the remaining reserves split between the Appalachian Basin, Michigan Basin, Piceance Basin and North Dakota. We sold a minimal amount of reserves to unaffiliated third parties in the Wattenberg Field. +2008 Activity. In 2008, we revised our previous estimate of proved reserves downward by 34.4 Bcfe. The revision was primarily due to a decrease of 50 Bcfe due to lower commodity prices, 25.8 Bcfe due to increased operating costs, and 14.4 Bcfe due to adjustments to proved undeveloped reserve values, partially offset by an increase of 55.8 Bcfe due to asset performance. New discoveries and extensions of 139.3 Bcfe in 2008 were due to drilling of 229 net wells and the addition of new proved undeveloped reserves: 24.9 Bcfe in the Appalachian Basin and 114.4 Bcfe in the Rocky Mountain Region (26.6 Bcfe in the Wattenberg Field, 80 Bcfe in Grand Valley Field, and 7.8 Bcfe in NECO and other areas). We acquired 2.5 Bcfe of proved reserves through the purchases of interest in some of our existing properties. We acquired reserves primarily in the Wattenberg Field with the remaining reserves being split between the Appalachian, Michigan, and Piceance Basins, the NECO area and North Dakota. We sold proved reserves of 1.1 Bcfe to unaffiliated third parties and to our sponsored partnerships for drilling activity. +F- 40 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +Results of Operations for Natural Gas and Crude Oil Producing Activities +The results of operations for natural gas and crude oil producing activities are presented below. The results include activities related to both continuing and discontinued operations and exclude activities related to natural gas marketing and well operations and pipeline services. +Year Ended December 31, +2010 +2009 +2008 +(in thousands) +Revenue: +Natural gas, NGL and crude oil sales +$ +216,159 +$ +179,093 +$ +321,877 +Commodity price risk management gain (loss), net +59,891 +(10,053 +) +127,838 +276,050 +169,040 +449,715 +Expenses: +Production costs +61,544 +57,825 +72,518 +Exploration expense +20,291 +21,961 +32,280 +DD&A expense +103,303 +125,415 +100,207 +Impairment of proved natural gas and oil properties +4,666 +926 +12,825 +189,804 +206,127 +217,830 +Results of operations for natural gas and crude oil producing +activities before provision for income taxes +86,246 +(37,087 +) +231,885 +Provision (benefit) for income taxes +5,925 +(13,355 +) +81,577 +Results of operations for natural gas and crude oil producing activities, excluding corporate overhead and interest costs +$ +80,321 +$ +(23,732 +) +$ +150,308 +Production costs include those costs incurred to operate and maintain productive wells and related equipment, including costs such as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance and production and severance taxes. In addition, production costs include administrative expenses and depreciation applicable to support equipment associated with these activities. DD&A expense includes those costs associated with capitalized acquisition, exploration and development costs, but does not include the depreciation applicable to support equipment. The provision for income taxes is computed using effective tax rates. +Costs Incurred in Natural Gas and Crude Oil Property Acquisition, Exploration and Development Activities +Costs incurred in natural gas and crude oil property acquisition, exploration and development are presented below. +Year Ended December 31, +2010 +2009 +2008 +(in thousands) +Acquisition of properties: (1) +Proved properties +$ +87,241 +$ +2,251 +$ +6,147 +Unproved properties +84,636 +5,867 +6,890 +Development costs (2) +138,018 +72,416 +257,656 +Exploration costs: (3) +Exploratory drilling +21,223 +18,317 +26,499 +Geological and geophysical +2,367 +1,788 +2,121 +Total costs incurred +$ +333,485 +$ +100,639 +$ +299,313 +__________ +(1) +Property acquisition costs - represent costs incurred to purchase, lease or otherwise acquire a property. +(2) +Development costs - represents costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells, recompletions and to provide facilities to extract, treat, gather and store natural gas, NGLs and crude oil. Of these costs incurred for the years ended December 31, 2010 , 2009 and 2008, $37.4 million, $44.4 million and +$66 million, respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end. +(3) +Exploration costs - represents costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing natural gas, NGL and crude oil reserves. +F- 41 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +Capitalized Costs Related to Natural Gas and Crude Oil Producing Activities +Aggregate capitalized costs related to natural gas and crude oil exploration and production activities with applicable accumulated DD&A are presented below: +As of December 31, +2010 +2009 +(in thousands) +Proved natural gas and crude oil properties (1) +$ +1,481,191 +$ +1,329,666 +Unproved natural gas and crude oil properties +85,502 +38,626 +1,566,693 +1,368,292 +Less accumulated DD&A +492,501 +428,754 +$ +1,074,192 +$ +939,538 +__________ +(1) As of December 31, 2010, we had no capitalized proved undeveloped natural gas and crude oil properties disclosed as such for longer than 5 years. +Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves +Presented in the following table is information with respect to the standardized measure of discounted future net cash flows relating to proved reserves. +As of December 31, +2010 +2009 +2008 +(in thousands) +Future estimated cash flows +$ +4,361,095 +$ +2,915,377 +$ +3,867,461 +Future estimated production costs +(1,418,044 +) +(1,088,337 +) +(1,325,362 +) +Future estimated development costs +(1,119,604 +) +(825,139 +) +(1,100,533 +) +Future estimated income tax expense +(508,805 +) +(237,790 +) +(384,676 +) +Future net cash flows +1,314,642 +764,111 +1,056,890 +10% annual discount for estimated timing of cash flows +(826,224 +) +(416,475 +) +(700,085 +) +Standardized measure of discounted future estimated net cash flows +$ +488,418 +$ +347,636 +$ +356,805 +Future cash inflows are computed by applying prices used in estimating the entity's proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the statutory rate in effect at the end of each year to the future pretax net cash flows, less the tax basis of the properties and gives effect to permanent differences, tax credits and allowances related to the properties. +F- 42 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +The following table presents the principal sources of change in the standardized measure of discounted future estimated net cash flows. +Year Ended December 31, +2010 +2009 +2008 +(in thousands) +Sales of natural gas, NGL and crude oil production, net of production costs +$ +(163,104 +) +$ +(136,568 +) +$ +(261,692 +) +Net changes in prices and production costs +180,124 +(107,766 +) +(479,894 +) +Extensions, discoveries, and improved recovery, less related costs +88,637 +30,851 +80,859 +Sales of reserves +(24,174 +) +(21 +) +(2,012 +) +Purchase of reserves +45,538 +1,266 +4,280 +Development costs incurred during the period +44,491 +40,603 +88,008 +Revisions of previous quantity estimates +47,884 +(46,226 +) +(79,536 +) +Changes in estimated income taxes +(105,557 +) +38,371 +239,054 +Net changes in future development costs +(41,595 +) +101,765 +(87,625 +) +Accretion of discount +35,951 +49,434 +122,409 +Timing and other +32,586 +19,122 +(20,117 +) +Total +$ +140,781 +$ +(9,169 +) +$ +(396,266 +) +It is necessary to emphasize that the data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein. +QUARTERLY FINANCIAL INFORMATION - UNAUDITED +Quarterly financial data for the years ended December 31, 2010 and 2009, is presented below. The sum of the quarters may not equal the total of the year's net income or loss per share attributable to shareholders due to changes in the weighted average shares outstanding throughout the year. +F- 43 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +2010 +Quarter Ended +March 31 +June 30 +September 30 +December 31 +Year Ended +(in thousands, except per share data) +Revenues: +Natural gas, NGL and crude oil sales +$ +57,827 +$ +48,729 +$ +47,295 +$ +55,793 +$ +209,644 +Sales from natural gas marketing +22,687 +12,589 +18,337 +15,458 +69,071 +Commodity price risk management gain (loss), net +43,222 +12,257 +19,029 +(14,617 +) +59,891 +Well operations, pipeline income and other +2,589 +2,148 +2,159 +2,145 +9,041 +Total revenues +126,325 +75,723 +86,820 +58,779 +347,647 +Costs, expenses and other: +Production costs +14,961 +16,004 +16,524 +19,328 +66,817 +Cost of natural gas marketing +22,323 +12,207 +18,300 +15,185 +68,015 +Exploration expense +6,418 +3,830 +3,712 +6,306 +20,266 +General and administrative expense +10,694 +9,855 +10,426 +11,213 +42,188 +Depreciation, depletion and amortization +27,458 +26,945 +28,024 +26,816 +109,243 +Gain on sale of leaseholds +— +(96 +) +(57 +) +(21 +) +(174 +) +Total costs, expenses and other +81,854 +68,745 +76,929 +78,827 +306,355 +Income (loss) from operations +44,471 +6,978 +9,891 +(20,048 +) +41,292 +Interest income +5 +34 +21 +11 +71 +Interest expense +(7,800 +) +(7,672 +) +(8,174 +) +(9,604 +) +(33,250 +) +Income (loss) from continuing operations before income taxes +36,676 +(660 +) +1,738 +(29,641 +) +8,113 +Provision (benefit) for income taxes +13,804 +(238 +) +(1,156 +) +(11,218 +) +1,192 +Income (loss) from continuing operations +22,872 +(422 +) +2,894 +(18,423 +) +6,921 +Income (loss) from discontinued operations, net of tax +797 +(2,313 +) +460 +69 +(987 +) +Net income (loss) +23,669 +(2,735 +) +3,354 +(18,354 +) +5,934 +Less: net loss attributable to noncontrolling interests +(55 +) +(6 +) +(5 +) +(214 +) +(280 +) +Net income (loss) attributable to shareholders +$ +23,724 +$ +(2,729 +) +$ +3,359 +$ +(18,140 +) +$ +6,214 +Amounts attributable to Petroleum Development Corporation shareholders: +Income (loss) from continuing operations +$ +22,927 +$ +(416 +) +$ +2,899 +$ +(18,209 +) +$ +7,201 +Income (loss) from discontinued operations, net of tax +797 +(2,313 +) +460 +69 +(987 +) +Net income (loss) attributable to shareholders +$ +23,724 +$ +(2,729 +) +$ +3,359 +$ +(18,140 +) +$ +6,214 +Earnings (loss) per share attributable to shareholders: +Basic +Income (loss) from continuing operations +$ +1.19 +$ +(0.03 +) +$ +0.15 +$ +(0.86 +) +$ +0.37 +Income (loss) from discontinued operations +0.04 +(0.12 +) +0.02 +— +(0.05 +) +Net income (loss) attributable to shareholders +$ +1.23 +$ +(0.15 +) +$ +0.17 +$ +(0.86 +) +$ +0.32 +Diluted +Income (loss) from continuing operations +$ +1.19 +$ +(0.03 +) +$ +0.15 +$ +(0.86 +) +$ +0.36 +Income (loss) from discontinued operations +0.04 +(0.12 +) +0.02 +— +(0.05 +) +Net income (loss) attributable to shareholders +$ +1.23 +$ +(0.15 +) +$ +0.17 +$ +(0.86 +) +$ +0.31 +Weighted average common shares outstanding +Basic +19,191 +19,213 +19,250 +21,026 +19,674 +Diluted +19,287 +19,213 +19,406 +21,026 +19,821 +F- 44 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +2009 +Quarter Ended +March 31 +June 30 +September 30 +December 31 +Year Ended +(in thousands, except per share data) +Revenues: +Natural gas, NGL and crude oil sales +$ +37,884 +$ +39,745 +$ +42,050 +$ +51,563 +$ +171,242 +Sales from natural gas marketing +20,832 +11,306 +11,062 +16,395 +59,595 +Commodity price risk management gain (loss), net +23,683 +(23,284 +) +(13,813 +) +3,361 +(10,053 +) +Well operations, pipeline income and other +2,647 +2,771 +2,239 +2,435 +10,092 +Total revenues +85,046 +30,538 +41,538 +73,754 +230,876 +Costs, expenses and other: +Production costs +15,749 +13,643 +14,332 +18,379 +62,103 +Cost of natural gas marketing +20,346 +10,895 +10,179 +16,198 +57,618 +Exploration expense +5,640 +3,085 +2,469 +6,983 +18,177 +Impairment of proved natural gas and crude oil properties +— +— +926 +— +926 +General and administrative expense +12,094 +14,784 +9,627 +17,480 +53,985 +Depreciation, depletion and amortization +33,532 +32,610 +31,315 +29,298 +126,755 +Gain on sale of leaseholds +(120 +) +— +— +(350 +) +(470 +) +Total costs, expenses and other +87,241 +75,017 +68,848 +87,988 +319,094 +Loss from operations +(2,195 +) +(44,479 +) +(27,310 +) +(14,234 +) +(88,218 +) +Interest income +20 +12 +208 +14 +254 +Interest expense +(8,383 +) +(9,420 +) +(9,221 +) +(10,184 +) +(37,208 +) +Loss from continuing operations before income taxes +(10,558 +) +(53,887 +) +(36,323 +) +(24,404 +) +(125,172 +) +Benefit for income taxes +(4,355 +) +(20,635 +) +(13,469 +) +(6,595 +) +(45,054 +) +Loss from continuing operations +(6,203 +) +(33,252 +) +(22,854 +) +(17,809 +) +(80,118 +) +Income from discontinued operations, net of tax +484 +157 +(1,921 +) +305 +(975 +) +Net loss +(5,719 +) +(33,095 +) +(24,775 +) +(17,504 +) +(81,093 +) +Less: net loss attributable to noncontrolling interests +(16 +) +(16 +) +(299 +) +(1,485 +) +(1,816 +) +Net loss attributable to shareholders +$ +(5,703 +) +$ +(33,079 +) +$ +(24,476 +) +$ +(16,019 +) +$ +(79,277 +) +Amounts attributable to Petroleum Development Corporation shareholders: +Loss from continuing operations +$ +(6,187 +) +$ +(33,236 +) +$ +(22,555 +) +$ +(16,324 +) +$ +(78,302 +) +Income from discontinued operations, net of tax +484 +157 +(1,921 +) +305 +(975 +) +Net loss attributable to shareholders +$ +(5,703 +) +$ +(33,079 +) +$ +(24,476 +) +$ +(16,019 +) +$ +(79,277 +) +Earnings (loss) per share attributable to shareholders: +Basic +Loss from continuing operations +$ +(0.41 +) +$ +(2.24 +) +$ +(1.33 +) +$ +(0.85 +) +$ +(4.76 +) +Income from discontinued operations +0.03 +0.01 +(0.11 +) +0.01 +(0.06 +) +Net loss attributable to shareholders +$ +(0.38 +) +$ +(2.23 +) +$ +(1.44 +) +$ +(0.84 +) +$ +(4.82 +) +Diluted +Loss from continuing operations +$ +(0.41 +) +$ +(2.24 +) +$ +(1.33 +) +$ +(0.85 +) +$ +(4.76 +) +Income from discontinued operations +0.03 +0.01 +(0.11 +) +0.01 +(0.06 +) +Net loss attributable to shareholders +$ +(0.38 +) +$ +(2.23 +) +$ +(1.44 +) +$ +(0.84 +) +$ +(4.82 +) +Weighted average common shares outstanding +Basic +14,793 +14,811 +16,962 +19,172 +16,448 +Diluted +14,793 +14,811 +16,962 +19,172 +16,448 +F- 45 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +FINANCIAL STATEMENT SCHEDULE +Schedule II -VALUATION AND QUALIFYING ACCOUNTS +Description +Beginning +Balance +January 1 +Deconsolidation/Purchase Price Adjustment for PDCM +Charged to +Costs and +Expenses +Deductions (1) +Ending +Balance +December 31 +(in thousands) +2010: +Allowance for doubtful accounts +$ +548 +135 +$ +307 +$ +34 +$ +686 +Valuation allowance for state tax benefits +747 +— +— +747 +— +Valuation allowance for unproved natural gas and crude oil properties +15,001 +19 +6,120 +4,106 +16,996 +2009: +Allowance for doubtful accounts +$ +537 +— +$ +120 +$ +109 +$ +548 +Valuation allowance for state tax benefits +— +— +747 +— +747 +Valuation allowance for unproved natural gas and crude oil properties +12,870 +— +7,279 +5,148 +15,001 +2008: +Allowance for doubtful accounts +$ +357 +— +$ +180 +$ +— +$ +537 +Valuation allowance for unproved natural gas and crude oil properties +2,365 +— +12,798 +2,293 +12,870 +___ ____________ +(1) For allowance for doubtful accounts, deductions represent the write-off of accounts receivable deemed uncollectible. For allowance for unproved natural gas and crude oil properties, deductions represent accumulated amortization of expired or abandoned unproved natural gas and crude oil properties. For allowance for state tax benefits, deductions represent expired or unutilized state tax benefits. +F- 46 \ No newline at end of file diff --git a/raw/filings/0000077877/2010/0000077877-11-000011/filing_metadata.csv b/raw/filings/0000077877/2010/0000077877-11-000011/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..826f38f644f57e651001e1ca167e07d8e4bb9357 --- /dev/null +++ b/raw/filings/0000077877/2010/0000077877-11-000011/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 +0000077877,PDCE,"PDC ENERGY, INC.",10-K,2011-02-24,2010-12-31,2011-02-24T13:26:45.000Z,0000077877-11-000011,petrodev10kfy10.htm,PDC 2010 FORM 10-K,5257613,0,0,https://www.sec.gov/Archives/edgar/data/77877/000007787711000011/petrodev10kfy10.htm,https://www.sec.gov/Archives/edgar/data/77877/000007787711000011/,2010,2010,1 diff --git a/raw/filings/0000077877/2010/0000077877-11-000011/item1.txt b/raw/filings/0000077877/2010/0000077877-11-000011/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2010/0000077877-11-000011/item13.txt b/raw/filings/0000077877/2010/0000077877-11-000011/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..96387c74db6a9d1caea37cbfa54ed0a7b0f74f1a --- /dev/null +++ b/raw/filings/0000077877/2010/0000077877-11-000011/item13.txt @@ -0,0 +1,2 @@ +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE +The information called for by this Item is incorporated by reference from information under the captions entitled Certain Relationships and Related Transactions and Director Independence in our definitive proxy statement to be filed pursuant to Regulation 14A no later than 120 days after the close of our fiscal year. \ No newline at end of file diff --git a/raw/filings/0000077877/2010/0000077877-11-000011/item9a.txt b/raw/filings/0000077877/2010/0000077877-11-000011/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..207fb62b2a7e1b78fdfedcd4313221ff9b80afb8 --- /dev/null +++ b/raw/filings/0000077877/2010/0000077877-11-000011/item9a.txt @@ -0,0 +1,6 @@ +ITEM 9A. CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +As of December 31, 2010 , we carried out an evaluation under the supervision and with the participation of 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 pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e). Based on the results of this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2010 . +Changes in Internal Control over Financial Reporting +During the fourth quarter of 2010 , we made no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) that have materially affected or are reasonably likely to materially affect our internal control over financial reporting. +48 \ No newline at end of file diff --git a/raw/filings/0000077877/2010/0000077877-11-000011/rp_note.txt b/raw/filings/0000077877/2010/0000077877-11-000011/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2010/0000077877-11-000011/rpt_disclosure.txt b/raw/filings/0000077877/2010/0000077877-11-000011/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..d75457dccfc3579c597d0e622a3666da802c4a5f --- /dev/null +++ b/raw/filings/0000077877/2010/0000077877-11-000011/rpt_disclosure.txt @@ -0,0 +1,104 @@ +Under the related party transaction policy, a related person +transaction is a transaction or arrangement involving a related +person in which the Company is a participant or that would +require disclosure in the Company’s filings with the SEC as +a transaction with a related person. The related person must +disclose to the Audit Committee +27 +Table of Contents +any potential related person transactions and must disclose all +material facts with respect to such interest. All related person +transactions will be reviewed by the Audit Committee. In +determining whether to approve or ratify a transaction, the +Audit Committee will consider the relevant facts and +circumstances of the transaction, which may include factors such +as the relationship of the related person with the Company, the +materiality or significance of the transaction to the Company +and the business purpose and reasonableness of the transaction, +whether the transaction is comparable to a transaction that +could be available to the Company on an arms-length basis, and +the impact of the transaction on the Company’s business and +operations. +ADDITIONAL +INFORMATION +The Company files annual, quarterly and current reports, proxy +statements and other information with the SEC. Copies of the +Company’s filings with the SEC are available to the public +at the SEC’s website at +http://www.sec.gov . +These documents may also be viewed at the SEC’s public +reference room located at 100 F Street, N.E., +Washington, D.C. 20549. Please call the SEC at +1-800-SEC-0330 +for further information on the public reference room. +EXECUTIVE +OFFICERS +The current Named Executive Officers of the Company, their +principal occupations for the past five years and additional +information is set forth below. +Name +Age +Position(s) +Richard W. McCullough +59 +Chairman, Chief Executive Officer (“CEO”) and Director +Gysle R. Shellum +59 +Chief Financial Officer (“CFO”) +Barton R. Brookman +48 +Senior Vice President Exploration and Production +Daniel W. Amidon +50 +General Counsel and Secretary +Lance A. Lauck +48 +Senior Vice President Business Development +Richard W. McCullough. See +“Proposal No. 1 – Election of +Directors – Continuing Directors with Term Expiring in +2013 Class III” for Mr. McCullough’s +biography. +Gysle R. Shellum , 59, was appointed CFO in 2008. Prior to +joining the Company, Mr. Shellum served as Vice President, +Finance and Special Projects of Crosstex Energy, L.P., Dallas, +Texas. Mr. Shellum served in this capacity from September +2004 through September 2008. From March 2001 until September +2004, Mr. Shellum served as a consultant to Value Capital, +a private consulting firm in Dallas, Texas, where he worked on +various projects, including corporate finance and Sarbanes-Oxley +Act compliance. Crosstex Energy, L.P. is a publicly traded +Delaware limited partnership whose securities are listed on the +NASDAQ Global Select Market and is an independent midstream +energy company engaged in the gathering, transmission, treating, +processing and marketing of natural gas and natural gas liquids. +Barton R. Brookman, Jr. , 48, was appointed Senior Vice +President Exploration and Production in March 2008. +Mr. Brookman previously served as Vice President +Exploration and Production upon joining PDC in July 2005. Prior +to joining PDC, Mr. Brookman worked for Patina Oil and Gas +and its predecessor Snyder Oil for 17 years in a series of +positions of increasing responsibility, ending his service as +Vice President of Operations of Patina. +Daniel W. Amidon , 50, was appointed General Counsel and +Secretary in July 2007. Prior to joining PDC, Mr. Amidon +was employed by Wheeling-Pittsburgh Steel Corporation beginning +in July 2004, where he served in several positions including +General Counsel and Secretary. Prior to his employment with +Wheeling-Pittsburgh Steel, Mr. Amidon was employed by +J&L Specialty Steel Inc. from 1992 through July 2004 in +positions of increasing responsibility, including General +Counsel and Secretary. Mr. Amidon practiced with the +Pittsburgh law firm of Buchanan Ingersoll PC from 1986 through +1992. +Lance A. Lauck , 48, was appointed Senior Vice President +Business Development in August 2009. Previously Mr. Lauck +served as Vice President — Acquisitions and Business +Development for Quantum Resources Management LLC from +2006 — 2009. From 1988 until 2006, he held various +management positions at Anadarko Petroleum Corporation in the +areas of acquisitions and divestitures, corporate mergers and +business development. +28 +Table of Contents +COMPENSATION \ No newline at end of file diff --git a/raw/filings/0000077877/2011/0000077877-12-000013/filing.txt b/raw/filings/0000077877/2011/0000077877-12-000013/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..d077f72d122d8a409db67bd5b7c2f1b4b6aaa3ec --- /dev/null +++ b/raw/filings/0000077877/2011/0000077877-12-000013/filing.txt @@ -0,0 +1,8055 @@ +10-K +1 +petrodev-10kxfy11.htm +PDC ENERGY 2011 FORM 10-K +petro.dev-10K-FY11 +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +FORM 10-K +T 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 +£ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period from __________ to _________ +Commission File Number 000-07246 +PETROLEUM DEVELOPMENT CORPORATION +(Exact name of registrant as specified in its charter) +(Doing Business as PDC Energy) +Nevada +95-2636730 +(State of Incorporation) +(I.R.S. Employer Identification No.) +1775 Sherman Street, Suite 3000 +Denver, Colorado 80203 +(Address of principal executive offices) (Zip Code) +Registrant's telephone number, including area code: (303) 860-5800 +Securities registered pursuant to Section 12(b) of the Act: +Title of each class +Name of each exchange on which registered +Common Stock, par value $0.01 per share +NASDAQ Global Select Market +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 T No £ +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 £ No T +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 T No £ +Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, 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 T No £ +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. £ +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 definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. +Large accelerated filer £ +Accelerated filer x +Non-accelerated filer £ +(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 £ No T +The aggregate market value of our common stock held by non-affiliates on June 30, 2011 , was $699,417,474 (based on the then closing price of $29.91 ). +As of February 17, 2012 , there were 23,634,456 shares of our common stock outstanding. +DOCUMENTS INCORPORATED BY REFERENCE +We hereby incorporate by reference into this document the information required by Part III of this Form, which will appear in our definitive proxy statement to be filed pursuant to Regulation 14A for our 2012 Annual Meeting of Stockholders. +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +2011 ANNUAL REPORT ON FORM 10-K +TABLE OF CONTENTS +PART I +Page +Items 1 and 2. +Business and Properties +2 +Item 1A. +Risk Factors +16 +Item 1B. +Unresolved Staff Comments +28 +Item 3. +Legal Proceedings +28 +Item 4. +Mine Safety Disclosures +28 +PART II +Item 5. +Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities +29 +Item 6. +Selected Financial Data +31 +Item 7. +Management's Discussion and Analysis of Financial Condition and Results of Operations +32 +Item 7A. +Quantitative and Qualitative Disclosures About Market Risk +49 +Item 8. +Financial Statements and Supplementary Data +52 +Item 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +52 +Item 9A. +Controls and Procedures +52 +Item 9B. +Other Information +52 +PART III +Item 10. +Directors, Executive Officers and Corporate Governance +53 +Item 11. +Executive Compensation +53 +Item 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +53 +Item 13. +Certain Relationships and Related Transactions, and Director Independence +53 +Item 14. +Principal Accounting Fees and Services +53 +PART IV +Item15. +Exhibits, Financial Statement Schedules +53 +Signatures +57 +Glossary of Units of Measurements and Industry Terms +58 +PART I +REFERENCES TO THE REGISTRANT +In July 2010, Petroleum Development Corporation, established in 1969, began conducting business as PDC Energy. The Company's common stock continues to trade on the NASDAQ Global Select Market under the ticker symbol PETD. The Company's website, www.petd.com, reflects the PDC Energy name and brand identity. At the Company's annual stockholders' meeting to be held in June 2012, we plan to request shareholders to approve and amend the Company's articles of incorporation to formally change the corporate name to PDC Energy, Inc. Information contained on or linked to our website is not part of this report and is not hereby incorporated by reference and should not be considered part of this report. +Unless the context otherwise requires, references in this report to "PDC," "PDC Energy," "the Company," "we," "us," "our," "ours" or "ourselves" refer to the registrant, Petroleum Development Corporation, and all subsidiaries consolidated for the purposes of its financial statements, including our proportionate share of the financial position, results of operations, cash flows and operating activities of our affiliated partnerships and PDC Mountaineer, LLC ("PDCM"), a joint venture currently owned 50% each by PDC and Lime Rock Partners, LP formed for the purpose of exploring and developing the Marcellus Shale formation in the Appalachian Basin ("Marcellus JV"). Unless the context otherwise requires, references in this report to "Appalachian Basin" includes PDC's proportionate share of our affiliated partnerships' and the Marcellus JV's assets, results of operations, cash flows and operating activities. +See Note 1, Nature of Operations and Basis of Presentation, to our consolidated financial statements included in this report for a description of our consolidated subsidiaries. +GLOSSARY OF UNITS OF MEASUREMENTS AND INDUSTRY TERMS +Units of measurements and industry terms defined in the Glossary of Units of Measurements and Industry Terms, included at the end of this report, are set in boldface type the first time they appear. +WHERE YOU CAN FIND ADDITIONAL INFORMATION +We file annual, quarterly and current reports, proxy statements and other information with the United States Securities and Exchange Commission ("SEC"). Our SEC filings are available free of charge from the SEC’s website at www.sec.gov or from our website at www.petd.com. You may also read or copy any document we file at the SEC’s public reference room in Washington, D.C., located at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Please call the SEC at (800) SEC-0330 for further information on the public reference room. We also make available free of charge any of our SEC filings by mail. For a mailed copy of a report, please contact Petroleum Development Corporation, dba PDC Energy, Investor Relations, 1775 Sherman Street, Suite 3000, Denver, CO 80203, or call toll free (800) 624-3821. +We recommend that you view our website for additional information, as we routinely post information that we believe is important for investors. Our website can be used to access such information as our recent news releases, bylaws, committee charters, code of business conduct and ethics, shareholder communication policy, director nomination procedures and our whistle-blower hotline. While we recommend that you view our website, the information available on our website is not part of this report and is not hereby incorporated by reference. +SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS +This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 ("Securities Act") and Section 21E of the Securities Exchange Act of 1934 ("Exchange Act") regarding our business, financial condition, results of operations and prospects. All statements other than statements of historical facts included in and incorporated by reference into this report are "forward-looking statements" within the meaning of the safe harbor provisions of the United States ("U.S.") Private Securities Litigation Reform Act of 1995. Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements herein. These statements include: estimated natural gas, natural gas liquids (" NGLs ") and crude oil production and reserves ; expected operational, midstream and marketing synergies from PDCM's Seneca-Upshur acquisition; anticipated capital expenditures, including our ability to fund our 2012 capital budget; increased focus on the Wattenberg Field and liquid-rich areas; our horizontal Niobrara drilling plans in 2012; planned refractures and recompletions in 2012; expected use of proceeds from our Permian divestiture; the expected benefit of operational diversity in the Rocky Mountain region; our ability to mitigate risks by sharing costs of exploratory drilling in the Marcellus Shale with our joint venture partner; our intent to mitigate risks by maintaining a natural gas and liquids mix to counter a decline in the market price of one of our commodities; our expected term for inventory of projects for drilling activity; planned limited development in Piceance in 2012 due to the commodity pricing environment; drilling plans in the Utica Shale in 2012; that development drilling will remain the foundation of our drilling program; addition of 8 Bcfe of reserves at December 31, 2011 from the Seneca Upshur acquisition; our belief that pricing provisions in our natural gas contracts are customary; our belief that our exploration program has the potential to replenish our portfolio with new projects for significant production and reserves growth; our compliance with our debt covenants and the indenture restrictions governing our senior notes and expected continued compliance; sufficient liquidity to meet our partnership repurchase obligations; our belief that the acquisition of partnerships will provide us with growth in production and proved reserves and operational benefits; the adequacy of our casualty insurance coverage as managing general partner of numerous partnerships and as operator of our own wells; the impact of decreased commodity prices on future borrowing base redeterminations; that we hold good and defensible title to our natural gas and crude oil properties in accordance with industry standards; the effectiveness of our derivative +1 +policies in achieving our risk management objectives; our expected remaining liability for uncertain tax positions; our ability to secure a joint venture partner for our Utica Shale acreage; the impact of outstanding legal issues; our ability to benefit from crude oil and natural gas price differential; and our strategies, plans and objectives. +The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Consequently, forward-looking statements are inherently subject to risks and uncertainties, including known and unknown risks and uncertainties incidental to the exploration for, and the acquisition, development, production and marketing of natural gas, NGLs and crude oil, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements. +Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to: +• +changes in production volumes and worldwide demand, including economic conditions that might impact demand; +• +volatility of commodity prices for natural gas, NGLs and crude oil; +• +the impact of governmental fiscal terms and/or regulations, including changes in environmental laws, the regulation and enforcement related to those laws and the costs to comply with those laws, as well as other regulations; +• +decline in the values of our natural gas and crude oil properties resulting in impairments; +• +changes in estimates of proved reserves; +• +inaccuracy of reserve estimates and expected production rates; +• +the potential for production decline rates from our wells to be greater than expected; +• +the timing and extent of our success in discovering, acquiring, developing and producing reserves; +• +our ability to acquire leases, drilling rigs, supplies and services at reasonable prices; +• +the timing and receipt of necessary regulatory permits; +• +risks incidental to the drilling and operation of natural gas and crude oil wells; +• +our future cash flow, liquidity and financial position; +• +competition in the oil and gas industry; +• +the availability and cost of capital to us; +• +reductions in the borrowing base under our credit facility; +• +the availability of sufficient pipeline and other transportation facilities to carry our production and the impact of these facilities on price; +• +our success in marketing natural gas, NGLs and crude oil; +• +the effect of natural gas and crude oil derivatives activities; +• +the impact of environmental events, governmental responses to the events and our ability to insure adequately against such events; +• +the cost of pending or future litigation; +• +our ability to retain or attract senior management and key technical employees; and +• +the success of strategic plans, expectations and objectives for future operations of the Company. +Further, we urge you to carefully review and consider the cautionary statements and disclosures, specifically those under Item 1A, Risk Factors , made in this report and our other filings with the SEC for further information on risks and uncertainties that could affect our business, financial condition, results of operations and cash flows. We caution you not to place undue reliance on forward-looking statements, which speak only as of the date of this report. We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. All forward-looking statements are qualified in their entirety by this cautionary statement. +ITEMS 1 AND 2. BUSINESS AND PROPERTIES +The Company +Effective July 15, 2010, Petroleum Development Corporation began conducting business as PDC Energy. A new logo and corporate identity accompanied this change. Our common stock continues to trade on the NASDAQ Global Select Market under the ticker symbol PETD. We continue to maintain our website address, www.petd.com, which reflects the new PDC Energy name and brand identity. This change reflects the transitioning in our business model, from a company that was predominately a sponsor of limited partnerships to an exploration and production company that explores for and acquires, develops, produces and markets natural gas and oil resources. +We are a domestic independent exploration and production company that acquires, develops, explores, and produces natural gas, NGLs, and crude oil. Our Western Operating Region is primarily focused on development in the Wattenberg Field in Colorado, particularly in the liquid-rich horizontal Niobrara play and on the ongoing development of refractures and recompletions of our Wattenberg wells. In our Eastern Operating Region, we are focused on horizontal development in the Marcellus Shale in northern West Virginia, and recently initiated exploration and development activity in the liquid-rich portion of the Utica Shale play in Ohio. We own an interest in approximately 6,500 gross producing wells and maintained an average December 2011 production rate of approximately 146 MMcfe per day, which was comprised of 62% natural gas, 27% crude oil and 11% NGLs. +As of December 31, 2011, an independent petroleum engineering firm estimated our total proved reserves to be approximately 1 +2 +Tcfe with a PV-10% , a non-U.S. GAAP financial measure, of $1.3 billion. Approximately 46% of our total proved reserves have been classified as proved developed . Our total proved reserves consist of 66% natural gas and 34% crude oil and NGLs. Our internal estimate of proved, probable and possible ("3P") reserves has increased from 1.4 Tcfe as of December 31, 2010, to 2.1 Tcfe as of December 31, 2011, and includes a significant multi-year inventory of horizontal and vertical drilling projects as well as multiple refracture and recompletion projects in existing wells. +See Part I, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Reconciliation of Non-U.S. GAAP Financial Measures , for a definition of PV-10% and a reconciliation of our PV-10% value to our standardized measure. +2011 Overview +In 2011, we focused primarily in the liquid-rich Wattenberg Field in northern Colorado where we drilled 17 horizontal Niobrara wells, 80 vertical wells, completed 190 refracture and/or recompletion projects and participated in 48 non-operated drilling projects. During the year, we reduced our drilling of vertical wells to refocus our efforts on our horizontal Niobrara drilling program. We have successfully de-risked much of the horizontal Niobrara potential throughout our core Wattenberg acreage position and generated over 350 gross horizontal well projects in inventory. PDCM drilled six horizontal Marcellus wells, completed five horizontal wells and initiated several midstream projects. In October, we announced that we entered the Utica Shale play, where we have the rights to acquire up to an estimated 40,000 net acres targeting the wet gas and crude oil windows in southeast Ohio, and through PDCM, completed the Seneca-Upshur acquisition which added 90,000 gross acres to our Marcellus position. During the fourth quarter, we closed on the sale of our non-core Permian Basin assets to an unrelated third party for a sales price of $13.2 million. In December, we executed a definitive agreement to sell our core Permian Wolfberry assets to anoth er unrelated third party for a sales price of $173.9 million, subject to customary post-closing adjustments. On February 28, 2012, this divestiture was completed with total proceeds received of $184.4 million after preliminary closing adjustments. +. +Business Strategy +Our business strategy focuses on generating shareholder value through the growth of our reserves and production in our liquid-rich and high impact horizontal plays. We allocate capital to high return projects in our portfolio capable of maximizing our cash flow and return on capital. We place a strong emphasis on organic growth through active horizontal drilling programs, emphasize low-risk development drilling, engage in targeted exploratory drilling in unconventional resources and maintain an active acquisition program. We pursue various midstream, marketing and cost reduction initiatives designed to increase our per unit operating margins and maintain a conservative and disciplined financial strategy focused on providing sufficient liquidity and balance sheet strength to execute our business strategy. +Drill and Develop +Our leasehold consists primarily of interests in developed and undeveloped natural gas, NGLs and crude oil resources located in our Western and Eastern Operating Regions. We seek to maximize the value of our existing wells through a successful program of well refractures, recompletions and workovers . Based on our prior acreage holdings and recent acquisitions, we have accumulated a multi-year inventory of horizontal and vertical developmental drilling projects, as well as refracture, recompletion and exploration projects. +Western Operating Region . Our primary focus in the liquid-rich Wattenberg Field is horizontal development drilling of the Niobrara formation. We also maintain a vertical drilling inventory in the Niobrara and Codell formations in Wattenberg and continue to execute on multiple refracture and recompletion projects. Additionally, we operate natural gas assets in the Piceance Basin in western Colorado and in northeast Colorado ("NECO") where we currently focus on production optimization and increasing operating margins. +Approximately 65% of our 2012 capital budget, or $184 million, is expected to be spent on development activities, approximately 97% of which is expected to be invested in the Wattenberg Field for an expanded horizontal Niobrara drilling program, increased pace of refractures and recompletions and participation in various non-operated projects. We currently estimate that we have more than 1,750 gross drilling projects, which include over 350 gross projects for the horizontal Niobrara, and approximately 1,450 refracture and recompletion projects in existing wells in the Wattenberg Field. Depending on the number of drilling rigs operating and commodity prices, we believe that this inventory of projects provides us with approximately 10 years of drilling activity. In 2012, we plan to run a one-rig program in Wattenberg to drill between between 25 and 30 horizontal Niobrara wells, along with completing an estimated 250 to 265 refracture and recompletion projects on existing wells. +In 2011, we drilled a total of 17 development wells in the Piceance Basin. We currently estimate that we have more than 390 gross drilling projects, representing multiple years of inventory depending on the number of drilling rigs operating and commodity prices. We expect to maintain a disciplined approach to the development of our Piceance gas acreage holdings in 2012, with plans to complete only those wells previously drilled in this area in 2011 as we focus our capital budget in areas expected to generate higher rates of return. +Drilling activity in the Permian Basin in 2011 included 23 development wells, including two determined to be dry holes . In October 2011, we announced our intent to divest our Permian Basin assets. The divestiture was completed on February 28, 2012. See Acquisitions and Divestitures below and Note 13, Assets Held for Sale, Divestitures and Discontinued Operations, and Note 18 , Subsequent Event, to our consolidated financial statements included in this report for additional details related to the divestiture of our Permian assets. +Eastern Operating Region . Our primary focus in the Marcellus Shale natural gas play consists of horizontal drilling in West Virginia. In 2011, PD CM drilled a total of 6 gross, 3 net, horizontal wells and constructed various midstream assets to gather and compress its Marcellus gas. PDCM recently announced it has elected to temporarily suspend drilling in the Marcellus Shale play due to the current depressed natural gas price environment. Prior to suspending its drilling activities in 2012, PDCM expects to drill a total of 4 gross horizontal +3 +wells and complete 7 wells, including 3 wells that were in-process as of Decemb er 31, 2011. +With the addition of our Ohio leaseholds in late 2011, we have recently begun to focus on exploratory and delineation drilling targeting the wet gas and crude oil windows of the Utica Shale. We drilled one vertical well to total depth in mid-December, which was fracture treated early in 2012. In 2012, we expect to drill approximately two horizontal shale wells with an option to drill two additional vertical wells. Currently, we are pursuing an industry joint venture partner to participate in and share in funding the growth and development in this play. While we expect to identify a partner by mid-2012, we cannot assure we will be successful in securing a partner or developing this acreage. +The following table presents information regarding the number of wells we drilled or participated in and the number of refractures and/or recompletions we performed. +Drilling Activity +Year Ended December 31, +2011 +2010 +2009 +Operating Region +Gross +Net +Gross +Net +Gross +Net +Western (1) +186 +139.6 +204 +164.9 +92 +71.2 +Eastern +9 +5.2 +9 +5.2 +8 +8.0 +Total wells drilled +195 +144.8 +213 +170.1 +100 +79.2 +Refractures and Recompletions (2) +192 +177.6 +46 +33.7 +37 +35.4 +__________ +(1) +Includes drilling activity in the Permian Basin. As of December 31, 2011, our Permian assets were held for sale and, on February 28, 2012, the divestiture closed. See Note 13, Assets Held for Sale, Divestitures and Discontinued Operations, and Note 18, Subsequent Event, to our consolidated financial statements included in this report for additional details related to the divestiture of our Permian assets. +(2) +190 of the refractures and recompletions occurred in the Wattenberg Field. +The following tables set forth our developmental and exploratory well drilling activity. There is no correlation between the number of productive wells completed during any period and the aggregate reserves attributable to those wells. Productive wells consist of wells spudded , turned in line and producing during the period. In-process wells represent wells that are in the process of being drilled or have been drilled and are waiting to be fractured and/or for gas pipeline connection during the period. +Net Development Well Drilling Activity +Year Ended December 31, +2011 +2010 +2009 +Operating Region/Area +Productive +In-Process +Dry +Productive +In-Process +Dry +Productive +In-Process +Dry +Western +Wattenberg Field +86.5 +13.1 +— +106.9 +26.5 +— +58.3 +6.9 +— +Piceance Basin +14.0 +3.0 +— +18.0 +7.0 +— +1.0 +— +— +Permian Basin (1) +14.5 +5.5 +2.0 +— +5.0 +— +— +— +— +Other +— +— +— +0.5 +— +— +2.0 +— +1.0 +Total Western +115.0 +21.6 +2.0 +125.4 +38.5 +— +61.3 +6.9 +1.0 +Eastern +Appalachian Basin +0.9 +2.0 +— +0.6 +1.1 +— +2.0 +— +— +Total Eastern +0.9 +2.0 +— +0.6 +1.1 +— +2.0 +— +— +Total net development wells +115.9 +23.6 +2.0 +126.0 +39.6 +— +63.3 +6.9 +1.0 +__________ +(1) +As of December 31, 2011, our Permian assets were held for sale and, on February 28, 2012, the divestiture closed. See Note 13, Assets Held for Sale, Divestitures and Discontinued Operations, and Note 18, Subsequent Event, to our consolidated financial statements included in this report for additional details related to the divestiture of our Permian assets. +4 +Net Exploratory Well Drilling Activity +Year Ended December 31, +2011 +2010 +2009 +Operating Region/Area +In-Process +Productive +In-Process +Productive +In-Process +Western +Wattenberg Field +— +— +1.0 +— +— +Other +1.0 +— +— +1.0 +1.0 +Total Western +1.0 +— +1.0 +1.0 +1.0 +Eastern +Appalachian Basin +2.3 +2.8 +0.7 +5.0 +1.0 +Total Eastern +2.3 +2.8 +0.7 +5.0 +1.0 +Total net exploratory wells +3.3 +2.8 +1.7 +6.0 +2.0 +Acquisitions and Divestitures +We typically pursue the acquisition of assets that have a balance of value in producing wells, behind-pipe reserves and high quality undeveloped drilling locations. In 2010, we began seeking liquid-rich properties with large undeveloped drilling upside where we believe we can utilize our operational abilities to add shareholder value. As we evaluate investment opportunities, we may also seek to divest non-core assets to optimize our property portfolio. +Acquisitions +In 2010, we initiated a plan to purchase our affiliated partnerships. The acquisition of these partnerships have provided us with immediate growth in both production and proved reserves from assets in which we currently own an operated working interest. We believe that these acquisitions will also allow us to realize operational benefits as well as the potential to accelerate the refracture/recompletion program of the wells acquired, thus allowing us to optimize revenue opportunities. As of December 31, 2011, we had acquired a total of 12 affiliated partnerships for an aggregate purchase price of $107.7 million, eight of which occurred in 2011 for an aggregate purchase price of $73 million. We estimate that the 2011 acquisitions added approximately 40 Bcfe in total proved reserves as of December 31, 2011, which includes the non-affiliated investor partners' remaining working interests in a total of 299 gross, 204.2 net, wells located in our Wattenberg Field and Piceance Basin. +During 2011, we obtained the rights to acquire Utica leasehold acres from unrelated third parties targeting the wet natural gas and crude oil windows of the Utica Shale play throughout southeastern Ohio. Should we exercise our right to acquire all 40,000 acres, we estimate that the purchase price of such leaseholds will approximate $70 million. A portion of the options related to these leaseholds will expire in August 2012. Currently, we are pursuing an industry joint venture partner to participate in and share in funding the growth and development in this play. While we expect to identify a partner by mid-2012, we cannot assure we will be successful in securing a partner or developing this acreage. +In October 2011, PDCM acquired from an unrelated third party 100% of the membership interests of Seneca-Upshur Petroleum, LLC ("Seneca-Upshur"), a West Virginia limited liability company, for the purchase price of $162.9 million, including a post-closing working capital adjustment of $10.4 million. The acquisition included approximately 1,340 gross wells producing natural gas from the shallow Devonian Shale and Mississippian formations and all rights and depths to an estimated 100,000 net acres in West Virginia, of which 90,000 acres are prospective for the Marcellus Shale. Substantially all of the acreage acquired is held by production, prospective for the Marcellus Shale and is in close proximity to PDCM's existing properties. Pursuant to our joint venture interest in PDCM, our portion of the purchase price was $81.5 million and we hold a 50% interest in both the wells and acreage acquired. We estimate that the acquisition added approximately 8 Bcfe to our total proved reserves as of December 31, 2011. +Divestitures +Permian Basin . In October 2011, we announced our intent to divest our acreage located in the Wolfberry Trend in the Permian Basin in West Texas to focus our efforts in our horizontal drilling programs and to provide funding for our 2012 capital budget. During the fourth quarter of 2011, we completed the sale of our non-core Permian assets to unrelated third parties for a total of $13.2 million. On December 20, 2011, we executed a purchase and sale agreement with another unrelated third party for the sale of our core Permian assets for a total price of $173.9 million, subject to customary post-closing adjustments. The transaction closed on February 28, 2012 with total proceeds received of $184.4 million after preliminary closing adjustments . The proceeds from the sales were used to pay down our corporate credit facility, until needed to fund our 2012 capital budget. The Permian Basin assets were classified as held for sale as of December 31, 2011 and 2010, and the results of operations related to those assets were reported as discontinued operations in 2010, year of acquisition, and 2011 on our consolidated statements of operations included in this report. +North Dakota. In December 2010, we effected a letter of intent with an unrelated third party for the sale of our North Dakota assets. The North Dakota assets were classified as held for sale as of December 31, 2010, and the results of operations related to those assets were reported as discontinued operations in 2009, 2010 and 2011 on our consolidated statements of operations included in this report. In February +5 +2011, we executed a purchase and sale agreement and subsequently closed with the same unrelated party. Proceeds from the sale were $9.5 million, net of non-affiliated investor partners' share of $3.8 million, resulting in a pretax gain on sale of $3.9 million. +Exploration +We believe that our disciplined exploration program has the potential to consistently replenish our portfolio with new exploration projects capable of positioning us for significant production and reserve growth in future years. Due to the continued decline in natural gas prices, we have focused our efforts toward liquid-rich plays to take advantage of the current attractive economics associated with crude oil and NGL weighted projects. We strive to identify potential plays in their early stages in an attempt to accumulate significant leasehold positions prior to competitive forces driving up the cost of entry. We seek investment in leasehold positions that are in the proximity of existing or emerging pipeline infrastructures. We believe the leaseholds we acquired targeting the Utica Shale meet these criteria and we see these leaseholds as our primary exploration play for 2012. +Manage Operational and Financial Risk +We focus on lower risk development drilling programs in resource plays with repeatable drilling opportunities that will grow reserves and production while maintaining or growing cash flows. We regularly review acquisition opportunities in our core areas of operation as we believe we can enhance the value of such opportunities through economies of scale. We believe development drilling will remain the foundation of our drilling programs; however, we view a disciplined approach to exploratory drilling as having the potential to identify new development opportunities, as we have done in recent years with our horizontal Niobrara and Marcellus drilling programs. +We engage in limited exploratory drilling as such activities involve numerous risks, including the risk that we may not be successful in the discovery of commercially productive natural gas and crude oil reservoirs. Costs associated with exploratory activities can be quite high. In an effort to mitigate in part the financial risk associated with exploratory activities, we may seek opportunities to participate in joint venture arrangements to share in the potential high costs and risks of exploratory drilling while maximizing the potential returns. We believe our Marcellus JV has effectively served to mitigate the risks associated with exploring the Marcellus Shale. We are currently seeking an investment partner to participate with us in exploring our newly acquired Ohio properties, which are prospective for the wet gas and crude oil windows of the Utica Shale. We cannot assure we will be successful in securing a joint venture partner or developing this acreage. +We believe we proactively employ strategies to help reduce the financial risks associated with the oil and gas industry. One such strategy is to maintain a balanced production mix of natural gas and liquids. Our Western Operating Region produces natural gas, NGLs and crude oil, with a production mix of approximately 65% natural gas to 35% liquids. While our legacy properties in the Eastern Operating Region primarily produce natural gas, our Ohio properties are prospective for the wet gas and crude oil windows of the Utica Shale. This strategy of a diversified commodity mix helps to mitigate the financial impact from a decline in the market price in any one of our commodities. In addition, we utilize commodity-based derivative instruments to manage a portion of our exposure to price volatility with regard to our natural gas and crude oil sales and natural gas marketing. We utilize both financial and physical derivative instruments. The financial instruments consist of floors, collars, swaps and basis swaps and consist of NYMEX , CIG and PEPL -based contracts. We may utilize derivatives based on other indices or markets where appropriate. The contracts provide price stability for up to 80% of our committed and anticipated natural gas and crude oil sales and purchases forecasted to occur within the next five-year period. Our policies prohibit the use of commodity derivatives for speculative purposes and permit utilization of derivatives only if there is an underlying physical position. As of December 31, 2011, we had natural gas and crude oil derivative positions in place for 2012 covering 59.1% of our expected natural gas production and 60.8% of our expected crude oil production. Currently, we do not hedge our NGL production. See Item 7A , Quantitative and Qualitative Disclosures about Market Risk, for a detailed summary of our open derivative positions. +Riley Natural Gas ("RNG"), a wholly-owned subsidiary, uses financial derivatives in its gas marketing operations to augment its fixed purchases and sales. RNG also enters into back-to-back fixed-price physical purchases and sales contracts with counterparties. RNG does not always hedge the area basis risk for third party trades with back-to-back fixed price purchases and sales. We continue to evaluate the potential for reducing this risk by entering into derivative transactions. Further, we may choose to close out any portion of a derivative contract existing at any time, which may result in a realized gain or loss on that derivative transaction. +Business Segments +We divide our operating activities into two segments: (1) Oil and Gas Exploration and Production and (2) Gas Marketing. +Oil and Gas Exploration and Production +Our Oil and Gas Exploration and Production segment primarily reflects revenues and expenses from the production and sale of natural gas, NGLs and crude oil. +• +Natural gas . We sell our natural gas to marketers, utilities, industrial end-users and other wholesale purchasers. We primarily sell the natural gas that we produce under contracts with indexed or NYMEX monthly pricing provisions with the remaining production sold under contracts with daily pricing provisions. Virtually all of our contracts include provisions wherein prices change monthly with changes in the market, for which certain adjustments may be made based on whether a well delivers to a gathering or transmission line, quality of natural gas and prevailing supply and demand conditions. Therefore, the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. As a result, our revenues from the sale of +6 +natural gas, holding production volume constant, increase as market prices increase and decrease as market prices decline. We believe that the pricing provisions of our natural gas contracts are customary in the industry. +• +Crude oil . We do not refine any of our crude oil production. We sell our crude oil to oil marketers and refiners. Our crude oil production is sold to purchasers at or near our wells under both short and long-term purchase contracts with monthly pricing provisions based on an average daily price. +• +NGLs . The majority of our NGLs are sold to one NGL marketer in the Wattenberg Field. Our NGL production is sold under both short and long-term purchase contracts with monthly pricing provisions based on an average daily price. +We enter into financial derivatives in order to reduce the impact of possible price volatility regarding the physical sales market. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations: Results of Operations – Commodity Price Risk Management, Net, Natural Gas and Crude Oil Derivative Activities , Item 7A, Quantitative and Qualitative Disclosures about Market Risk, and Note 4, Derivative Financial Instruments , to our consolidated financial statements included in this report. +Our Oil and Gas Exploration and Production segment also reflects revenues and expenses related to well operations and pipeline services. We are paid a monthly operating fee for the portion of each well we operate that is owned by others, including our affiliated partnerships. We believe the fee is competitive with rates charged by other operators in the area. As we acquire the working interest of our non-affiliated investor partners in our affiliated partnerships, revenues related to well operations and pipeline services will decrease. +We construct, own and operate gathering systems in some of our areas of operations. Pipelines and related facilities can represent a significant portion of the capital costs of developing wells, particularly in new areas located at a distance from existing pipelines. We consider these costs in the evaluation of our leasing, development and acquisition opportunities. +Our natural gas and NGLs are transported through our own and third party gathering systems and pipelines, and we incur gathering, processing and transportation expenses to move our natural gas from the wellhead to a purchaser-specified delivery point. These expenses vary based on the volume and distance shipped, and the fee charged by the third-party processor or transporter. Capacity on these gathering systems and pipelines is occasionally interrupted due to repairs or improvements. A majority of our natural gas is transported under interruptible contracts and thus could, if pipeline space is constrained, result in an interruption in natural gas sales. While our ability to market these volumes of natural gas has been only infrequently limited or delayed, if transportation space is restricted or is unavailable, our cash flow from the affected properties could be adversely affected. In certain instances, we enter into firm transportation agreements to provide for pipeline capacity to flow and sell a portion of our natural gas volumes. In order to meet pipeline specifications, we are required, in some cases, to process our natural gas before we can transport it. We typically contract with third parties in the Piceance Basin and the NECO areas of our Western Operating Region and our Eastern Operating Region for firm transportation of our natural gas. We also may enter into firm sales agreements to ensure that we are selling to a purchaser who has contracted for pipeline capacity. These agreements are subject to the same limitations discussed above in this paragraph. See Note 11, Commitments and Contingencies - Firm Transportation Agreements , to our consolidated financial statements included in this report for our long-term firm sales, processing and transportation agreements for pipeline capacity. +Our crude oil production is marketed directly to purchasers in the Wattenberg area under a combination of annual and short-term monthly agreements. The majority of our crude oil is delivered to local area refineries with other volumes being either trucked or shipped via pipeline out of the Wattenberg area. +See Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations, Summary Operating Results, for production, sales, prices and lifting cost data for each of the years in the three-year period ended December 31, 2011. +Gas Marketing +Our Gas Marketing segment is comprised solely of the operating activities of RNG. RNG specializes in the purchase, aggregation and sale of natural gas production in the Eastern Operating Region. RNG purchases for resale natural gas produced by third party producers as well as natural gas produced by us, PDCM and our affiliated partnerships. The natural gas is marketed to third party marketers, natural gas utilities, as well as industrial and commercial customers, either directly through our gathering system, or through transportation services provided by regulated interstate pipeline companies. Additionally, RNG markets our natural gas production in the NECO area. +For additional information regarding our business segments, see Note 17, Business Segments , to our consolidated financial statements included in this report. +7 +Areas of Operations +The following map presents the general locations of our development, production and exploration activities as of December 31, 2011 . With the divestiture of our Permian Basin assets on February 28, 2012, our development, production and exploration efforts are primarily focused in two geographic areas of the U.S. +Western Operating Region +Our primary focus in the Western Operating Region for 2012 and the near term is on horizontal Niobrara drilling. We divide our Western Operating Region into two major areas: the Wattenberg Field and Piceance Basin. +• +Wattenberg Field, DJ Basin, Colorado. Wells drilled in this area have historically been vertical and range from approximately 7,000 to 8,000 feet in depth. These wells target reservoirs in the Codell and Niobrara formations that have historically contained about 50% crude oil and NGLs. In October 2010, we began a horizontal drilling program targeting the liquid-rich Niobrara formation. The horizontal Niobrara wells have a vertical depth range from approximately 7,000 to 8,000 feet with an average lateral length of 4,000 feet. Operations in Wattenberg Field, in addition to developmental drilling, include a program of refractures and recompletion projects on existing wells in the Codell and Niobrara reservoirs. +• +Piceance Basin, Colorado. Wells in this area predominately target natural gas, with the area's volume of natural gas reserves representing approximately 47% of our total proved natural gas reserves, which equates to approximately 32% of our total proved reserves. Reserves in this area represent approximately 1% of our present value of future net revenues ("PV-10%"), a non-U.S. GAAP measure. See table in the Properties -Proved Reserves section below for information regarding our proved reserves and PV-10% as of December 31, 2011. While all inputs to the cash flow model must be evaluated at each date that the estimate of future cash flows for each producing basin is calculated, a significant decrease in long-term forward natural gas prices alone could result in a significant impairment for our properties that are sensitive to declines in natural gas prices. +The majority of the wells drilled in this area are drilled directionally from multi-well drilling pads, generally range from two to ten wells per pad, and range from 7,000 to 9,500 feet in depth. Reserves in this area originate from multiple sandstone reservoirs in the Mesaverde Williams Fork formation. +• +Northeastern Colorado ("NECO") . Wells drilled in this are range from 1,500 to 3,000 feet in depth and target natural gas reserves in the shallow Niobrara reservoir. We have not conducted drilling activity in this area since 2009. +• +Permian Basin. As of December 31, 2011, our Permian assets were held for sale and, on February 28, 2012, the divestiture closed. See Note 13, Assets Held for Sale, Divestitures and Discontinued Operations , and Note 18, Subsequent Event , to our consolidated financial statements included in this report for additional details related to the divestiture of our Permian assets. +Eastern Operating Region +Our primary focus in the Eastern Operating Region is on horizontal drilling in the Marcellus Shale play in northern West Virginia and, with the addition of leaseholds in Ohio during 2011, exploratory and delineation drilling in the emerging Utica Shale play. +8 +• +Marcellus Shale, West Virginia. In October 2009, through our contribution of the majority of our Eastern Operating Region assets, consisting of acreage, producing properties and related reserves, gathering assets and equipment, and a cash contribution by our joint venture partner, we formed the joint venture PDCM. The wells contributed were producing from the shallow Devonian and Mississippian aged tight sandstone reservoirs, ranging from 1,200 to 6,000 feet in depth. In October 2011, PDCM acquired all rights and depths to 100,000 net acres, of which 90,000 net acres are prospective for the Marcellus Shale and added an additional 1,340 gross wells producing from the Devonian and Mississippian formations. PDCM is primarily focused on horizontal drilling, targeting the Marcellus Shale formation in northern West Virginia. These wells have a vertical depth range from approximately 7,000 to 8,000 feet with lateral lengths ranging from 4,000 to 6,000 feet. +In addition to our ownership interest in the wells held by PDCM, we own an interest in approximately 311 gross, 106.2 net, natural gas and crude oil wells in West Virginia, Pennsylvania and Tennessee. +• +Utica Shale, Ohio. Our newest prospect is the Utica Shale play in southeastern Ohio, with our initial leasehold acquisitions occurring in 2011. Exploratory drilling activity began in the fourth quarter, with one vertical well drilled to total depth, approximately 9,600 feet, and subsequently fracture treated in early 2012. We continue to pursue an industry joint venture partner to participate in and share in funding the growth and development in this play; however, we cannot assure we will be successful in securing a partner or developing the play. +Properties +Productive Wells +The following table presents our productive wells. +Productive Wells +As of December 31, 2011 +Natural Gas +Crude Oil +Total +Operating Region/Area +Gross +Net +Gross +Net +Gross +Net +Western +Wattenberg Field +1,762 +1,456.0 +24 +19.1 +1,786 +1,475.1 +Piceance Basin +348 +301.4 +— +— +348 +301.4 +Permian Basin (1) +— +— +58 +54.5 +58 +54.5 +NECO +618 +410.0 +— +— +618 +410.0 +Other +97 +95.0 +3 +0.7 +100 +95.7 +Total Western +2,825 +2,262.4 +85 +74.3 +2,910 +2,336.7 +Eastern +Appalachian Basin +3,568 +1,652.4 +39 +15.5 +3,607 +1,667.9 +Total Eastern +3,568 +1,652.4 +39 +15.5 +3,607 +1,667.9 +Total productive wells +6,393 +3,914.8 +124 +89.8 +6,517 +4,004.6 +__________ +(1) +As of December 31, 2011, our Permian assets were held for sale and, on February 28, 2012, the divestiture closed. See Note 13, Assets Held for Sale, Divestitures and Discontinued Operations, and Note 18, Subsequent Event, to our consolidated financial statements included in this report for additional details related to the divestiture of our Permian assets. +Proved Reserves +Our proved reserves are sensitive to future natural gas and crude oil sales prices and their effect on the economic productive life of producing properties. Increases in commodity prices may result in a longer economic productive life of a property or result in more economically viable proved undeveloped reserves to be recognized. Decreases in commodity prices may result in negative impacts of this nature. +All of our proved reserves are located in the U.S. Our reserve estimates are prepared with respect to reserve categorization, using the definitions for proved reserves set forth in SEC Regulation S-X, Rule 4-10(a) and subsequent SEC staff regulations, interpretations and guidance. All of our proved reserves, as of December, 31, 2011, including the reserves of all subsidiaries consolidated for the purposes of our financial statements, have been estimated by independent petroleum engineers. +We have a comprehensive process that governs the determination and reporting of our proved reserves. As part of our internal control process, our reserves are reviewed annually by an internal team composed of reservoir engineers, geologists and accounting personnel for adherence to SEC guidelines through a detailed review of land records, available geological and reservoir data as well as production performance data. The review includes, but is not limited to, confirmation that reserve estimates (1) include all properties owned, (2) are based on proper working and net revenue interests, and (3) reflect reasonable cost estimates and field performance. The internal team compiles the reviewed data and forwards the data to an independent engineering firm engaged to estimate our reserves. +9 +Our reserve estimates as of December 31, 2011 , were based on a reserve report prepared by Ryder Scott Company, L.P. ("Ryder Scott"). When preparing our reserve estimates, the independent petroleum engineer did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, production volumes, well test data, historical costs of operations and development, product prices, or any agreements relating to current and future operations of properties and sales of production. +The independent petroleum engineer prepares an estimate of our reserves in conjunction with an ongoing review by our engineers. A final comparison of data is performed to ensure that the reserve estimates are complete, determined by acceptable industry methods and to a level of detail we deem appropriate. The final independent petroleum engineer's estimated reserve report is reviewed and approved by our engineering staff and management. +The professional qualifications of the internal lead engineer primarily responsible for overseeing the preparation of our reserve estimates meet the standards of Reserves Estimator as defined in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information as promulgated by the Society of Petroleum Engineers. This employee holds a Bachelor of Science degree in Petroleum and Chemical Refining Engineering with a minor in Petroleum Engineering and has over 30 years of experience in reservoir engineering. The individual is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers and is a registered Professional Engineer in the State of Colorado. +The following tables provide information regarding our estimated proved reserves. Reserves cannot be measured exactly, because reserve estimates involve judgments. The estimates must be reviewed periodically and adjusted to reflect additional information gained from reservoir performance, new geological and geophysical data and economic changes. Neither the estimated future net cash flows nor the standardized measure of discounted future net cash flows ("standardized measure") is intended to represent the current market value of our proved reserves. For additional information regarding both of these measures, as well as other information regarding our proved reserves, see the unaudited Supplemental Information - Natural Gas and Crude Oil Information provided with our consolidated financial statements included in this report. +As of December 31, +2011 (1) +2010 (1) +2009 +Proved reserves +Natural gas (MMcf) (2) +672,145 +657,306 +608,925 +Crude oil and condensate (MBbls) +37,636 +23,236 +18,070 +NGLs (MBbls) (2) +19,588 +10,649 +— +Total proved reserves (MMcfe) +1,015,489 +860,616 +717,345 +Proved developed reserves (MMcfe) (3) +471,347 +301,141 +295,839 +Estimated future net cash flows (in millions) +$ +2,290 +$ +1,315 +$ +764 +PV-10% ( in millions ) (4) +$ +1,350 +$ +693 +$ +360 +Standardized measure (in millions) +$ +941 +$ +488 +$ +348 +__________ +(1) +Includes estimated reserve data related to our Permian assets, which were held for sale as of December 31, 2011, and, on February 28, 2012, the divestiture closed. See Note 13, Assets Held for Sale, Divestitures and Discontinued Operations, and Note 18, Subsequent Event, to our consolidated financial statements included in this report for additional details related to the divestiture of our Permian assets. +The following table sets forth information regarding estimated proved reserves for our Permian assets. +As of December 31, +2011 +2010 +Proved reserves +Natural gas (MMcf) +6,242 +4,979 +Crude Oil and condensate (MBbls) +7,825 +3,331 +NGLs (MBbls) +1,971 +1,190 +Total proved reserves (MMcfe) +65,018 +32,105 +Proved developed reserves (MMcfe) +15,940 +11,416 +Estimated future net cash flows (in millions) +$ +348 +$ +129 +(2) +P rior to 2010, NGLs were included in natural gas, which impacts comparability of 2011 and 2010 to 2009. +(3) +Approximately 73.4% of the increase in proved developed reserves from December 31, 2010, to December 31, 2011, was due to the reclassification of our estimated Wattenberg refracture reserves from proved undeveloped to proved developed as a result of the greater difference between the cost of a refracture and the cost of drilling a new well. +(4) +PV-10% is a non-U.S. GAAP financial measure. This non-U.S. GAAP measures is not a measure of financial or operating performance under U.S. GAAP, nor is it intended to represent the current market value of our estimated reserves. PV-10% should not be considered in isolation or as a substitute for the standardized measure reported in accordance with U.S. GAAP, but rather should be considered in addition to the standardized measure. See Part I, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Reconciliation of Non-U.S. +10 +GAAP Financial Measures, for a definition of PV-10% and a reconciliation of our PV-10% value to the standardized measure. +As of December 31, 2011 +Operating Region/Area +Natural Gas +(MMcf) +NGLs +(MBbls) +Crude Oil and Condensate (MBbls) +Natural Gas +Equivalent +(MMcfe) +Percent +Proved developed +Western +Wattenberg Field +113,911 +11,203 +14,788 +269,857 +58 +% +Piceance Basin +108,642 +— +231 +110,028 +23 +% +Permian Basin (1) +1,750 +550 +1,815 +15,940 +3 +% +Other +31,940 +— +— +31,940 +7 +% +Total Western +256,243 +11,753 +16,834 +427,765 +91 +% +Eastern +Appalachian Basin +43,126 +— +76 +43,582 +9 +% +Total Eastern +43,126 +— +76 +43,582 +9 +% +Total proved developed +299,369 +11,753 +16,910 +471,347 +100 +% +Proved undeveloped +Western +Wattenberg Field +64,071 +6,414 +14,506 +189,591 +35 +% +Piceance Basin +210,467 +— +210 +211,727 +39 +% +Permian Basin (1) +4,492 +1,421 +6,010 +49,078 +9 +% +Other +3,194 +— +— +3,194 +* +Total Western +282,224 +7,835 +20,726 +453,590 +83 +% +Eastern +Appalachian Basin +90,552 +— +— +90,552 +17 +% +Total Eastern +90,552 +— +— +90,552 +17 +% +Total proved undeveloped +372,776 +7,835 +20,726 +544,142 +100 +% +Proved reserves +Western +Wattenberg Field +177,982 +17,617 +29,294 +459,448 +46 +% +Piceance Basin (2) +319,109 +— +441 +321,755 +32 +% +Permian Basin (1) +6,242 +1,971 +7,825 +65,018 +6 +% +Other +35,134 +— +— +35,134 +3 +% +Total Western +538,467 +19,588 +37,560 +881,355 +87 +% +Eastern +Appalachian Basin +133,678 +— +76 +134,134 +13 +% +Total Eastern +133,678 +— +76 +134,134 +13 +% +Total proved reserves +672,145 +19,588 +37,636 +1,015,489 +100 +% +______________ +* De Minimis +(1) +As of December 31, 2011, our Permian assets were held for sale and, on February 28, 2012, the divestiture closed. See Note 13, Assets Held for Sale, Divestitures and Discontinued Operations, and Note 18, Subsequent Event, to our consolidated financial statements included in this report for additional details related to the divestiture of our Permian assets. +(2) +Two leases in our Piceance Basin represent 32% of our total proved reserves. +11 +Developed and Undeveloped Acreage +The following table presents our developed and undeveloped lease acreage . +As of December 31, 2011 +Developed +Undeveloped (1) +Total +Operating Region/Area +Gross +Net +Gross +Net +Gross +Net +Western +Wattenberg Field +53,300 +51,200 +28,800 +20,200 +82,100 +71,400 +Piceance Basin +3,100 +3,100 +4,900 +4,900 +8,000 +8,000 +Permian Basin (2) +3,800 +3,800 +3,400 +6,800 +6,500 +10,600 +9,900 +NECO +23,600 +19,600 +81,500 +71,700 +105,100 +91,300 +Other +400 +400 +22,100 +18,000 +22,500 +18,400 +Total Western +84,200 +77,700 +144,100 +121,300 +228,300 +199,000 +Eastern +Appalachian Basin +263,900 +107,300 +50,000 +33,150 +313,900 +140,450 +Total Eastern +263,900 +107,300 +50,000 +33,150 +313,900 +140,450 +Total acreage +348,100 +185,000 +194,100 +154,450 +542,200 +339,450 +__________ +(1) +With the exception of our Eastern Operating Region properties prospective for the Utica Shale, substantially all of our undeveloped acreage is related to leaseholds that are held by production. Approximately 15% of our undeveloped leaseholds expire during 2012, none of which is material to any one specific area. +(2) +As of December 31, 2011, our Permian assets were held for sale and, on February 28, 2012, the divestiture closed. See Note 13, Assets Held for Sale, Divestitures and Discontinued Operations, and Note 18, Subsequent Event, to our consolidated financial statements included in this report for additional details related to the divestiture of our Permian assets. +Title to Properties +We believe that we hold good and defensible title to our natural gas and crude oil properties, in accordance with standards generally accepted in the industry. As is customary in the industry, a preliminary title examination is conducted at the time the undeveloped properties are acquired. Prior to the commencement of drilling operations, a title examination is conducted and remedial work is performed with respect to discovered defects which we deem to be significant. Title examinations have been performed with respect to substantially all of our producing properties. +The properties we own are subject to royalty , overriding royalt y and other outstanding interests customary to the industry. The properties may also be subject to additional burdens, liens or encumbrances customary to the industry, including items such as operating agreements, current taxes, development obligations under natural gas and crude oil leases, farm-out agreements and other restrictions. We do not believe that any of these burdens will materially interfere with our use of the properties. +Substantially all of our natural gas and crude oil properties, excluding properties held by PDCM, have been mortgaged or pledged as security for our corporate credit facility. Substantially all of our Eastern Operating Region properties, excluding our Ohio acreage, have been pledged as security for PDCM's credit facility. See Note 8, Long-Term Debt , to our consolidated financial statements included in this report. +Facilities +We lease 39,720 square feet in Denver, Colorado, which serves as our corporate offices, through December 2015. We own a 32,000 square feet administrative office building located in Bridgeport, West Virginia, where we also lease approximately 18,600 square feet of office space in a second building through October 2014. +We own or lease field operating facilities in the following locations: +• +Colorado: Evans, Parachute and Wray +• +Pennsylvania: Indiana and Mahaffey +• +Texas: Midland +• +West Virginia: Bridgeport, Buckhannon and Glenville +Governmental Regulation +While the prices of natural gas and crude oil are market driven, other aspects of our business and the industry in general are heavily regulated. The availability of a ready market for natural gas and crude oil production depends on several factors beyond our control. These factors include regulation of production, federal and state regulations governing environmental quality and pollution control, the amount of +12 +natural gas and crude oil available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. In general, state and federal regulations are intended to protect consumers from unfair treatment and oppressive control, to reduce environmental and health risks from the development and transportation of natural gas and crude oil, to prevent misuse of natural gas and crude oil and to protect rights among owners in a common reservoir. Pipelines are subject to the jurisdiction of various federal, state and local agencies. In the western part of the U.S., governments own a large percentage of the land and control the right to develop natural gas and crude oil. Government leases may be subject to additional regulations and controls not common to private leases. We believe that we are in compliance with such statutes, rules, regulations and governmental orders, although there can be no assurance that this is or will remain the case. The following summary discussion on the regulation of the U.S. oil and gas industry is not intended to constitute a complete discussion of the various statutes, rules, regulations and environmental orders to which our operations may be subject. +Regulation of Natural Gas and Crude Oil Exploration and Production. Our exploration and production business is subject to various federal, state and local laws and regulations on the taxation of natural gas and crude oil, the development, production and marketing of natural gas and crude oil and environmental and safety matters. Many laws and regulations require drilling permits and govern the spacing of wells, rates of production, water discharge, prevention of waste and other matters. Prior to commencing drilling activities for a well, we must procure permits and/or approvals for the various stages of the drilling process from the applicable state and local agencies where the well being drilled is located. Additionally, other regulated matters include: +• +bond requirements in order to drill or operate wells; +• +well locations; +• +drilling and casing methods; +• +surface use and restoration of well properties; +• +well plugging and abandoning; and +• +fluid disposal. +In addition, our drilling activities involve hydraulic fracturing , which may be subject to additional federal and state disclosure and regulatory requirements discussed below in Environmental Matters . +Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the density of wells which may be drilled and the unitization or pooling of properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely primarily or exclusively on voluntary pooling of lands and leases. In areas where pooling is voluntary, it may be more difficult to form units, and therefore, more difficult to develop a project if the operator owns less than 100% of the leasehold. State laws may establish maximum rates of production from natural gas and crude oil wells, generally prohibiting the venting or flaring of natural gas and imposing certain requirements regarding the ratability of production. State or federal leases often include additional regulations and conditions. The effect of these regulations may limit the amount of natural gas and crude oil we can produce from our wells and may limit the number of wells or the locations at which we can drill. Such laws and regulations may increase the costs of planning, designing, drilling, installing, operating and abandoning our natural gas and crude oil wells and other facilities. These laws and regulations, and any others that are passed by the jurisdictions where we have production, can limit the total number of wells drilled or the allowable production from successful wells, which can limit our reserves. As a result, we are unable to predict the future cost or effect of complying with such regulations. +Although we currently hold very little acreage under federal leases, if we were to increase such holdings, then our costs and timing would increase due to the new Bureau of Land Management leasing policies announced in May 2010. These policies change, among other things, a required environmental review, including additional public input related to the proposed leases. +Regulation of Sales and Transportation of Natural Gas. Historically, the price of natural gas was subject to limitation by federal legislation. As of January 1, 1993, The Natural Gas Wellhead Decontrol Act removed all remaining federal price controls from natural gas sold in "first sales" on or after that date. The Federal Energy Regulatory Commission's ("FERC") jurisdiction over natural gas transportation was unaffected by the Decontrol Act. +We move natural gas through pipelines owned by other companies, and sell natural gas to other companies that also utilize common carrier pipeline facilities. Natural gas pipeline interstate transmission and storage activities are subject to regulation by the FERC under the Natural Gas Act of 1938 ("NGA") and under the Natural Gas Policy Act of 1978, and, as such, rates and charges for the transportation of natural gas in interstate commerce, accounting, and the extension, enlargement or abandonment of its jurisdictional facilities, among other things, are subject to regulation. Each natural gas pipeline company holds certificates of public convenience and necessity issued by the FERC authorizing ownership and operation of all pipelines, facilities and properties for which certificates are required under the NGA. Each natural gas pipeline company is also subject to the Natural Gas Pipeline Safety Act of 1968, as amended, which regulates safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities. FERC regulations govern how interstate pipelines communicate and do business with their affiliates. Interstate pipelines may not operate their pipeline systems to preferentially benefit their marketing affiliates. +Each interstate natural gas pipeline company establishes its rates primarily through the FERC’s rate-making process. Key determinants in the ratemaking process are: +• +costs of providing service, including depreciation expense; +• +allowed rate of return, including the equity component of the capital structure and related income taxes; and +13 +• +volume throughput assumptions. +The availability, terms and cost of transportation affect our natural gas sales. In the past, FERC has undertaken various initiatives to increase competition within the industry. As a result of initiatives like FERC Order No. 636, issued in April 1992, the interstate natural gas transportation and marketing system was substantially restructured to remove various barriers and practices that historically limited non-pipeline natural gas sellers, including producers, from effectively competing with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. The most significant provisions of Order No. 636 require that interstate pipelines provide transportation separate or "unbundled" from their sales service, and require that pipelines provide firm and interruptible transportation service on an open access basis that is equal for all natural gas suppliers. In many instances, the result of Order No. 636 and related initiatives has been to substantially reduce or eliminate the interstate pipelines' traditional role as wholesalers of natural gas in favor of providing only storage and transportation services. Another effect of regulatory restructuring is greater access to transportation on interstate pipelines. In some cases, producers and marketers have benefited from this availability. However, competition among suppliers has greatly increased and traditional long-term producer-pipeline contracts are rare. Furthermore, gathering facilities of interstate pipelines are no longer regulated by FERC, thus allowing gatherers to charge higher gathering rates. Historically, producers were able to flow supplies into interstate pipelines on an interruptible basis; however, recently we have seen the increased need to acquire firm transportation on pipelines in order to avoid curtailments or shut-in gas, which could adversely affect cash flows from the affected area. +Additional proposals and proceedings that might affect the industry occur frequently in Congress, FERC, state commissions, state legislatures, and the courts. The industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by FERC and Congress will continue. We cannot determine to what extent our future operations and earnings will be affected by new legislation, new regulations, or changes in existing regulation, at federal, state or local levels. +Environmental Matters +Our operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and restrictive environmental legislation and regulations is expected to continue. To the extent laws are enacted or other governmental actions are taken restricting drilling or imposing environmental protection requirements resulting in increased costs, our business and prospects may be adversely affected. +We generate wastes that may be subject to the Federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes. The U.S. Environmental Protection Agency ("EPA") and various state agencies have adopted requirements that limit the approved disposal methods for certain hazardous and non-hazardous wastes. Furthermore, certain wastes generated by our operations that are currently exempt from treatment as "hazardous wastes" may in the future be designated as "hazardous wastes," and therefore may subject us to more rigorous and costly operating and disposal requirements. +Hydraulic fracturing is commonly used to stimulate production of natural gas and/or crude oil from dense subsurface rock formations such as shales that generally exist between 4,000 and 14,000 feet below ground. We routinely apply fracturing in our drilling programs. The process involves the injection of water, sand and additives under pressure into a targeted subsurface formation. The water and pressure create fractures in the rock formations, which are held open by the grains of sand, enabling the crude oil or natural gas to flow to the wellbore. The process is generally subject to regulation by state oil and gas commissions. However, the EPA recently asserted federal regulatory authority over certain fracturing activities involving diesel under the federal Safe Drinking Water Act ("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, 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. +Certain states in which we operate, including Colorado, Pennsylvania, and Ohio, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, transparency and well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether. In December 2011, Colorado adopted a fracturing chemical disclosure rule wherein all chemicals used in the hydraulic fracturing of a well must be reported in a publicly searchable registry website developed and maintained by the Ground Water Protection Council and Interstate Oil and Gas Compact Commission. Also, in December 2011, West Virginia enacted the Natural Gas Horizontal Well Control Act and amendments to existing laws that together establish a comprehensive, detailed system for permitting and regulation of horizontal natural gas wells. The new law applies to most proposed new natural gas wells. The law imposes far more detailed permitting and regulatory requirements than prior law, and requires further study and authorizes potential rulemaking by the West Virginia Department of Environmental Protection (DEP). Among the new regulatory requirements are: detailed surface owner compensation requirements; performance standards applicable to disposal of drilling cuttings and associated drilling mud, protection of quantity and quality of surface and groundwater systems; advance designation of water withdrawal locations to the DEP, and record keeping and reporting for all flowback and produced water; and restrictions on well locations. In Ohio, in early 2012, officials of the Department of Natural Resources imposed a moratorium on injection drilling of wastewater from fracturing operations within a five mile radius of a well that was suspected as contributing to the cause of earthquakes in the area. +The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the U.S. 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, 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, +14 +with initial results expected to be available by late 2012 and final results by 2014. In addition, the U.S. 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. The U.S. Department of the Interior is considering disclosure requirements or other mandates for hydraulic fracturing on federal lands. These ongoing studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanism. +In Colorado, local governing bodies have begun to issue drilling moratoriums or develop jurisdictional siting, permitting, and operating requirements. If new laws or regulations that significantly restrict hydraulic fracturing, or well locations, are adopted at the state and local level, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from dense subsurface rock formations and, in the event of local prohibitions against commercial production of natural gas, may preclude our ability to drill wells. If hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or other federal agencies, our fracturing activities could become subject to additional permitting requirements and result in permitting delays as well as 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 its reserves. +We currently own or lease numerous properties that for many years have been used for the exploration and production of natural gas and crude oil. Although we believe that we have utilized good operating and waste disposal practices, and when necessary, appropriate remediation techniques, prior owners and operators of these properties may not have utilized similar practices and techniques, and hydrocarbons or other wastes may have been disposed of or released on or under the properties that we own or lease or on or under locations where such wastes have been taken for disposal. These properties and the wastes disposed thereon may be subject to the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), RCRA and analogous state laws, as well as state laws governing the management of natural gas and crude oil wastes. Under such laws, we may be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or remediate property contamination (including surface and groundwater contamination) or to perform remedial plugging operations to prevent future contamination. +CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed of or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for release of hazardous substances under CERCLA may be subject to full liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and 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. As an owner and operator of natural gas and crude oil wells, we may be liable pursuant to CERCLA and similar state laws. +Our operations are subject to the federal Clean Air Act ("CAA") and comparable state and local requirements. Amendments to the CAA were adopted in 1990 and contain provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. The EPA and states have been developing regulations to implement these requirements. We may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues. Greenhouse gas record keeping and reporting requirements of the CAA became effective in 2011 and will continue into the future with increased costs for administration and implementation of controls. The New Source Performance Standards introduced by the EPA in 2011 will become effective in 2012, adding administrative and operational expense. +The federal Clean Water Act ("CWA") and analogous state laws impose strict controls against the discharge of pollutants, including spills and leaks of crude oil and other substances. The CWA also regulates storm water run-off from natural gas and crude oil facilities and requires storm water discharge permits for certain activities. Spill Prevention, Control, and Countermeasure ("SPCC") requirements of the CWA require appropriate secondary containment loadout controls and piping controls to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon spill, rupture or leak. +Crude oil production is subject to many of the same operating hazards and environmental concerns as natural gas production, but is also subject to the risk of crude oil spills. Federal regulations require certain owners or operators of facilities that store or otherwise handle crude oil, including us, to procure and implement SPCC plans relating to the possible discharge of crude oil into surface waters. The Oil Pollution Act of 1990, or OPA, subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from crude oil spills. Noncompliance with OPA may result in varying civil and criminal penalties and liabilities. Historically, we have not experienced any significant crude oil discharge or crude oil spill problems. Our shift in production since mid-2010 to a greater percentage of crude oil enhances our risks related to soil and water contamination. +In late 2011, the State of Colorado's Oil and Gas Conservation Commission ("Commission") adopted rules that require service companies and vendors to disclose all known chemicals in hydraulic fracturing fluid to operators and require operators to disclose such chemicals to the public through a website or, with respect to an operator's trade secrets, directly to the Commission or health professionals. The new rules also require operators seeking new location approvals to provide certain disclosures regarding fracturing to surface owners and adjacent property owners within 500 feet of a new well. These regulations will continue to increase our costs and may ultimately limit some drilling locations. +Our expenses relating to preserving the environment have risen over the past few years and are expected to continue to rise in 2012 +15 +and beyond. Environmental regulations have increased our costs and planning time, but have had no materially adverse effect on our ability to operate to date. However, no assurance can be given that environmental regulations or interpretations of such regulations will not, in the future, result in a curtailment of production or otherwise have a materially adverse effect on our business, financial condition or results of operations. See Note 11, Commitments and Contingencies , to our consolidated financial statements included in this report. +Operating Hazards and Insurance +Our exploration and production operations include a variety of operating risks, including, but not limited to, the risk of fire, explosions, blowouts, cratering, pipe failure, casing collapse, abnormally pressured formations, and environmental hazards such as gas leaks, ruptures and discharges of natural gas and crude oil. The occurrence of any of these could result in substantial losses to us due to injury and loss of life, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. Our pipeline, gathering and distribution operations are subject to the many hazards inherent in the industry. These hazards include damage to wells, pipelines and other related equipment, damage to property caused by hurricanes, floods, fires and other acts of God, inadvertent damage from construction equipment, leakage of natural gas and other hydrocarbons, fires and explosions and other hazards that could also result in personal injury and loss of life, pollution and suspension of operations. +Any significant problems related to our facilities could adversely affect our ability to conduct our operations. In accordance with customary industry practice, we maintain insurance against some, but not all, potential risks; however, there can be no assurance that such insurance will be adequate to cover any losses or exposure for liability. The occurrence of a significant event not fully insured against could materially adversely affect our operations and financial condition. We cannot predict whether insurance will continue to be available at premium levels that justify our purchase or whether insurance will be available at all. Furthermore, we are not insured against our economic losses resulting from damage or destruction to third party property, such as transportation pipelines, crude oil refineries or natural gas processing facilities; such an event could result in significantly lower regional prices or our inability to deliver gas. +Competition and Technological Changes +We believe that our exploration, drilling and production capabilities and the experience of our management and professional staff generally enable us to compete effectively. We encounter competition from numerous other natural gas and crude oil companies, drilling and income programs and partnerships in all areas of operations, including drilling and marketing natural gas and crude oil and obtaining desirable natural gas and crude oil leases on producing properties. Many of these competitors possess larger staffs and greater financial resources than we do, which may enable them to identify and acquire desirable producing properties and drilling prospects more economically. Our ability to explore for natural gas and crude oil prospects and to acquire additional properties in the future depends upon our ability to conduct our operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. We also face intense competition in the marketing of natural gas from competitors including other producers as well as marketing companies. Also, international developments and the possible improved economics of domestic natural gas exploration may influence other companies to increase their domestic natural gas and crude oil exploration. Furthermore, competition among companies for favorable prospects can be expected to continue, and it is anticipated that the cost of acquiring properties will increase in the future. +In 2011, certain regions experienced strong demand for drilling services and supplies, which resulted in increasing costs. Our Wattenberg Field and Eastern Operating Region, specifically our properties in West Virginia, experienced intense competition for drilling and pumping services. Factors affecting competition in the industry include price, location of drilling, availability of drilling prospects and drilling rigs, fracturing services, pipeline capacity, quality of production and volumes produced. We believe that we can compete effectively in the industry in each of the areas where we have operations. Nevertheless, our business, financial condition and results of operations could be materially adversely affected by competition. We also compete with other natural gas and crude oil companies as well as companies in other industries for the capital we need to conduct our operations. Should economic conditions deteriorate and financing become more expensive and difficult to obtain, we may not have adequate capital to execute our business plan and we may be forced to curtail our drilling and acquisition activities. +The oil and gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial position, results of operations and cash flows could be materially adversely affected. +Employees +As of December 31, 2011 , we had 404 employees. Our employees are not covered by a collective bargaining agreement. We consider relations with our employees to be good. +Our engineers, supervisors and well tenders are responsible for the day-to-day operation of wells and some pipeline systems. Much of the work associated with drilling, completing and connecting wells, including fracturing, logging and pipeline construction, is performed under our direction by subcontractors specializing in these activities as is common in the industry. +16 +ITEM 1A. RISK FACTORS +You should carefully consider the following risk factors in addition to the other information included in this report. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common stock or other securities. +Risks Related to the Domestic and Global Economic Environment +The current slow economic growth both domestically and globally may not improve or there may be a reoccurrence of the disruptions during the recent recession in the global financial markets and the related economic environment may further decrease the demand for natural gas and crude oil and the prices of natural gas and crude oil, negatively impacting our future drilling and production, and adversely affecting our financial condition and profitability. +The global financial market disruptions during the recent recession and the related economic environment initially resulted in a decrease, and more recently in 2011, limited growth in the demand for natural gas and crude oil and has maintained pressure on natural gas prices. For example, during 2011, the price for natural gas decreased another 8% from 2010 rates, which were over 60% below the 2008 peak. Crude oil prices rebounded in 2011, increasing 20% over 2010 rates, but were still 28% below the 2008 peak. While crude oil prices have remained relatively strong, the continued growth in production of natural gas has increased supply and resulted in record gas storage inventories. As a result natural gas prices continue to face downward pressure. There is no certainty how long this low price environment would continue. We operate in a highly competitive industry, and certain competitors may have lower operating costs in such an environment. In particular, consider the risks related to (1) the deterioration of demand for natural gas and crude oil products and the related negative impact on natural gas and crude oil pricing, and (2) the deterioration of the financial markets and the related challenges, constraints or inability to raise necessary capital or maintain sufficient liquidity to access and provide the capital necessary to fund our operations. Further reductions in natural gas and crude oil prices could result in some of our assets becoming uneconomic to exploit, which would reduce our economically viable reserve profile. Counterparty failure risk would increase for both the banks which provide us capital and are parties to our natural gas and crude oil derivative holdings and for purchasers of our natural gas and crude oil. A prolonged and material negative economic environment could lead to the curtailment of capital expenditures and therefore a reduction in our drilling program, which would result in reduced production, reserves, cash flow generation and financial results. +Credit and funding challenges of French banks which are participants in our revolving credit facility and counterparties to some of our natural gas and crude oil derivative holdings could have a material adverse effect on our operations and financial condition . +We have three French banks, Credit Agricole Corporate and Investment Bank ("CA"), BNP Paribas ("BNP") and Natixis (collectively "the French Banks") that participate in our revolving credit facility and are counterparties to some of our natural gas and crude oil derivative hedges. The recent global economic turmoil, particularly in Europe, has led to negative credit actions and created an increased cost for the French Banks to provide U.S. dollar funding under contractually committed U.S. credit facilities. Certain of the French Banks have provided public disclosures as to the challenges they are experiencing. BNP has announced that it plans to divest both its U.S. hedging holdings and activities and its U.S. dollar energy portfolio; CA has announced that it is divesting its U.S. hedging holdings and activities. We are unaware of any announced divestitures by Natixis. We have had numerous discussions with senior bank representatives from each of the French Banks, and their representatives have indicated they plan to hold their current position in our revolving credit facility and intend to fund borrowing requests as contractually required. Additionally, the French Banks have indicated that they intend to satisfy their contractual counterparty obligations on all natural gas and crude oil derivative holdings with us. Moreover, the French Banks have been performing to date under our revolving credit facility and as hedging counterparties. However, should the need arise, we believe we would be able to replace our current French Banks borrowing and hedging capacity through increased credit provision from our existing bank syndicate or through the addition of additional banks to our bank syndicate. In light of the preceding challenges confronting our French bank credit providers, and despite the numerous mitigants to offset the situation, we cannot assure that we can replace the borrowing capacity being provided to us by the French Banks should the need arise, or that the French Banks will continue to perform under our revolving credit facility or as hedging counterparties in the future. Should we be unable to replace such borrowing capacity, or should the French Banks fail to perform, those events could have a material adverse effect on our operations and financial condition. +While we believe that we will be able to find other banking institutions to be effective counterparties for our derivatives instruments in the future, it is possible that the loss of these banks from the class of available banking institutions that become counterparties for U.S. derivative instruments will significantly reduce the number of banking institutions that write such instruments and serve as counterparties. In this event, it is possible that we might not be able to find comparable counterparties to write derivatives instruments as readily as before these banks determined to leave the U.S. hedging market. Additionally, even if we are readily able to contract with such counterparties, the cost of these derivatives instruments might be greater than those that we have to date become a party to, thereby diminishing the economic effectiveness of those derivatives instruments that we in fact do write. Moreover, it is possible that with new counterparties to our derivatives instruments the risk of counterparty default on such derivatives instruments might increase. +Risks Related to Our Business and the Industry +Natural gas and crude oil prices fluctuate and a decline in natural gas and crude oil prices can significantly affect the value of our assets, our financial results and impede our growth. +Our revenue, profitability and cash flow depend in large part upon the prices and demand for natural gas and crude oil. The markets +17 +for these commodities can be volatile, and significant drops in prices can negatively affect our financial results and impede our growth. For instance, in much of 2011, natural gas prices were too low to economically justify drilling operations in several areas. Changes in natural gas and crude oil prices have a significant effect on our cash flow and on the value of our reserves, which can in turn reduce our borrowing base under our senior credit facility. Prices for natural gas and crude oil may fluctuate in response to relatively minor changes in the supply of and demand for natural gas and crude oil, market uncertainty and a variety of additional factors that are beyond our control, including national and international economic and political factors and federal and state legislation. In addition to factors affecting the price of oil and natural gas generally, the prices we receive for our oil and natural gas production are affected by factors specific to us and to the local markets where the production occurs. Pricing can be influenced by, among other things, local or regional supply and demand factors (such as refinery or pipeline capacity issues, trade restrictions and governmental regulations) and the terms of our sales contracts. In addition, any substantial reduction in the growth rate of China could affect global oil prices significantly. +Lower natural gas and crude oil prices may not only reduce our revenues, but also may reduce the amount of natural gas and crude oil that we can produce economically. As a result, we may have to make substantial additional downward adjustments to our estimated proved reserves. If this occurs or if our estimates of development costs increase, production data factors change or our exploration results deteriorate, accounting rules may require us to write-down operating assets to fair value, as a non-cash charge to earnings. We assess impairment of capitalized costs of proved natural gas and crude oil properties by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which management reasonably estimates such products may be sold. In 2011 and 2010, we recorded an impairment charge related to our NECO proved natural gas and crude oil properties of $22.5 million and related to our Michigan proved natural gas and crude oil properties an impairment of $4.7 million, respectively. These impairments were attributable to our decision to divest these assets. We may incur impairment charges in the future, which could have a material adverse effect on the results of our operations. +Our ability to produce natural gas and crude oil could be impaired if we are unable to acquire adequate supplies of water for our drilling and completion operations or are unable to dispose of the water we use at a reasonable cost and within applicable environmental rules. +Our operations could be adversely impacted if we are unable to locate sufficient amounts of water, or dispose of or recycle water used in our exploration and production operations. Currently, the quantity of water required in certain completion operations, such as hydraulic fracturing, and changing regulations on usage may lead to water constraints and supply concerns. As a result, future availability of water from certain sources used in the past may be limited. 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 waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of oil and natural gas. The CWA imposes restrictions and strict controls regarding the discharge of produced waters and other oil and natural gas waste into navigable waters. Permits must be obtained to discharge pollutants to waters and to conduct construction activities in waters and wetlands. The CWA 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 Federal National Pollutant Discharge Elimination System general permits issued by the EPA, prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into coastal waters. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Indeed, on October 20, 2011, the EPA announced its intention to develop federal pretreatment standards for wastewater discharges associated with hydraulic fracturing activities. If adopted, the new pretreatment rules will require coalbed methane and shale gas operations to pretreat wastewater before transferring it to treatment facilities. Proposed rules are expected in 2013 for coalbed methane and 2014 for shale gas. We cannot predict the impact that these standards may have on our business at this time, but these standards could have a material impact on our business, financial condition and results of operations. Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells will increase our operating costs and may cause delays, interruptions or termination of our operations, the extent of which cannot be predicted. In addition, our inability to meet our water supply needs to conduct our completion operations may impact our business, and any such future laws and regulations could negatively affect our financial condition and results of operations. +Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional drilling and operating restrictions or delays in the production of natural gas and crude oil, including from the development of shale plays. A decline in the drilling of new wells and related servicing activities caused by these initiatives could adversely affect our financial condition, results of operations and cash flows. +Most of our drilling uses hydraulic fracturing. Proposals have been introduced in the U.S. Congress to regulate hydraulic fracturing operations and related injection of fracturing fluids and propping agents used by the oil and natural gas industry in fracturing fluids under the SDWA, and to require the disclosure of chemicals used in the hydraulic fracturing process under the SDWA, Emergency Planning and Community Right-to-Know Act ("EPCRA"), or other laws. Hydraulic fracturing is an important and commonly used process in the completion of unconventional natural gas and crude oil wells in shale, coalbed and tight sand formations. Sponsors of these bills, which are currently being considered in the legislative process, including the House Energy and Commerce Committee and the Senate Environmental and Public Works Committee, have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies and otherwise cause adverse environmental impacts. The Chairman of the House Energy and Commerce Committee has initiated an investigation of the potential impacts of hydraulic fracturing, which has involved seeking information about fracturing activities and chemicals from certain companies in the oil and natural gas sector. The EPA has recently focused on citizen concerns about the risk of water contamination and public health problems from drilling and hydraulic fracturing activities, including public meetings around the country on this issue which have been well publicized and well attended. In March 2010, the EPA announced its intention to conduct a comprehensive research study on +18 +the potential adverse impacts that hydraulic fracturing may have on water quality and public health. The initial results are expected in the fall of 2012. +Several states have also proposed additional disclosure concerning chemicals used in the process. New York has imposed a moratorium on hydraulic fracturing of horizontal wells pending additional environmental investigation by the state. Lawsuits have also been filed against unrelated third parties in Pennsylvania and New York alleging contamination of drinking water by hydraulic fracturing. Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to natural gas and crude oil production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or lead us to incur increased operating costs in the production of natural gas and crude oil, including from the development of shale plays, or could make it more difficult to perform hydraulic fracturing. If these legislative and regulatory initiatives cause a material decrease in the drilling of new wells and in related servicing activities, our profitability could be materially impacted. +A substantial part of our natural gas and crude oil production is located in our Western Operating Region, making it vulnerable to risks associated with operating primarily in a single geographic area. +Our operations have been focused in the Wattenberg Field and Piceance Basin of our Western Operating Region, which means our current producing properties and new drilling opportunities are geographically concentrated in that area. Because our operations are not as diversified geographically as many of our competitors, the success of our operations and our profitability may be disproportionately exposed to the effect of any regional events, including fluctuations in prices of natural gas and crude oil produced from the wells in the region, natural disasters, restrictive governmental regulations, transportation capacity constraints, curtailment of production or interruption of transportation, and any resulting delays or interruptions of production from existing or planned new wells. For example, the recent increase in activity in the Niobrara could lead to bottlenecks in processing that negatively affect our results disproportionately compared to our more geographically diverse competitors. +Prior to 2010, natural gas prices in the Rocky Mountain Region often fell disproportionately when compared to other markets, due in part to continuing constraints in transporting natural gas from producing properties in the region. Because of the concentration of our operations in our Western Operating Region, such price decreases are more likely to have a material adverse effect on our revenue, profitability and cash flow than those of our more geographically diverse competitors. During 2010 and 2011, natural gas prices in the Rocky Mountain Region were not steeply discounted to NYMEX and future prices are trading at the same discount; however, there can be no assurance as to such continuation. In view of the concentration of our operations in Colorado, a significant decline in natural gas prices in the Western Operating Region could have a material adverse effect on our operations, financial condition and results of operations. +Our estimated natural gas and crude oil reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves. +Natural gas and crude oil reserve engineering requires subjective estimates of underground accumulations of natural gas and crude oil and assumptions concerning natural gas and crude oil prices, production levels, and operating and development costs over the economic life of the properties. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be inaccurate. Independent petroleum engineers prepare our estimates of natural gas and crude oil reserves using pricing, production, cost, tax and other information that we provide. The reserve estimates are based on certain assumptions regarding natural gas and crude oil prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect: +• +the economically recoverable quantities of natural gas and crude oil attributable to any particular group of properties; +• +future depreciation, depletion and amortization ("DD&A") rates and amounts; +• +impairments in the value of our assets; +• +the classifications of reserves based on risk of recovery; +• +estimates of the future net cash flows; +• +timing of our capital expenditures; and +• +the amount of funds available for us to utilize under our revolving credit facility. +Some of our reserve estimates must be made with limited production history, which renders these reserve estimates less reliable than estimates based on a longer production history. Reserve estimates are based on the volumes of natural gas, NGLs and crude oil that are anticipated to be economically recoverable from a given date forward based on economic conditions that exist at that date. The actual quantities of natural gas, NGLs and crude oil recovered will be different than the reserve estimates since they will not be produced under the same economic conditions as used for the reserve calculations. In addition, quantities of probable and possible reserves by definition are inherently more risky than proved reserves and are less likely to be recovered. +The present value of our estimated future net cash flows from proved reserves is not necessarily the same as the current market value of our estimated natural gas and crude oil reserves. The estimated discounted future net cash flows from proved reserves were based on the prior 12-month average natural gas and crude oil index prices. However, factors such as actual prices we receive for natural gas and crude oil and hedging instruments, the amount and timing of actual production, amount and timing of future development costs, supply of and demand for natural gas and crude oil, and changes in governmental regulations or taxation also affect our actual future net cash flows from our natural gas and crude oil properties. +The timing of both our production and incurrence of expenses in connection with the development and production of natural gas +19 +and crude oil properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor (the rate required by the SEC) we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates currently in effect and risks associated with our natural gas and crude oil properties or the industry in general. +Unless natural gas and crude oil reserves are replaced as they are produced, our reserves and production will decline, which would adversely affect our future business, financial condition and results of operations. +Producing natural gas and crude oil reservoirs generally is characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The rate of decline will change if production from existing wells declines in a different manner than we estimated and the rate can change due to other circumstances. Thus, our future natural gas and crude oil reserves and production and, therefore, our cash flow and income, are highly dependent on efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, discover or acquire additional reserves to replace our current and future production at acceptable costs. As a result, our future operations, financial condition and results of operations would be adversely affected. +Acquisitions are subject to the uncertainties of evaluating recoverable reserves and potential liabilities, including environmental uncertainties. +Acquisitions of producing properties and undeveloped properties have been an important part of our historical and recent growth. We expect acquisitions will also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, many of which are beyond our control. These factors include recoverable reserves, development potential, future natural gas and crude oil prices, operating costs and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain, including those regarding the validity of our assumptions about reserves, future production, future commodity prices, revenues, capital expenditures and operating costs, including synergies. In connection with our assessments, we perform engineering, geological and geophysical reviews of the acquired properties, which we believe are generally consistent with industry practices. However, such reviews are not likely to permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well prior to an acquisition and our ability to evaluate undeveloped acreage is inherently imprecise. Even when we inspect a well, we may not always discover structural, subsurface and environmental problems that may exist or arise. In some cases, our review prior to signing a definitive purchase agreement may be even more limited. +The acquisitions of producing natural gas and crude oil properties may increase our potential exposure to liabilities and costs for environmental and other problems existing on acquired properties. Often we are not entitled to contractual indemnification associated with acquired properties. We often acquire interests in properties on an "as is" basis with no or limited remedies for breaches of representations and warranties. We could incur significant unknown liabilities, including environmental liabilities, natural disasters or experience losses due to title defects, in our acquisitions for which we have limited or no contractual remedies or insurance coverage. In addition, the acquisition of undeveloped acreage is subject to many inherent risks and we may not be able to efficiently realize the assumed or expected economic benefits of acreage that we acquire, if at all. +Additionally, significant acquisitions can change the nature of our operations 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. We acquire interests in wells which we may need to operate together with other partners, and we acquire pipelines that we may need to operate and expect we may need to commit to drilling in the acquired areas to achieve the expected benefits. Consequently, we may not be able to efficiently realize the assumed or expected economic benefits of properties that we acquire, if at all. +We may not be able to consummate additional prospective acquisitions of our drilling partnerships, which could adversely affect our business operations. +We have previously disclosed our intention to pursue, beginning in the fall of 2010 and extending through 2013, the acquisition of the limited partnership units held by non-affiliated investor partners in the drilling partnerships that we have sponsored. We may be unable to make additional acquisitions of such affiliated drilling partnerships since consummation of any future acquisitions of our affiliated public drilling partnerships may be subject to the same procedural processes that were utilized in connection with our previously completed acquisitions of public drilling partnerships. Such procedural hurdles previously included, and may in the future include, among others: +• +negotiation and execution of a merger agreement with a special committee, comprised entirely of non-employee directors, of our board of directors; +• +clearance from the SEC upon completion by each of the partnerships of their SEC proxy disclosure review process before the partnerships can request approval of the merger transactions from their non-affiliated investors; and +• +approval by the holders of a majority of the limited partnership units held by the non-affiliated investors of each respective partnership. +In addition, two former non-affiliated investor partners have initiated litigation concerning our acquisition of the limited partnership units we acquired in 2010 and 2011. Litigation challenges to further acquisitions are also possible. If we are unable to consummate all or a portion of these prospective acquisitions, we would not realize the expected benefits of the proposed acquisitions. In addition, we will have incurred, and will remain liable for, transaction costs, including legal, accounting, financial advisory and other costs relating to the prospective acquisitions, including the costs of the financial and legal consultants to the special committee of our board of directors, whether +20 +or not they are consummated. We currently do not have any drilling partnership acquisitions pending or planned in 2012; however, future acquisitions are possible. The occurrence of any of these events individually or in combination could have an adverse effect on our business, financial condition and results of operations. +Any acquisitions we complete, including prospective acquisitions, are subject to substantial risks including integration risks that could adversely affect our financial condition and results of operations. +Even if we complete the prospective acquisitions, integration of the prospective acquisitions may be difficult. Any acquisition involves potential risks, including, among other things: +• +the validity of our assumptions about reserves, future production, future commodity prices, +revenues, capital expenditures and operating costs, including synergies; +• +an inability to integrate the businesses we acquire successfully; +• +a decrease in our liquidity by using a portion of our available cash or borrowing capacity under +our revolving credit facility to finance acquisitions; +• +a significant increase in our interest expense or financial leverage if we incur additional debt to +finance acquisitions; +• +the assumption of unknown liabilities, losses or costs, including those that are environmental, for +which we are not indemnified or for which our indemnity is inadequate; +• +the diversion of management’s attention from other business concerns; +• +the incurrence of other significant charges, such as impairment of natural gas and crude oil properties, +goodwill or other intangible assets, asset devaluation or restructuring charges; +• +unforeseen difficulties encountered in operating in new geographic areas; and +• +customer or key employee losses at the acquired businesses. +If we fail to realize the benefits we anticipate from an acquisition, our results of operations may be adversely affected. +When drilling prospects, we may not yield natural gas or crude oil in commercially viable quantities. +A prospect is a property on which our geologists have identified what they believe, based on available information, to be indications of natural gas or crude oil bearing rocks. However, our geologists cannot know conclusively prior to drilling and testing whether natural gas or crude oil will be present or, if present, whether natural gas or crude oil will be present in sufficient quantities to repay drilling or completion costs and generate a profit given the available data and technology. If a well is determined to be dry or uneconomic, which can occur even though it contains some natural gas or crude oil, it is classified as a dry hole and must be plugged and abandoned in accordance with applicable regulations. This generally results in the loss of the entire cost of drilling and completion to that point, the cost of plugging, and lease costs associated with the prospect. Even wells that are completed and placed into production may not produce sufficient natural gas and crude oil to be profitable. If we drill a dry hole or unprofitable well on current and future prospects, the profitability of our operations will decline and our value will likely be reduced. In sum, the cost of drilling, completing and operating any well is often uncertain and new wells may not be productive. +We may not be able to identify and acquire enough attractive prospects on a timely basis to meet our development needs, which could limit our future development opportunities and adversely affect our profitability. +Our geologists have identified a number of potential drilling locations on our existing acreage. These drilling locations must be replaced as they are drilled for us to continue to grow our reserves and production. Our ability to identify and acquire new drilling locations depends on a number of uncertainties, including the availability of capital, regulatory approvals, natural gas and crude oil prices, competition, costs, availability of drilling rigs, drilling results and the ability of our geologists to successfully identify potentially successful new areas to develop. Because of these uncertainties, our profitability and growth opportunities may be limited by the timely availability of new drilling locations. As a result, our operations and profitability could be adversely affected. +Drilling for and producing natural gas and crude oil are high risk activities with many uncertainties that could adversely affect our business, financial condition and results of operations. Our drilling risk exposure may be increased as we plan to devote most of our 2012 capital budget to drilling horizontal wells. +Drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for natural gas and crude oil can be unprofitable, not only due to dry holes, but also due to curtailments, delays or cancellations as a result of other factors, including: +• +unusual or unexpected geological formations; +• +pressures; +• +fires; +• +blowouts; +• +loss of drilling fluid circulation; +• +title problems; +• +facility or equipment malfunctions; +• +unexpected operational events; +• +shortages or delivery delays of equipment and services; +21 +• +compliance with environmental and other governmental requirements; and +• +adverse weather conditions. +Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and regulatory penalties. We maintain insurance against various losses and liabilities arising from operations; however, insurance against certain operational risks may not be available or may be prohibitively expensive relative to the perceived risks presented. Thus, losses could occur for uninsurable or uninsured risks or for amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance and/or the governmental response to an event could have a material adverse effect on our business activities, financial condition and results of operations. +Our business strategy focuses on production in our liquid-rich and high impact shale gas plays. In this regard, we plan to allocate our capital to an active horizontal drilling program. During 2012, we intend to devote a substantial part of our capital budget to drilling horizontal wells in the Wattenberg Field in Colorado to exploit the Niobrara formation. While we drilled 195 total wells in 2011, we plan to drill approximately 35 wells during 2012. Substantially all of these wells will be horizontal wells. Drilling horizontal wells is technologically more difficult than drilling vertical wells, and thus the risk of failure is far greater than the risk involved in drilling vertical wells. Additionally, drilling horizontal wells is far costlier than drilling vertical wells. Consequently, because we plan to drill far fewer wells during 2012, the risk of drilling a non-economic well will be relatively higher than if we were to drill a similar number of wells as we did in previous years. Furthermore, because of the relatively higher cost in drilling horizontal wells, a completed well to be successful economically will need to have production that will cover the higher drilling costs involved in drilling horizontal wells. While we believe that the Company will be better served by our drilling horizontal wells, the risk component involved in such drilling will be increased, with the result that we might find it more difficult to achieve economic success in our horizontal drilling program. +Our hydrocarbon drilling, transportation and processing activities are subject to a range of applicable federal, state and local laws and regulations. A loss of containment of hydrocarbons during these activities could potentially subject us to civil and/or criminal liability and the possibility of substantial costs, including environmental remediation, depending upon the circumstances of the loss of containment, the nature and scope of the loss and the applicable laws and regulations. We are currently involved in various remedial and investigatory activities at some of our wells and related sites. See Note 11, Commitments and Contingencies - Environmental , to our consolidated financial statements included in this report. +Under the "successful efforts" accounting method that we use, unsuccessful exploratory wells must be expensed in the period when they are determined to be non-productive, which reduces our net income in such periods and could have a negative effect on our profitability. +We have conducted exploratory drilling and plan to continue exploratory drilling in 2012 in order to identify additional opportunities for future development. Under the "successful efforts" method of accounting that we use, the cost of unsuccessful exploratory wells must be charged to expense in the period when they are determined to be unsuccessful. In addition, lease costs for acreage condemned by the unsuccessful well must also be expensed. In contrast, unsuccessful development wells are capitalized as a part of the investment in the field where they are located. Because exploratory wells generally are more likely to be unsuccessful than development wells, we anticipate that some or all of our exploratory wells may not be productive. The costs of such unsuccessful exploratory wells could result in a significant reduction in our profitability in periods when the costs are required to be expensed and have a negative effect on our debt covenants. +Increasing finding and development costs may impair our profitability. +In order to continue to grow and maintain our profitability, we must annually add new reserves that exceed our yearly production at a finding and development cost that yields an acceptable operating margin and DD&A rate. Without cost effective exploration, development or acquisition activities, our production, reserves and profitability will decline over time. Given the relative maturity of most natural gas and crude oil basins in North America and the high level of activity in the industry, the cost of finding new reserves through exploration and development operations has been increasing. The acquisition market for natural gas and crude oil properties has become extremely competitive among producers for additional production and expanded drilling opportunities in North America. Acquisition values for crude +oil properties climbed in 2010 and 2011 and these values may continue to increase in the future. This increase in finding and development costs results in higher DD&A rates. If the upward trend in crude oil finding and development costs continues, we will be exposed to an increased likelihood of a write-down in carrying value of our crude oil properties in response to any future falling commodity prices and reduced profitability of our operations. +Our development and exploration operations require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our natural gas and crude oil reserves, and ultimately our profitability. +Our industry is capital intensive. We expect to continue to make substantial capital expenditures in our business and operations for the exploration, development, production and acquisition of natural gas and crude oil reserves. To date, we have financed capital expenditures primarily with bank borrowings under our credit facility, cash generated by operations and capital markets, through the sale of equity and the issuance of debt securities and sale of properties. We intend to finance our future capital expenditures utilizing similar financing sources. Our cash flows from operations and access to capital are subject to a number of variables, including: +• +our proved reserves; +• +the amount of natural gas and crude oil we are able to produce from existing wells; +• +the prices at which natural gas and crude oil are sold; +22 +• +the costs to produce natural gas and crude oil; and +• +our ability to acquire, locate and produce new reserves. +If our revenues or the borrowing base under our credit facility decreases as a result of lower natural gas and crude oil prices, operating difficulties, declines in reserves or for any other reason, then we may have limited ability to obtain the capital necessary to sustain our operations at current levels. We may, from time to time, need to seek additional financing. If we raise funds by issuing equity securities, this would have a dilutive effect on existing shareholders. There can be no assurance as to the availability or terms of any additional financing. Our inability to obtain additional financing, or sufficient financing on favorable terms, would adversely affect our financial condition and profitability. +If our revenues or the borrowing base under our revolving credit facility decreases as a result of lower natural gas and crude oil prices, or we incur operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at planned levels, and our profitability may be adversely affected. +If additional capital is needed, we may not be able to obtain debt or equity financing on favorable terms, or at all. If cash generated by our operations or available under our revolving credit facility is not sufficient to meet our capital requirements, failure to obtain additional financing could result in a curtailment of the exploration and development of our prospects, which in turn could lead to a possible loss of properties, decline in natural gas and crude oil reserves and production and a decline in our profitability. +Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate. +Seasonal weather conditions and lease stipulations designed to protect various wildlife affect natural gas and crude oil operations in our Western Operating Region. In certain areas, including parts of the Piceance Basin in Colorado, drilling and other natural gas and crude oil activities are restricted or prohibited by lease stipulations, or prevented by weather conditions, for up to six months out of the year. This limits our operations in those areas and can intensify competition during those months for drilling rigs, oil field equipment, services, supplies and qualified personnel, which may lead to additional or increased costs or periodic shortages. These constraints and the resulting high costs or shortages could delay our operations and materially increase operating and capital costs and therefore adversely affect our profitability. +We have limited control over activities on properties in which we own an interest but we do not operate, which could reduce our production and revenues. +We operate approximately 88% of the wells in which we own an interest. If we do not operate the properties in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of underlying properties. The failure by an operator to adequately perform operations, or an operator’s breach of the applicable agreements, could reduce production and revenues and adversely affect our profitability. The success and timing of drilling and development activities on properties operated by others therefore depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise (including safety and environmental compliance) and financial resources, inclusion of other participants in drilling wells, and use of technology. +Market conditions or operational impediments, including transportation and gathering systems, could hinder our access to natural gas and crude oil markets or delay production and thereby adversely affect our profitability. +Market conditions or the unavailability of satisfactory natural gas and crude oil transportation arrangements may hinder our access to natural gas and crude oil markets or delay our production. The availability of a ready market for natural gas and crude oil production depends on a number of factors, including the demand for and supply of natural gas and crude oil and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells for the lack of a market or because of inadequacy, unavailability or the pricing associated with natural gas pipelines, gathering system capacity or processing facilities. If that were to occur, we would be unable to realize revenue from those wells until we made production arrangements to deliver the product to market. Thus, our profitability would be adversely affected. +Our derivative activities could result in financial losses or reduced income from failure to perform by our counterparties or could limit our potential gains from increases in prices. +We use derivatives for a portion of our natural gas and crude oil production from our own wells, our partnerships and for natural gas purchases and sales by our marketing subsidiary to achieve a more predictable cash flow, to reduce exposure to adverse fluctuations in the prices of natural gas and crude oil, and to allow our natural gas marketing company to offer pricing options to natural gas sellers and purchasers. These arrangements expose us to the risk of financial loss in some circumstances, including when purchases or sales are different than expected, the counter-party to the derivative contract defaults on its contract obligations, or when there is a change in the expected differential between the underlying price in the derivative agreement and actual prices that we receive. +In addition, derivative arrangements may limit the benefit from increases in the prices for natural gas and crude oil. They may also require the use of our resources to meet cash margin requirements. Since we do not designate our derivatives as hedges, we do not currently +23 +qualify for use of hedge accounting; therefore, changes in the fair value of derivatives are recorded in our income statements, and our net income is subject to greater volatility than if our derivative instruments qualified for hedge accounting. For instance, if natural gas and crude oil prices rise significantly, it could result in significant non-cash charges each quarter, which could have a material negative effect on our net income. +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 our natural gas, NGL and crude oil sales or joint interest billings to a small number of third parties in the energy industry. This concentration of customers and joint interest owners may affect our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, our natural gas and crude oil derivatives as well as the derivatives used by our marketing subsidiary expose us to credit risk in the event of nonperformance by counterparties. Nonperformance by our customers may adversely affect our financial condition and profitability. +Our business could be negatively impacted by security threats, including cybersecurity threats, and other disruptions. +As an oil and natural gas 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 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. +Our insurance coverage may not be sufficient to cover some liabilities or losses that we may incur. +The occurrence of a significant accident or other event not fully covered by insurance or in excess of our insurance coverage could have a material adverse effect on our operations and financial condition. Insurance does not protect us against all operational risks. We do not carry business interruption insurance at levels that would provide enough funds for us to continue operating without access to other funds. We do not carry contingent business interruption insurance related to the processing plants owned by our natural gas purchasers or oil refineries owned by our crude oil purchasers. For some risks, such as drilling blow-out insurance, we may not obtain insurance if we believe the cost of available insurance is prohibitive relative to the perceived risks presented. In addition, pollution and environmental risks are generally not fully insurable. +We may not be able to keep pace with technological developments in our industry. +Our industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement those or other new technologies at substantial cost. In addition, other natural gas and crude oil companies 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. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we were unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected. +Competition in our industry is intense, which may adversely affect our ability to succeed. +Our industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce natural gas and crude oil, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive natural gas and crude oil properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than we can. In addition, these companies may have a greater ability to continue exploration activities during periods of low natural gas and crude oil market prices. Larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which can adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because many companies in our industry have greater financial and human resources, we may be at a disadvantage in bidding for exploratory prospects and producing natural gas and crude oil properties. These factors could adversely affect the success of our operations and our profitability. +Anti-oil and gas industry sentiment has increased. The current trend is to increase regulation of our operations and the industry. We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business. +Our exploration, development, production and marketing operations are regulated extensively at the federal, state and local levels. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon natural gas and crude oil wells. Under these laws and regulations, we could also be liable for personal injuries, property damage and other +24 +damages. Failure to comply with these laws and regulations may result in the suspension or termination of operations and subject us to administrative, civil and criminal penalties. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects. +In addition, our activities are subject to the regulation of conservation practices and protection of correlative rights by state governments. These regulations affect our operations, increase our costs of exploration and production and limit the quantity of natural gas and crude oil that we can produce and market. A major risk inherent in our drilling plans is the need to obtain drilling permits from state and local authorities. Delays in obtaining regulatory approvals, drilling permits, 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. Additionally, the natural gas and crude oil regulatory environment could change in ways that might substantially increase our financial and managerial costs to comply with the requirements of these laws and regulations and, consequently, adversely affect our profitability. Furthermore, these additional costs may put us at a competitive disadvantage compared to larger companies in the industry which can spread such additional costs over a greater number of wells and larger operating staff. +The BP crude oil spill in the Gulf of Mexico and anti-industry sentiment may result in new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. Although we have no operations in the Gulf of Mexico, this incident could result in regulatory initiatives in other areas as well that could limit our ability to drill wells and increase our costs of exploration and production. The EPA has recently focused on citizen concerns about the risk of water contamination and public health problems from drilling and hydraulic fracturing activities, including public meetings around the country on this issue which have been well publicized and well attended. This renewed focus could lead to additional federal and state laws and regulations affecting our drilling, fracturing and operations. Additional laws, regulations or other changes could significantly reduce our future growth, increase our costs of operations, and reduce our cash flow, in addition to undermining the demand for the natural gas and crude oil we produce. +Other potential laws and regulations affecting us include new or increased severance taxes proposed in several states, including Pennsylvania. This could adversely affect the existing operations in these states and the economic viability of future drilling. Additional laws, regulations or other changes could significantly reduce our future growth, increase our costs of operations and reduce our cash flow, in addition to undermining the demand for the natural gas and crude oil we produce. +Certain federal income tax deductions currently available with respect to natural gas and crude oil and exploration and development may be eliminated as a result of future legislation. +In February 2012, U.S. President Barack Obama ("President Obama") and his administration (the "Obama administration"), released its budget proposals for the fiscal year 2013, which included numerous proposed tax changes. The proposed budget, if enacted, would eliminate certain key U.S. federal income tax preferences currently available to natural gas and crude oil exploration and production. Similar changes have been in previous budget proposals from the Obama administration but were not adopted into law. The changes in the current budget proposal related to oil and gas drilling and production include, but are not limited to (i) the repeal of the percentage depletion allowance for natural gas and crude oil properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is not possible at this time to predict how legislation or new regulations that may be adopted to address these proposals would impact our business, but any such future laws and regulations could result in higher federal income taxes, +which could negatively affect our financial condition and results of operation. +New derivatives legislation and regulation could adversely affect our ability to hedge natural gas and crude oil prices and increase our costs and adversely affect our profitability. +In July 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”). The Dodd-Frank Act regulates derivative transactions, including our natural gas and crude oil hedging swaps (swaps are broadly defined to include most of our hedging instruments). The new law required the issuance of new regulations and administrative procedures related to derivatives within one year, but that implementation has been delayed until at least July 2012 and will initially consist of reporting and data gathering requirements, with substantive regulation to follow. The effect of such future regulations on our business is currently uncertain. In particular, note the following: +• +The Dodd-Frank Act may decrease our ability to enter into hedging transactions which would expose us to additional risks related to commodity price volatility; commodity price decreases would then have an immediate significant adverse affect on our profitability and revenues. Reduced hedging may also impair our ability to have certainty with respect to a portion of our cash flow, which could lead to decreases in capital spending and, therefore, decreases in future production and reserves. +• +If, as a result of the Dodd-Frank Act or its implementing regulations, we are required to post cash collateral in connection with our derivative positions, this would likely make it impracticable to implement our current hedging strategy. +• +We expect that the cost to hedge will increase as a result of fewer counterparties in the market and the pass-through of increased counterparty costs, thereby increasing the costs of derivative instruments. Our derivatives counterparties may be subject to significant new capital, margin and business conduct requirements imposed as a result of the Dodd-Frank Act. +• +The Dodd-Frank Act contemplates that most swaps will be required to be cleared through a registered clearing facility and traded on a designated exchange or swap execution facility. There are some exceptions to these +25 +requirements for entities that use swaps to hedge or mitigate commercial risk. While we may ultimately be eligible for such exceptions, the scope of these exceptions currently is somewhat uncertain, pending further definition through rulemaking proceedings. +• +The above factors could also affect the pricing of derivatives and make it more difficult for us to enter into hedging transactions on favorable terms. +Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the natural gas and crude oil that we produce while physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects. +In December 2009, the EPA published its findings 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. These findings allow the EPA to adopt and implement regulations that would restrict emissions of greenhouse gases under existing provisions of the CAA. In June 2010, the EPA published its final rule to address the permitting of greenhouse gas emissions from stationary sources under the Prevention of Significant Deterioration ("PSD"), and Title V permitting programs. This rule “tailors” these permitting programs to apply to certain stationary sources of greenhouse gas emissions in a multi-step process, with the largest sources first subject to permitting. It is widely expected that facilities required to obtain PSD permits for their greenhouse gas emissions will be required to also reduce those emissions according to “best available control technology,” or BACT, standards. In its permitting guidance for greenhouse gases, issued on November 10, 2010, the EPA recommended options for BACT, which include improved energy efficiency, among others. Any regulatory or permitting obligation that limits emissions of greenhouse gases could require us to incur costs to reduce emissions of greenhouse gases associated with our operations and also adversely affect demand for the natural gas and crude oil that we produce. +In addition, in October 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas sources in the U.S. on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010. On November 8, 2010, the EPA finalized rules to expand its greenhouse gas reporting rule to include onshore natural gas and crude oil production, processing, transmission, storage and distribution facilities. Reporting of greenhouse gas emissions from such facilities will be required on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011. +In June 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 on emissions of greenhouse gases in the U.S. and would require most sources of greenhouse gas emissions to obtain and hold “allowances” corresponding to their annual emissions of greenhouse gases. By steadily reducing the number of available allowances over time, ACESA would require a 17 percent reduction in greenhouse gas emissions from 2005 levels by 2020, increasing up to an 83 percent reduction of such emissions by 2050. Many 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. The passage of legislation that limits emissions of greenhouse gases from our equipment and operations could require us to incur costs to reduce the greenhouse gas emissions from our operations, and it could also adversely affect demand for the natural gas and crude oil that we produce. +Some have suggested that one consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods. If such effects were to occur, our operations could be adversely affected in various ways, including damages to our facilities from powerful winds or increased costs for insurance. +Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we produce. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate +that climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is difficult to predict how the market for our fuels could be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business. +Litigation against us pertaining to our royalty practices and payments is ongoing; our cost of defending these lawsuits, and any future similar lawsuits, could be significant and any resulting judgments against us could have a material adverse effect upon our financial condition. +In recent years, litigation has commenced against us and other companies in our industry regarding royalty practices and payments in jurisdictions where we conduct business. For more information on the suits that currently relate to us, see Note 11, Commitments and Contingencies , to our consolidated financial statements included in this report. We intend to defend ourselves vigorously in these cases. Even if the ultimate outcome of this litigation resulted in our dismissal, defense costs could be significant. These costs would be reflected in terms of dollar outlay as well as the amount of time, attention and other resources that our management would have to appropriate to the defense. Although we cannot predict an eventual outcome of this litigation, a judgment in favor of a plaintiff could have a material adverse effect on our financial condition and profitability. +Risks Associated with Our Indebtedness +Our credit facility has substantial restrictions and financial covenants and we may have difficulty obtaining additional credit, which could +26 +adversely affect our operations. Our lenders can unilaterally reduce our borrowing availability based on anticipated sustained natural gas and crude oil prices. +We depend in large part on our revolving credit facility for future capital needs. The terms of the borrowing agreement require us to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flows from operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants under the revolving credit facility or other debt financing could result in a default under those facilities, which could cause all of our existing indebtedness to be immediately due and payable. +The revolving credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion based upon projected revenues from the natural gas and crude oil properties securing their loan. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the revolving credit facility. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other natural gas and crude oil properties as additional collateral. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under the revolving credit facility. Our inability to borrow additional funds under our credit facility could adversely affect our operations and our financial results. +The indentures governing our outstanding notes and our senior credit facility impose (and we anticipate that the indentures governing any other debt securities we may issue will also impose) restrictions on us that may limit the discretion of management in operating our business. That, in turn, could impair our ability to meet our obligations. +The indentures governing our outstanding notes and our senior credit facility contain (and we anticipate that the indentures governing any other debt securities we may issue will also contain) various restrictive covenants that limit management’s discretion in operating our business. In particular, these covenants limit our ability to, among other things: +• +incur additional debt; +• +make certain investments or pay dividends or distributions on our capital stock, or purchase, redeem or retire capital stock; +• +sell assets, including capital stock of our restricted subsidiaries; +• +restrict dividends or other payments by restricted subsidiaries; +• +create liens; +• +enter into transactions with affiliates; and +• +merge or consolidate with another company. +These covenants could materially and adversely affect our ability to finance our future operations or capital needs. Furthermore, they may restrict our ability to expand, to pursue our business strategies and otherwise conduct our business. Our ability to comply with these covenants may be affected by circumstances and events beyond our control, such as prevailing economic conditions and changes in regulations, and we cannot assure you that we will be able to comply with them. A breach of any of these covenants could result in a default under the indentures governing our outstanding senior notes and any other debt securities we may issue in the future and/or our senior credit facility. If there were an event of default under our indentures and/or the senior credit facility, the affected creditors could cause all amounts borrowed under these instruments to be due and payable immediately. Additionally, if we fail to repay indebtedness under our senior credit facility when it becomes due, the lenders under the senior credit facility could proceed against the assets which we have pledged to them as security. Our assets and cash flow might not be sufficient to repay our outstanding debt in the event of a default. The occurrence of such an event would adversely affect our operations and profitability. +Our senior credit facility also requires us to maintain specified financial ratios and satisfy certain financial tests. Our ability to maintain or meet such financial ratios and tests may be affected by events beyond our control, including changes in general economic and business conditions, and we cannot assure you that we will maintain or meet such ratios and tests, or that the lenders under the senior credit facility will waive any failure to meet such ratios or tests. +In addition, upon a change in control, we are required to offer to buy each senior note for 101% of the principal amount, plus unpaid interest. A change in control is defined to include: (i) when a majority of the Board of Directors are not continuing directors; (ii) when one person (or group of related persons) holds direct or indirect ownership of over 50% of our voting stock; or (iii) upon sale, transfer or lease of substantially all of our assets. +We may incur additional indebtedness to facilitate our acquisition of additional properties, which would increase our leverage and could negatively affect our business or financial condition. +Our business strategy includes the acquisition of additional properties that we believe would have a positive effect on our current business and operations. We expect to continue to pursue acquisitions of such properties and may incur additional indebtedness to finance the acquisitions. Our incurrence of additional indebtedness would increase our leverage and our interest expense, which could have a negative effect on our business or financial condition. +If we fail to obtain additional financing, we may be unable to refinance our existing debt, expand our current operations or acquire new businesses. This could result in our failure to grow in accordance with our plans, or could result in defaults in our obligations under our senior credit facility or the indentures relating to our outstanding senior notes. +27 +In order to refinance indebtedness, expand existing operations and acquire additional businesses or properties, we will require substantial amounts of capital. There can be no assurance that financing, whether from equity or debt financings or other sources, will be available or, if available, will be on terms satisfactory to us. If we are unable to obtain such financing, we will be unable to acquire additional businesses or properties and may be unable to meet our obligations under our senior credit facility and the indentures relating to our outstanding senior notes or any other debt securities we may issue in the future. Such an event would adversely affect our operations and profitability. +Risks Associated with Our Joint Venture +PDC Mountaineer, LLC is dependent upon our equity partner (the “Investor”) and poses exit-related risks for us. +The board of managers of the joint venture consists of three representatives appointed by us and three representatives appointed by the Investor, each with equal voting power. The joint venture agreement generally requires the affirmative vote of a majority of the members of the board to approve an action, and we and the Investor may not always agree on the best course of action for the joint venture. If such a disagreement were to occur, we would not be able to cause the joint venture to take action that we believed to be in the best interests of the joint venture. Consequently, our best interests may not be advanced and our investment in the joint venture could be adversely affected. If there is a disagreement about a development plan and budget for the joint venture, the Investor is entitled to unilaterally suspend substantially all of the operations of the joint venture, which could have a material adverse impact on the results of operations of the joint venture and our investment. Such a suspension could last for up to two years, at which point either party could elect to dissolve the joint venture or to sell their ownership interests to a third party. The Investor is entitled to a preference with respect to liquidating distributions and proceeds from significant sales of ownership interests up to the amount of its contributed capital, which would diminish our returns if the value of the joint venture had declined at the time of the liquidation or sale. +After a “restricted period” which generally lasts for the four year years following the closing of the joint venture, the Investor can seek to sell its interest in the joint venture to a third party, subject to rights of first offer and refusal in favor of us. If we do not exercise those rights in a sale involving all of the Investor’s ownership interests, the Investor can exercise “drag-along” rights and compel us to sell all of our interests in the proposed transaction. Accordingly, if we possessed insufficient funds and were unable to obtain financing necessary to purchase the Investor’s interest under the rights of first offer and refusal, the Investor might sell its interests in the joint venture to a third party with whom we might have a difficult time in dealing and in managing the joint venture or we may be required to sell our interest in the joint venture at a time when we may not wish to do so. Under these circumstances, our investment in the joint venture could be adversely affected. +ITEM 1B. UNRESOLVED STAFF COMMENTS +None. +ITEM 3. LEGAL PROCEEDINGS +Information regarding our legal proceedings can be found in Note 11, Commitments and Contingencies – Litigation , to our consolidated financial statements included in this report. +ITEM 4. MINE SAFETY DISCLOSURES +None. +28 +PART II +ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDERS MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES +Our common stock, par value $0.01 per share, is traded on the NASDAQ Global Select Market under the symbol PETD. The following table sets forth the range of high and low sales prices for our common stock for each of the periods presented. +Price Range +High +Low +January 1 - March 31, 2010 +$ +25.37 +$ +18.11 +April 1 - June 30, 2010 +27.73 +17.92 +July 1 - September 30, 2010 +30.39 +23.82 +October 1 - December 31, 2010 +43.01 +27.44 +January 1 - March 31, 2011 +49.60 +39.93 +April 1 - June 30, 2011 +48.51 +28.67 +July 1 - September 30, 2011 +39.50 +19.35 +October 1 - December 31, 2011 +37.77 +15.08 +As of February 17, 2012 , we had approximately 790 shareholders of record. Since inception, no cash dividends have been declared on our common stock. Cash dividends are restricted under the terms of our credit facility and we presently intend to continue a policy of using retained earnings for expansion of our business. See Note 8, Long-term Debt , to our consolidated financial statements included in this report. +The following table presents information about our purchases of our common stock during the three months ended December 31, 2011 . +Period +Total Number +of Shares +Purchased (1) +Average Price +Paid per Share +Total Number +of Shares +Purchased as +Part of Publicly +Announced Plans +or Programs +Maximum Number +of Shares that May +Yet Be Purchased +Under the Plans +or Programs +October 1 - 31, 2011 +175 +$ +26.11 +— +— +November 1 - 30, 2011 +3,755 +27.52 +— +— +December 1 - 31, 2011 +2,607 +35.11 +— +— +Total fourth quarter purchases +6,537 +30.51 +__________ +(1) +Purchases represent shares purchased pursuant to our stock-based compensation plans for payment of tax liabilities related to the vesting of securities. +29 +SHAREHOLDER PERFORMANCE GRAPH +The performance graph below compares the cumulative total return of our common stock over the five-year period ended December 31, 2011 , with the cumulative total returns for the same period for the Standard and Poor's ("S&P") 500 Index and the Standard Industrial Code ("SIC") Index. The SIC Index is a weighted composite of 235 crude petroleum and natural gas companies. The results shown in the graph below are not necessarily indicative of future performance. The cumulative total shareholder return assumes that $100 was invested, including reinvestment of dividends, if any, in our common stock on December 31, 2006, and in the S&P 500 Index and the SIC Index on the same date. +30 +ITEM 6. SELECTED FINANCIAL DATA +Year Ended December 31, +2011 +2010 +2009 +2008 +2007 (3) +(in millions, except per share data and as noted) +Statement of Operations +Natural gas, NGL and crude oil sales +$ +276.6 +$ +205.0 +$ +171.2 +$ +304.9 +$ +175.2 +Commodity price risk management gain (loss), net (1) +46.1 +59.9 +(10.1 +) +127.8 +2.8 +Total revenues +396.0 +343.0 +230.9 +572.5 +291.7 +Income (loss) from continuing operations +3.1 +6.0 +(80.1 +) +105.8 +26.1 +Earnings (loss) per share attributable to shareholders: +Net income (loss) from continuing operations - basic +$ +0.13 +$ +0.33 +$ +(4.76 +) +$ +7.19 +$ +1.77 +Net income (loss) from continuing operations - diluted +0.13 +0.32 +(4.76 +) +7.13 +1.76 +Statement of Cash Flows +Net cash provided by operating activities +$ +166.8 +$ +151.8 +$ +143.9 +$ +139.1 +$ +60.3 +Capital expenditures +334.5 +162.7 +143.0 +323.2 +239.0 +Acquisitions +145.9 +158.1 +— +— +255.7 +Balance Sheet +Total assets +$ +1,698.0 +$ +1,389.0 +$ +1,250.3 +$ +1,402.7 +$ +1,050.5 +Working capital (deficit) +(22.0 +) +16.2 +32.9 +31.3 +(50.2 +) +Long-term debt +532.2 +295.7 +280.7 +394.9 +235.0 +Equity +664.1 +642.2 +538.6 +512.3 +396.3 +Pricing and Lifting Costs on Continuing Operations +Average sales price (excluding gains/losses on derivatives) (per Mcfe) +$ +6.15 +$ +5.63 +$ +4.19 +$ +8.37 +$ +6.26 +Average sales price (including realized gains/losses on derivatives) (per Mcfe) +6.53 +6.89 +6.77 +8.62 +6.52 +Average lifting cost (per Mcfe) (2) +0.95 +1.09 +0.81 +1.08 +0.90 +Production (Bcfe) +Production from continuing operations +45.0 +37.0 +41.6 +36.9 +28.0 +Production from discontinued operations (3) +2.5 +1.6 +1.7 +1.8 +— +Total production +47.5 +38.6 +43.3 +38.7 +28.0 +Total proved reserves (Bcfe) (4) +1,015.5 +860.6 +717.3 +753.1 +685.6 +______________ +(1) +See Note 4, Derivative Financial Instruments, to our consolidated financial statements included in this report. +(2) +Lifting costs represent lease operating expenses, excluding production taxes, on a per unit basis. +(3) +2007 does not present the effects of the divestitures of our Michigan and North Dakota assets as discontinued operations as the amounts related to these operations were immaterial. +(4) +Includes total proved reserves related to our Permian Basin assets of 65.0 Bcfe and 32.1 Bcfe as of December 31, 2011 and 2010, respectively . As of December 31, 2011, our Permian assets were held for sale and, on February 28, 2012, the divestiture closed. See Note 13, Assets Held for Sale, Divestitures and Discontinued Operations, and Note 18, Subsequent Event, to our consolidated financial statements included in this report for additional details related to the divestiture of our Permian assets. +31 +ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +The following discussion and analysis, as well as other sections in this report, should be read in conjunction with our consolidated financial statements and related notes to consolidated financial statements included in this report. Further, we encourage you to revisit the Special Note Regarding Forward-Looking Statements in Part I of this report. +EXECUTIVE SUMMARY +2011 Financial Overview +In 2011, we recorded strong increases in revenues and cash flows from operations. Increased production, liquids to natural gas ratio and crude oil prices were the largest contributors to these increases, despite lower average natural gas prices. Natural gas, NGL and crude oil sales revenue increased 34.9% in 2011 compared to 2010, with increases in production of 21.5% and an overall increase in the average sales price per Mcfe of 9.2% . Leading the increase in production were liquids, with crude oil production increasing 38.9% and NGL production increasing 26.3% , resulting in a liquids to natural gas ratio of 32/68 in 2011 compared to 29/71 in 2010. Our derivative transactions generated revenues of $48.9 million and liquidity of $17.6 million. Available liquidity as of December 31, 2011, was $196.4 million, including $16.6 million related to PDCM for the acquisition and development of Marcellus properties, compared to $379.3 million, which included $23.9 million related to PDCM, as of December 31, 2010. The decrease in available liquidity year-over-year was expected as we intended to use the excess proceeds from our November 2010 capital transactions on the acquisition of natural gas and crude oil properties, specifically our partnership acquisitions and the acceleration of organic growth projects. Available liquidity is comprised of cash, cash equivalents and funds available under our credit facility after giving consideration to our undrawn outstanding letters of credit. +Operational Overview and Update +Drilling Activities . In 2011, we drilled 97 developmental wells and participated in 48 non-operated wells in the Wattenberg Field, of which 123 were completed and turned in line. We also executed 190 refracture and/or recompletion projects in this area. Of the 145 wells drilled, 17 were horizontal Niobrara with 16 of them producing as of December 31, 2011. We drilled 17 developmental wells in the Piceance Basin and PDCM drilled six horizontal Marcellus wells, two of which had been turned in line as of the end of the year, and completed three horizontal Marcellus wells that were in-process as of December 31, 2010. In the Permian Basin, we drilled a total of 23 developmental wells, 15 of which were producing at year end and two of which were determined to be dry holes. +Acquisitions and Leasehold Agreements . In 2011, we entered into leasehold agreements with various unrelated third parties providing us with an option to acquire acreage targeting the wet natural gas and crude oil windows of the Utica Shale play throughout southeastern Ohio. Pursuant to the agreements, we have the right to acquire an estimated 40,000 net acres. Should we exercise our right to acquire all 40,000 acres, we estimate that the purchase price of such leaseholds will approximate $70 million. A portion of the options related to these leaseholds will expire in August 2012. Currently, we are pursuing an industry joint venture partner to participate in and share in funding the growth and development in this play. While we expect to identify a partner by mid-2012, we cannot assure we will be successful in securing a partner or developing this acreage. These Utica Shale acreage expenditures demonstrate our heightened interest in dedicating a portion of our capital budget to exploration, which involves higher risks and the potential for higher rewards. In previous years we have dedicated very little of our expenditures to exploration. +In October 2011, PDCM acquired from an unrelated third party 100% of the membership interests of Seneca-Upshur Petroleum, LLC ("Seneca-Upshur"), a West Virginia limited liability company, for the purchase price of $162.9 million, including a post-closing working capital adjustment of $10.4 million. The acquisition included approximately 1,340 gross wells producing from the shallow Devonian Shale and Mississippian formations and all rights and depths to an estimated 100,000 net acres in West Virginia, of which 90,000 acres are prospective for the Marcellus Shale. Pursuant to our joint venture interest in PDCM, our portion of the purchase price was $81.5 million and we hold a 50% interest in both the wells and acres acquired. We estimate that the acquisition added approximately 8 Bcfe to our total proved reserves as of December 31, 2011. Substantially all of the acreage acquired is held by production and is in close proximity to PDCM's existing properties. +During 2011, we acquired eight affiliated partnerships for an aggregate purchase price of $73 million. These purchases included the non-affiliated investor partners' remaining working interests in a total of 299 gross, 204.2 net, wells located in our Wattenberg Field and Piceance Basin. The acquisition of these partnerships has provided us with immediate growth in both production and proved reserves, and will allow us to realize operational benefits, as well as the opportunity to optimize revenue opportunities by accelerating a refracture and recompletion program of the wells acquired. +Natural Gas and Crude Oil Properties Divestitures. In October 2011, we announced our intent to divest our assets located in the Wolfberry Trend in the Permian Basin in West Texas to focus our efforts in our horizontal drilling programs and to provide partial funding for our 2012 capital budget. During the fourth quarter of 2011, we sold our non-core Permian assets to unrelated third parties for a total of $13.2 million. On December 20, 2011, we executed a purchase and sales agreement with another unrelated third party for the sale of our core Permian assets for a total price of $173.9 million, subject to customary post-closing adjustments. The transaction closed on February 28, 2012 with total proceeds received of $184.4 million after preliminary closing adjustments . The proceeds from these sales were used to pay down our corporate credit facility and to provide partial funding for our 2012 capital budget, allowing us to accelerate the development of our liquid-rich inventory of projects in the Wattenberg Field and to fund the acquisition of Utica Shale acreage in Ohio while beginning exploratory activities on this acreage. Our Permian Basin assets were classified as held for sale as of December 31, 2010 and 2011, and the results of operations related to those assets were reported as discontinued operations in 2010, year of acquisition, and 2011, in the +32 +accompanying consolidated statements of operations included in this report. +Potential for Future Asset Impairments. The domestic natural gas market remains weak. A further decrease in forward natural gas prices during 2012 could result in significant impairment charges. Our Piceance Basin has significant natural gas reserves, representing 47% of our total proved natural gas reserves and 32% of our total proved reserves, and is sensitive to declines in natural gas prices. These assets, which had a net book value of approximately $308 million at December 31, 2011, are at risk of impairment if future natural gas prices for production in this area experience further long-term decline. The cash flow model we use to assess properties for impairment includes numerous assumptions, such as management's estimates of future oil and gas production and commodity prices, market outlook on forward commodity prices and operating and development costs. All inputs to the cash flow model must be evaluated at each date that the estimate of future cash flows for each producing basin is calculated. However, a significant decrease in long-term forward natural gas prices alone could result in a significant impairment for our properties that are sensitive to declines in natural gas prices. +Non-U.S. GAAP Financial Measures +We use "adjusted cash flow from operations," "adjusted net income (loss) attributable to shareholders," "adjusted EBITDA" and "PV-10%," non-U.S. GAAP financial measures, for internal managerial purposes, when evaluating period-to-period changes and providing public guidance on possible future results. These measures are not measures of financial performance under U.S. GAAP and should be considered in addition to, not as a substitute for, cash flows from operations, investing, or financing activities, nor as a liquidity measure or indicator of cash flows reported in accordance with U.S. GAAP. The non-U.S. GAAP financial measures that we use may not be comparable to similarly titled measures reported by other companies. Also, in the future, we may disclose different non-U.S. GAAP financial measures in order to help our investors more meaningfully evaluate and compare our future results of operations to our previously reported results of operations. We strongly encourage investors to review our financial statements and publicly filed reports in their entirety and to not rely on any single financial measure. See Reconciliation of Non-U.S. GAAP Financial Measures for a detailed description of these measures as well as a reconciliation of each to the nearest U.S. GAAP measure. +33 +Results of Operations +Summary Operating Results +The following table presents selected information regarding our operating results from continuing operations. +Year Ended December 31, +Change +2011 +2010 +2009 +2011-2010 +2010-2009 +(dollars in millions, except per unit data) +Production (1) +Natural gas (MMcf) (2) +30,429.7 +26,239.1 +34,089.6 +16.0 +% +(23.0 +)% +Crude oil (MBbls) +1,709.9 +1,231.4 +1,244.0 +38.9 +% +(1.0 +)% +NGLs (MBbls) (2) +719.2 +569.6 +— +26.3 +% +* +Natural gas equivalent (MMcfe) (3) +45,004.8 +37,044.9 +41,553.4 +21.5 +% +(10.8 +)% +Average MMcfe per day +123.3 +101.5 +113.8 +21.5 +% +(10.8 +)% +Natural Gas, NGL and Crude Oil Sales +Natural gas (2) +$ +99.6 +$ +94.6 +$ +105.4 +5.3 +% +(10.2 +)% +Crude oil +149.8 +91.1 +68.5 +64.4 +% +33.0 +% +NGLs (2) +27.2 +22.6 +— +20.4 +% +* +Provision for underpayment of natural gas sales +— +(3.3 +) +(2.7 +) +(100.0 +)% +22.2 +% +Total natural gas, NGL and crude oil sales +$ +276.6 +$ +205.0 +$ +171.2 +34.9 +% +19.7 +% +Realized Gain (Loss) on Derivatives, net (4) +Natural gas +$ +29.1 +$ +40.0 +$ +89.4 +(27.3 +)% +(55.3 +)% +Crude oil +(11.9 +) +7.1 +17.9 +(267.6 +)% +(60.3 +)% +Total realized gain on derivatives, net +$ +17.2 +$ +47.1 +$ +107.3 +(63.5 +)% +(56.1 +)% +Average Sales Price (excluding gain/loss on derivatives) +Natural gas (per Mcf) (2) +$ +3.27 +$ +3.61 +$ +3.09 +(9.4 +)% +16.8 +% +Crude oil (per Bbl) +87.63 +73.96 +55.07 +18.5 +% +34.3 +% +NGLs (per Bbl) (2) +37.82 +39.66 +— +(4.6 +)% +* +Natural gas equivalent (per Mcfe) +6.15 +5.63 +4.19 +9.2 +% +34.4 +% +Average Sales Price (including realized gain/loss on derivatives) +Natural gas (per Mcf) (2) +$ +4.23 +$ +5.13 +$ +5.72 +(17.5 +)% +(10.3 +)% +Crude oil (per Bbl) +80.69 +79.70 +69.44 +1.2 +% +14.8 +% +NGLs (per Bbl) (2) +37.82 +39.66 +— +(4.6 +)% +* +Natural gas equivalent (per Mcfe) +6.53 +6.89 +6.77 +(5.2 +)% +1.8 +% +Average Lifting Cost (per Mcfe) (5) +$ +0.95 +$ +1.09 +$ +0.81 +(12.8 +)% +34.6 +% +Natural Gas Marketing Contribution Margin (6) +$ +0.9 +$ +1.1 +$ +2.0 +(18.2 +)% +(45.0 +)% +Other Costs and Expenses +Exploration expense +$ +6.3 +$ +13.7 +$ +14.1 +(54.0 +)% +(2.8 +)% +Impairment of natural gas and crude oil properties +25.2 +6.5 +5.0 +287.7 +% +30.0 +% +General and administrative expense +61.5 +42.2 +54.0 +45.7 +% +(21.9 +)% +Depreciation, depletion, and amortization +128.9 +108.1 +126.8 +19.2 +% +(14.7 +)% +Interest Expense +$ +37.0 +$ +33.2 +$ +37.2 +11.4 +% +(10.8 +)% +* +Percentage change is not meaningful or equal to or greater than 300%. +Amounts may not recalculate due to rounding. +______________ +(1) +Production is net and determined by multiplying the gross production volume of properties in which we have an interest by the percentage interest we own. For total production volume including discontinued operations, see Part I, Item 6, Selected Financial Data included in this report. +(2) +Prior to 2010, NGLs were included in natural gas, which impacts the comparability of 2011 and 2010 to 2009. +(3) +Six Mcf of natural gas equals one Bbl of crude oil or NGL. +(4) +Represents realized derivative gains and losses related to natural gas, NGLs and crude oil sales, which do not include realized derivative gains and losses +34 +related to natural gas marketing. +(5) +Represents lease operating expenses, exclusive of production taxes, on a per unit basis. +(6) +Represents sales from natural gas marketing, net of costs of natural gas marketing, including realized and unrealized derivative gains and losses related to natural gas marketing activities. +Natural Gas, NGL and Crude Oil Sales +The following tables present natural gas, NGL and crude oil production and average sales price for continuing operations. +Year Ended December 31, +Change +Production by Operating Region +2011 +2010 +2009 +2011-2010 +2010-2009 +Natural gas (MMcf) (2) +Western +26,004.0 +23,650.8 +29,957.4 +9.9 +% +(21.1 +)% +Eastern (1) +4,389.9 +2,526.0 +4,010.5 +73.8 +% +(37.0 +)% +Other +35.8 +62.3 +121.7 +(42.5 +)% +(48.8 +)% +Total +30,429.7 +26,239.1 +34,089.6 +16.0 +% +(23.0 +)% +Crude oil (MBbls) +Western +1,705.1 +1,224.9 +1,233.3 +39.2 +% +(0.7 +)% +Eastern (1) +4.8 +5.9 +9.6 +(18.6 +)% +(38.5 +)% +Other +— +0.6 +1.1 +(100.0 +)% +(45.5 +)% +Total +1,709.9 +1,231.4 +1,244.0 +38.9 +% +(1.0 +)% +NGLs (MBbls) (2) +Western +712.1 +561.1 +— +26.9 +% +* +Other +7.1 +8.5 +— +(16.5 +)% +* +Total +719.2 +569.6 +— +26.3 +% +* +Natural gas equivalent (MMcfe) +Western +40,505.3 +34,367.2 +37,357.0 +17.9 +% +(8.0 +)% +Eastern (1) +4,418.9 +2,561.4 +4,068.1 +72.5 +% +(37.0 +)% +Other +80.6 +116.3 +128.3 +(30.7 +)% +(9.4 +)% +Total +45,004.8 +37,044.9 +41,553.4 +21.5 +% +(10.8 +)% +* +Percentage change is not meaningful or equal to or greater than 300%. +Amounts may not recalculate due to rounding. +__________ +(1) +For 2010, the decrease in production was primarily the result of our contribution of natural gas and crude oil properties to PDCM. Effective January 1, 2010, PDCM was deconsolidated and accounted for in accordance with the proportionate consolidation method. See Note 1, Nature of Operations and Basis of Presentation, to our consolidated financial statements included in this report. +(2) +Prior to 2010, NGLs were included in natural gas, which impacts the comparability of 2011 and 2010 to 2009. +35 +Year Ended December 31, +Average Sales Price by Operating Region +Change +(excluding gain/loss on derivatives) +2011 +2010 +2009 +2011-2010 +2010-2009 +Natural gas (per Mcf) (1) +Western +$ +3.12 +$ +3.52 +$ +2.97 +(11.4 +)% +18.5 +% +Eastern +4.15 +4.44 +4.00 +(6.5 +)% +11.0 +% +Other +4.01 +2.49 +2.40 +61.0 +% +3.8 +% +Weighted average price +3.27 +3.61 +3.09 +(9.4 +)% +16.8 +% +Crude oil (per Bbl) +Western +87.63 +73.95 +55.06 +18.5 +% +34.3 +% +Eastern +87.09 +77.10 +57.24 +13.0 +% +34.7 +% +Other +— +62.68 +40.62 +* +54.3 +% +Weighted average price +87.63 +73.96 +55.07 +18.5 +% +34.3 +% +NGLs (per Bbl) (1) +Western +37.69 +39.56 +— +(4.7 +)% +* +Other +50.30 +46.29 +— +8.7 +% +* +Weighted average price +37.82 +39.66 +— +(4.6 +)% +* +Natural gas equivalent (per Mcfe) +Western +6.35 +5.71 +4.20 +11.2 +% +36.0 +% +Eastern +4.22 +4.55 +4.08 +(7.3 +)% +11.5 +% +Other +7.14 +4.99 +2.62 +43.1 +% +90.5 +% +Weighted average price +6.15 +5.63 +4.19 +9.2 +% +34.4 +% +* +Percentage change is not meaningful or equal to or greater than 300%. +Amounts may not recalculate due to rounding. +__________ +(1) +Prior to 2010, NGLs were included in natural gas, which impacts the comparability of 2011 and 2010 to 2009. +The year-over-year change in natural gas, NGL and crude oil sales revenue were primarily due to the following: +Year Ended December 31, +2011 +2010 +2009 +(in millions) +Increase (decrease) in production +$ +56.4 +$ +(25.0 +) +$ +37.1 +Increase (decrease) in average crude oil price +23.4 +23.3 +(43.0 +) +Increase (decrease) in average NGL price (1) +(1.3 +) +22.6 +— +Increase (decrease) in average natural gas price +(10.2 +) +13.5 +(129.1 +) +Decrease (increase) in provision for underpayment of natural gas sales +3.3 +(0.6 +) +1.3 +Total increase (decrease) in natural gas, NGL and crude oil sales revenue +$ +71.6 +$ +33.8 +$ +(133.7 +) +__________ +(1) +Prior to 2010, NGLs were included in natural gas, which impacts the comparability of 2011 and 2010 to 2009. +Natural gas, NGL and crude oil sales revenue in 2011 increased 34.9% compared to 2010. The increase was primarily due to significantly higher volumes sold, in particular liquids, which shifted our liquids to natural gas ratio to approximately 32/68 in 2011 compared to 29/71 in 2010 and a higher average sales price of crude oil. The shift in production mix favoring liquids allowed us to benefit from the higher average sales price of crude oil compared to natural gas. +Our average daily sales volumes increased to 123.3 MMcfe per day in 2011 compared to 101.5 MMcfe per day in 2010, primarily due to an increase in production in our Western Operating Region of 16.8 MMcfe per day as a result of increased drilling in the Wattenberg field, as well as a 5.1 MMcfe per day increase in production in our Eastern Operating Region associated with our Marcellus wells. The 2011 increase in production was directly attributable to our decision to increase our capital expenditures for new wells drilled in 2010 and 2011 and switching a majority of our drilling program from vertical to horizontal wells in the Niobrara formation and Marcellus Shale. For December 2011, our average production exit rate was 146 MMcfe per day compared to 109 MMcfe per day in December 2010 and 98 MMcfe per day in December 2009. +The decrease in 2010 production compared to 2009 was directly attributable to our decision to reduce our capital expenditures for new wells drilled in 2009 due to the decline in commodity prices from the second half of 2008 to 2009 and the uncertainty in the financial and commodity markets. The decrease in production was offset in part by our decision to report NGLs separately from natural gas volumes as +36 +these amounts are expected to become more significant as we concentrate our drilling and acquisition spending toward more liquid rich resources as well as to enhance comparability among our peers, which resulted in the recognition of approximately 1.8 Bcfe of additional production. +Natural Gas and Crude Oil Pricing. Our results of operations depend upon many factors, particularly the price of natural gas and crude oil and our ability to market our production effectively. Natural gas and crude oil prices are among the most volatile of all commodity prices. These price variations have a material impact on our financial results and capital expenditures. Natural gas prices vary by region and locality, depending upon the distance to markets, the availability of pipeline capacity and the supply and demand relationships in that region or locality. The combination of increased drilling activity and the lack of local markets has resulted in local market oversupply situations from time to time. Like most producers, we rely on major interstate pipeline companies to construct these pipelines to increase capacity, rendering the timing and availability of these facilities beyond our control. Crude oil pricing is predominately driven by the physical market, supply and demand, the financial markets and national and international politics. +The price we receive for our natural gas produced in our Western Operating Region is based on a market basket of prices, which generally includes natural gas sold at, near or below CIG prices as well as other nearby region prices. The CIG Index, and other indices for production delivered to other western area pipelines, has historically been less than the price received for natural gas produced in the eastern regions, which is NYMEX-based. This negative differential has narrowed over the last few years and is lower than historical variances. The negative differential between NYMEX and CIG averaged $0.25, $0.47 and $0.92 in 2011, 2010 and 2009, respectively. +Production Costs. Production costs include our lease operating expenses, production taxes, the cost to operate wells and pipelines and certain production and engineering staff related overhead costs. +Year Ended December 31, +2011 +2010 +2009 +(in millions) +Lease operating expenses +$ +43.0 +$ +40.2 +$ +33.8 +Production taxes +17.5 +11.7 +8.8 +Costs of well operations and pipeline services +6.1 +7.4 +6.8 +Overhead and other production expenses +2.5 +5.6 +12.7 +Total production costs +$ +69.1 +$ +64.9 +$ +62.1 +Total production costs per Mcfe +$ +1.54 +$ +1.75 +$ +1.49 +Lease operating expenses. The increase in lease operating expenses in 2011 compared to 2010 was primarily related to the 21.5% increase in production offset in part by a decrease in saltwater disposal and water hauling expenses of $1.9 million following the completion of our saltwater disposal facility in the Piceance Basin. Lifting costs per Mcfe were $0.95 , $1.09 and $0.81 for 2011, 2010 and 2009, respectively. The 12.8% decrease in lifting costs per Mcfe in 2011 from 2010 was primarily due to increases in production, which resulted in the non-production based portion of our lease operating expenses being spread across an increased number of units. Our non-production based expenses, like well workovers, environmental and other fixed expenses, were relatively consistent in 2011, even with the increase in production. The 34.6% increase per Mcfe in 2010 from 2009 was in part due to the 10.8% decrease in production volumes compared to volumes produced in 2009, resulting in the non-production based portion of our production costs being allocated to a decreased number of units. Additionally, a large component of the increase in our 2010 lease operating expenses, as well as the per Mcfe cost, were well workovers, which include an increase in tubing and casing repairs of $4.7 million and environmental remediation charges of $2.7 million. +Production taxes. Production taxes fluctuate with natural gas, NGL and crude oil sales. The $5.8 million or 49.6% increase in production taxes for 2011 compared to 2010 was primarily related to the 34.9% increase in natural gas, NGL and crude oil sales and to a lesser extent higher ad valorem rates in certain Colorado counties. The $2.9 million or 33% increase in production taxes for 2010 compared to 2009 was primarily related to the 19.7% increase in sales revenues and an increase in ad valorem tax rates for certain Colorado counties. +Costs of well operations and pipeline services. The decrease in costs of well operations and pipeline services in 2011 compared to 2010 was the result of our acquisition of 12 affiliated partnerships, resulting in lower costs incurred for the wells and pipeline systems we operate on behalf of our affiliated partnerships and other third parties. The increases in these costs in 2010 compared to 2009 was the result of costs related to pipeline systems and compressor maintenance projects, offset in part by lower field services costs. +Overhead and other production expenses. Overhead and other production expenses decreased $3.1 million in 2011 compared to 2010. The decrease was primarily due to a July 2011 amendment to a firm transportation agreement and the corresponding reversal of a $3.1 million accrued liability related to an expected volume shortfall. The decrease in 2010 compared to 2009 was primarily due to the deconsolidation of PDCM with the remaining decrease resulting from reductions in various other expenses, including a $2.7 million accrual recognized in 2009 for an expected firm transportation volume shortfall in our Piceance Basin. +37 +Commodity Price Risk Management, Net +Commodity price risk management, net, includes realized gains and losses and unrealized changes in the fair value of derivative instruments related to our natural gas and crude oil production. Commodity price risk management, net, does not include derivative transactions related to our natural gas marketing, which are included in sales from and cost of natural gas marketing. See Note 3, Fair Value of Financial Instruments , and Note 4, Derivative Financial Instruments , to our consolidated financial statements included in this report for additional details of our derivative financial instruments. +The following table presents the realized and unrealized derivative gains and losses included in commodity price risk management, net. +Year Ended December 31, +2011 +2010 +2009 +(in millions) +Commodity price risk management gain (loss), net: +Realized gains (losses): +Natural gas +$ +29.1 +$ +40.0 +$ +89.4 +Crude oil +(11.9 +) +7.1 +17.9 +Total realized gains, net +17.2 +47.1 +107.3 +Unrealized gains (losses): +Reclassification of realized gains included in prior periods unrealized +(10.3 +) +(20.1 +) +(84.7 +) +Unrealized gains (losses) for the period +39.2 +32.9 +(32.7 +) +Total unrealized gains (losses), net +28.9 +12.8 +(117.4 +) +Total commodity price risk management gain (loss), net +$ +46.1 +$ +59.9 +$ +(10.1 +) +Realized gains recognized in 2011 are primarily the result of lower natural gas prices at settlement compared to the respective strike price of our natural gas derivative positions. Realized gains on natural gas, exclusive of basis swaps, were $44.0 million reflective of a weighted average strike price of $6.25 compared to a weighted average settlement price of $4.19. These gains were offset in part by realized losses of $14.9 million on our basis swap positions as the negative basis differential between NYMEX and CIG was a weighted average of $0.25 compared to a weighted average strike price of $1.83. The realized gains on natural gas derivative positions in 2011 were offset in part by realized losses on our crude oil positions as a result of higher prices at settlement compared to the respective strike price of our derivative positions. For 2011, the realized losses were reflective of a weighted average strike price of $80.80 compared to a weighted average settlement price of $94.68. +Unrealized gains in 2011 were primarily related to the downward shift in the natural gas forward curve and its impact on the fair value of our open positions, offset in part by the upward shift in the crude oil forward curve and the narrowing of the CIG basis forward curve. During 2011, unrealized gains on our natural gas positions were $46.1 million, offset slightly by unrealized losses on our crude oil positions and CIG basis swaps of $3.9 million and $3 million, respectively. +Realized gains recognized in 2010 were the result of lower natural gas and crude oil prices at settlement compared to the respective strike price, offset in part by a $12.1 million realized loss due to the negative basis differential between NYMEX and CIG being narrower than the strike price of our derivative position. During 2010, we recorded unrealized gains of $47.3 million on our natural gas positions offset in part by unrealized losses of $10.6 million on our crude oil positions and $3.8 million on our CIG basis swaps as the forward basis differential between NYMEX and CIG had continued to narrow. +During 2009, realized gains recognized were the result of lower natural gas and crude oil prices at settlement compared to the respective strike price. We recorded unrealized losses on our CIG basis swaps of $33.9 million as the forward basis differential between NYMEX and CIG had continued to narrow along with unrealized losses of $15 million on our crude oil positions, offset by unrealized gains of $16.2 million on our natural gas positions. +We use various derivative instruments to manage fluctuations in natural gas and crude oil prices. We have in place a variety of floors, collars, fixed-price swaps and basis swaps on a portion of our estimated natural gas and crude oil production. Because we sell all of our physical natural gas and crude oil at prices similar to the indexes inherent in our derivative instruments, adjusted for certain fees and surcharges stipulated in the applicable sales agreements, we ultimately realize a price related to our collars of no less than the floor and no more than the ceiling and, for our commodity swaps, we ultimately realize the fixed price related to our swaps. See Note 4, Derivative Financial Instruments , to our consolidated financial statements included in this report and Item 7A, Quantitative and Qualitative Disclosures About Market Risk , for a discussion of how each derivative type impacts our cash flows and a detailed presentation of our derivative positions as of December 31, 2011. +38 +Natural Gas Marketing +Fluctuations in our natural gas marketing's income contribution are primarily due to fluctuations in commodity prices and realized and unrealized, mark-to-market adjustments, gains and losses on open derivative positions, and, to a lesser extent, volumes sold and purchased. +The following table presents the components of sales from and costs of natural gas marketing. +Year Ended December 31, +2011 +2010 +2009 +(in millions) +Natural gas sales revenue +$ +63.6 +$ +63.3 +$ +54.6 +Realized derivative gains, net +3.0 +6.4 +8.5 +Unrealized derivative losses, net +(0.2 +) +(0.6 +) +(3.5 +) +Total sales from natural gas marketing +66.4 +69.1 +59.6 +Costs of natural gas purchases +61.6 +61.4 +52.0 +Realized derivative losses, net +2.6 +5.9 +8.8 +Unrealized derivative losses (gains), net +0.1 +(0.5 +) +(4.3 +) +Other +1.2 +1.2 +1.1 +Total costs of natural gas marketing +65.5 +68.0 +57.6 +Natural gas marketing contribution margin +$ +0.9 +$ +1.1 +$ +2.0 +Derivative instruments related to natural gas marketing include both physical and cash-settled derivatives. We offer fixed-price derivative contracts for the purchase or sale of physical natural gas and enter into cash-settled derivative positions with counterparties in order to offset those same physical positions. See Note 4, Derivative Financial Instruments , to our consolidated financial statements included in this report and Item 7A, Quantitative and Qualitative Disclosures About Market Risk , for a discussion of how each derivative type impacts our cash flows and detailed presentation of our derivative positions as of December 31, 2011. +Other Costs and Expenses +Exploration Expense +The following table presents the major components of exploration expense. +Year Ended December 31, +2011 +2010 +2009 +(in millions) +Exploratory dry hole costs +$ +0.2 +$ +4.2 +$ +1.1 +Geological and geophysical costs +1.8 +2.3 +1.8 +Operating, personnel and other +4.3 +7.2 +11.2 +Total exploration expense +$ +6.3 +$ +13.7 +$ +14.1 +Exploratory dry hole costs . In 2010, exploratory dry hole costs included the fracturing and testing of several exploratory zones on a well drilled in the Piceance Basin and a crude oil well drilled in the NECO area. +Operating, personnel and other . The decrease in operating, personnel and other in 2011 compared to 2010 was primarily related to a $3.9 million reduction in personnel costs resulting from the reassignment of former exploration department personnel during the first quarter of 2011 to development drilling or administrative activities, offset in part by a $1.1 million increase in PDCM's lease prospecting costs. In 2009, operating, personnel and other included $3.7 million for demobilization of our drilling operations in the Piceance Basin. +39 +Impairment of Natural Gas and Crude Oil Properties +The following table sets forth the major components of our impairments of natural gas and crude oil properties expense. +Year Ended December 31, +2011 +2010 +2009 +(in millions) +Impairment of proved properties +$ +22.5 +$ +— +$ +0.9 +Impairment of individually significant unproved properties +1.6 +1.5 +1.0 +Amortization of individually insignificant unproved properties +1.1 +5.0 +3.1 +Total impairment of natural gas and crude oil properties +$ +25.2 +$ +6.5 +$ +5.0 +Impairment of proved properties. In 2011, we recognized an impairment loss of $22.5 million related to our NECO assets. During the fourth quarter of 2011, the assets were classified as held for sale, resulting in an impairment charge to reduce the carrying value of the assets to estimated fair value. See Note 2, Summary of Significant Accounting Policies - Properties and Equipment, Proved Property Impairment, to our consolidated financial statements included in this report . +Amortization of individually insignificant unproved properties . The increase in amortization of individually insignificant unproved properties in 2010 was primarily due to our lack of drilling in the NECO area and the Pennsylvania portion of our Eastern Operating Region. +General and Administrative Expense +General and administrative expense for 2011 increased by $19.3 million or 45.7% compared to 2010. The increase was primarily due to an increase in payroll and payroll-related expense of $13.8 million, of which $7.1 million was related to a separation agreement with a former chief executive officer and other associated transition expenses. The increase in payroll and payroll-related expenses was also impacted by the reassignment of former exploration department personnel contributing $3.7 million to the increase, with the remaining increase in payroll and payroll-related expenses being attributable to new hires and an overall increase in employee benefits. Also contributing to the increase was a $1.6 million charge related to the settlement reached with regard to our West Virgina royalty lawsuit. +General and administrative expense decreased $11.8 million in 2010 compared to 2009. The decrease was primarily related to charges recorded during the prior year period: $7.9 million related to the formation of PDCM, $2.9 million related to a separation agreement with a former executive vice president, $1.5 million related to the expensing of previously capitalized 2008 acquisition costs pursuant to the adoption of a new accounting standard and $1.3 million related to corporate relocation costs. The 2010 decrease was offset in part by an increase in payroll and payroll related expenses during 2010. +Depreciation, Depletion and Amortization +Natural gas and crude oil properties. DD&A expense related to natural gas and crude oil properties is directly related to proved reserves and production volumes. +The following table presents our DD&A rates for natural gas and crude oil properties. +Year Ended December 31, +Operating Region/Area +2011 +2010 +2009 +(per Mcfe) +Western +Wattenberg Field (1) +$ +3.21 +$ +3.08 +$ +3.81 +Piceance Basin +2.53 +2.49 +2.35 +Weighted average Western +2.80 +2.72 +2.92 +Eastern +2.00 +2.57 +2.06 +Total weighted average +2.72 +2.71 +2.85 +__________ +(1) +Although the Wattenberg Field development costs and DD&A rates are higher than the other fields, the relative value of its liquids production currently more than offsets this cost difference. +Non-natural gas and crude oil properties. Depreciation expense for non-natural gas and crude oil properties was $6.7 million for 2011 compared to $7.5 million for 2010 and $8.1 million for 2009. +40 +Interest Expense +The increase in interest expense in 2011 compared to 2010 was attributable to $6 million of interest and amortization of the debt discount related to our convertible notes issued in November 2010. The increase was offset in part by a decrease in debt issuance costs of $1.5 million and an increase in interest capitalized of $1.4 million. The decrease in interest expense in 2010 compared to 2009 was primarily related to the lower average outstanding balances on our credit facilities. The average long-term debt in 2010 was $286.1 million compared to $392 million in 2009. Interest expense is net of capitalized interest. Interest costs capitalized in 2011, 2010 and 2009 were $1.7 million, $0.3 million and $0.8 million, respectively. We have historically utilized our daily cash balances to reduce our line of credit borrowings, thereby lowering our interest costs and interest income. +Provision/Benefit for Income Taxes +The effective tax rate ("rate") on income from continuing operations in 2011 was a 6.3% benefit on income, which reflects the benefit for the percentage depletion deduction and a $0.6 million tax benefit related to a reduction of the accrual for uncertain tax positions, offset by the adjustment to the estimated state deferred rate. Likewise, the 2010 rate of 9.7% was also favorably impacted by our deduction for percentage depletion as well as a $1.7 million discrete tax benefit related to our state deferred rate change. The 2009 rate of 36% was a benefit on loss, which was increased by a benefit for current state losses and offset by nondeductible expenditures related to the formation of PDCM. Excluding the effect of discrete items, our 2011, 2010 and 2009 rates were 0.1%, 32.9% and 36.2%, respectively, with 2011 representing a benefit on income, 2010 representing a provision on income and 2009 representing a benefit on loss. See Note 7, Income Taxes , to our consolidated financial statements included in this report for our rate reconciliation for each of the three years in the three-year period ended December 31, 2011. +Beginning with our 2010 tax year, we were accepted into and have agreed to participate in the IRS Compliance Assurance Process ("CAP") program. As part of this program, we agreed to an accelerated timeline for the IRS examination of our 2007, 2008 and 2009 tax years. This examination was completed during the second quarter of 2011, without any significant increase or decrease in tax expense. See Note 7, Income Taxes , to the accompanying consolidated financial statements included in this report for a discussion on the reduction of our uncertain tax liability due to the conclusion of this examination. Our 2010 CAP reviewed return was filed in September 2011. The IRS subsequently accepted our return without change. We have accepted an offer for continued participation in the IRS CAP program for our 2011 and 2012 tax years. +Discontinued Operations +Permian Basin. During the fourth quarter of 2011, we closed on the sale of our non-core Permian Basin assets to unrelated third parties for a sales price of $13.2 million. We then developed a plan to divest 100% of our core Permian Basin assets, consisting of producing wells and undeveloped leaseholds. Following the sale of our core Permian assets to the unrelated party, which closed on February 28, 2012, we do not have significant continuing involvement in the operations of or cash flows from these assets; accordingly, the Permian Basin assets have been reclassified as held for sale as of December 31, 2010 and 2011, and the results of operations related to the core and non-core Permian Basin assets have been reported as discontinued operations in 2010, year of acquisition, and 2011 in the accompanying consolidated statements of operations included in this report. Proceeds from the sale of our core Permian Basin assets were $184.4 million, including preliminary adjustments, which were received in the first quarter of 2012. See Note 13, Assets Held for Sale, Divestitures and Discontinued Operations , and Note 18, Subsequent Events, to our consolidated financial statements included in this report for further discussion of the Permian divestiture. +North Dakota. During the fourth quarter of 2010, we developed a plan to divest our North Dakota assets. The plan included 100% of our North Dakota assets, consisting of producing wells, undeveloped leaseholds and related facilities primarily located in Burke County. In December 2010, we effected a letter of intent with an unrelated third party. Following the sale to the unrelated party, we do not have significant continuing involvement in the operations of or cash flows from these assets; accordingly, the North Dakota assets were reclassified as held for sale as of December 31, 2010, and the results of operations related to those assets have been reported as discontinued operations in the accompanying financial statements included in this report for all periods presented. In February 2011, we closed with the same unrelated party. Proceeds from the sale were $9.5 million, net of non-affiliated investor partners' share of $3.8 million, resulting in a pretax gain on sale of $3.9 million. +Michigan. In July 2010, we completed the sale of our Michigan assets. Following the sale to the unrelated party, we do not have significant continuing involvement in the operations of or cash flows from these assets; accordingly, the results of operations related to the Michigan assets have been reported as discontinued operations in the accompanying financial statements included in this report for the year ended 2010 and 2009. Operating results related to these assets were immaterial to the financial statements with the following exception. In June 2010, in conjunction with our decision to divest our Michigan assets, we recorded a related pretax impairment charge of $4.7 million. See Note 2, Summary of Significant Accounting Polices, Properties and Equipment - Proved Property Impairment , and Note 13, Assets Held for Sale, Divestitures and Discontinued Operations , to our consolidated financial statements included in this report for additional information regarding the divestiture of our Michigan assets. +Natural Gas and Crude Oil Well Drilling Operations. We offered our last partnership drilling program in 2007. As of June 2009, we had concluded all previous commitments related to partnership well drilling and completion activities and reported our natural gas and crude oil well drilling activities as discontinued operations. +41 +For production data and operating results related to our discontinued operations, see Part I, Item 6, Selected Financial Data , of this report and Note 13, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included in this report. +Net Income (Loss) Attributable to Shareholders/Adjusted Net Income (Loss) Attributable to Shareholders +The year-over-year changes in net income (loss) attributable to shareholders are discussed above. These same reasons for change similarly impacted adjusted net income (loss) attributable to shareholders, a non-U.S. GAAP financial measure, with the exception of the unrealized derivative gains and losses on derivatives, adjusted for taxes. Adjusted net income (loss) attributable to shareholders excludes the impact of a tax adjusted unrealized derivative gain, net of $17.7 million in 2011 and $7.8 million in 2010, and a tax adjusted unrealized loss of $71.9 million in 2009. Adjusted net loss attributable to shareholders, a non-U.S. GAAP financial measure, in 2011 was $4.3 million compared to an adjusted net income of $0.4 million in 2010 and an adjusted net loss of $5.8 million in 2009. See Reconciliation of Non-U.S. GAAP Financial Measures , below, for a more detailed discussion of this non-U.S. GAAP financial measure. +Financial Condition, Liquidity and Capital Resources +Our primary sources of liquidity have been cash flows provided by operating activities and our bank credit facility and, as market conditions have permitted, we have utilized the debt and equity markets and engaged in asset monetization transactions as sources of financing. +Our primary source of cash flows provided by operations is the sale of natural gas, NGLs and crude oil. Fluctuations in our operating cash flow are substantially driven by commodity prices and changes in our production volumes. Commodity prices have historically been volatile and we manage this volatility through our use of derivatives, which has also historically been a source of cash. We enter into commodity derivative instruments with maturities of no greater than five years from the date of the instrument. For instruments that mature in two years or less, our debt covenants limit our holdings to 80% of our expected future production on total proved reserves ( PDPs , PDNPs and PUDs ). For instruments that mature greater than two years but no more than our designated maximum maturity, our debt covenants limit our holdings to 80% of our expected future production on PDPs. Therefore, we may still have significant fluctuations in our cash flows provided by operating activities due to the remaining non-hedged portion of our future production. +Our working capital fluctuates for various reasons, including, but not limited to, changes in the fair value of our commodity derivative instruments and changes in our cash and cash equivalents due to our practice of utilizing excess cash to reduce the outstanding borrowings under our corporate credit facility. At December 31, 2011, we had a working capital deficit of $22.0 million compared to a surplus of $16.2 million at December 31, 2010. Our surplus in 2010 was directly related to our November 2010 debt and equity offerings. +We began 2012 with cash and cash equivalents of $8.2 million , including $0.7 million related to PDCM for the acquisition and development of Marcellus property, and availability under credit facilities of $188.2 million, including $15.9 million related to PDCM, for a total liquidity position of $196.4 million compared to $379.3 million at the beginning of 2011. The decrease in liquidity of $182.9 million, or 48.2%, was expected as we utilized the proceeds from our November 2010 capital raise to fund our 2011 operating budget, $334.5 million in capital expenditures and $145.9 million in the acquisition of natural gas and crude oil properties. These uses of cash were offset in part by sources of cash provided by operating activities of $166.8 million , an increase in the borrowing base of our corporate credit facilities of $96.4 million, including $17.7 million related to PDCM, and $23.1 million from the divestiture of our non-core Permian and North Dakota assets during 2011. +We closed on the sale of our core Permian assets on February 28, 2012. The proceeds from the sale will serve as a source of liquidity in 2012. We also seek to monetize a portion of our Utica Shale assets as we are currently seeking a joint venture partner to participate in and share in funding the growth and development of this play. While we expect to identify a partner by mid-2012, we cannot assure we will be successful in securing a partner or developing this acreage. With our current liquidity position, including the proceeds from the sale of our Permian assets, and expected cash flow from operations, we believe that we have sufficient capital for operations and our planned uses of capital through 2012. +Capital Expenditures +We establish a capital budget each calendar year based on our development opportunities, liquidity position and the expected cash flows provided by operating activities for that year. We may revise our capital budget during the year as a result of acquisitions, drilling results, commodity prices, changes in our borrowing capacity and/or significant changes in cash flows. In December 2011, our Board of Directors approved our 2012 capital budget of $284 million, excluding our share of PDCM's capital budget. Based on our current forecast, we expect to allocate $184 million for developmental drilling, including recompletions and refractures, of which approximately 97% is expected to be invested in the Wattenberg field. We expect to allocate the remaining $100 million to acquisitions of properties and leased acreage, exploration and other capital needs. PDCM's capital budget for 2012 includes funding for the drilling of four gross horizontal wells and the completion of seven. PDCM's 2012 capital budget is currently set at $60 million, of which $30 million represents our share, and is expected to be funded by PDCM's operating activities and its credit facility. We believe, based on the current commodity price environment and our estimated 2012 production of approximately 53 Bcfe, an increase of approximately 17.8% over 2011 production from continuing operations, our cash flows provided by operating activities and the sale of our Permian assets will fund our 2012 capital budget while improving our 2012 liquidity position. Because natural gas and crude oil produced from our existing properties decline rapidly in the first few years of production, in order to grow our production, we need to continue to commit significant amounts of capital in 2012 and beyond. If capital is +42 +not available or is constrained in the future, we will be limited to our cash flows from operations and liquidity under our credit facility as the sources for funding our capital expenditures. We would not be able to maintain our current level of natural gas and crude oil production and cash flows provided by operating activities if capital markets and commodity prices were to become depressed and/or the borrowing base on our credit facility was reduced. The recurrence of such an event may result in our election to defer a substantial portion of our planned capital expenditures for 2012 and beyond and could have a material negative impact on our operations in the future. +Financing Activities +See Note 8, Long-Term Debt , and Note 12, Common Stock , to our consolidated financial statements included in this report for detailed discussions of our November 2010 issuance of convertible senior notes and sale of equity, respectively. We have experienced no impediments in our ability to access borrowings under our corporate credit facility or the capital markets, as demonstrated by our November 2010 capital market transactions, but we cannot assure this will continue to be the case in the future. We continue to monitor market events and circumstances and their potential impacts on each of the lenders that comprise our bank credit facility. Our $400 million bank credit facility borrowing base is subject to size redeterminations each May and November based upon a quantification of our proved reserves at each December 31st and June 30th, respectively. A commodity price deck reflective of the current and future commodity pricing environment is utilized by our lenders to quantify our reserve reports and determine the underlying borrowing base. Our next scheduled redetermination is in May 2012. While we have continued to add producing reserves through our drilling operations since our last redetermination, we believe a significant decrease in commodity prices could have a negative impact on our future borrowing base redeterminations. +On January 23, 2012, we filed with the SEC an automatic shelf registration statement on Form S-3. Effective upon filing, the shelf provides for the potential sale an unspecified amount of debt securities, common stock or preferred stock, either separately or represented by depository shares, warrants and purchase contracts, as well as units that may include any of these securities or securities of other entities. The shelf registration statement is intended to allow us to be proactive in our ability to raise capital should the need arise, and to have the flexibility to raise such funds in one or more offerings should we perceive the market conditions to be favorable. As of December 31, 2011, we had $315.8 million available on our former shelf, which was replaced with our January 23, 2012, shelf. +We are subject to quarterly financial debt covenants on our bank credit facility. Currently, our key credit facility debt covenants require that we maintain: 1) total debt of less than 4.25 times earnings before interest, taxes, DD&A expense and capital expenditures ("EBITDAX") and 2) an adjusted working capital ratio of at least 1.0 to 1.0. Our adjusted working capital ratio is calculated by reducing our current assets and liabilities by any impact of recording the fair value of our natural gas and crude oil derivative instruments and adding our available borrowings on our bank credit facility to our current assets. The impact of any current portion of our debt is eliminated from the current liabilities, therefore any change in our available borrowings under our credit facility impacts our working capital ratio. We were in compliance with all debt covenants at December 31, 2011 , and expect to remain in compliance throughout the next year. +The indenture governing our senior notes contains customary representations and warranties as well as typical restrictive covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: (a) incur additional debt, (b) make certain investments or pay dividends or distributions on our capital stock or purchase or redeem or retire capital stock, (c) sell assets, including capital stock of our restricted subsidiaries, (d) pay dividends or other payments by restricted subsidiaries, (e) create liens that secure debt, (f) enter into transactions with affiliates and (g) merge or consolidate with another company. Additionally, with regard to our 12% senior notes, we are subject to two incurrence covenants: 1) EBITDAX of at least two times interest expense and 2) total debt of less than 4.0 times EBITDAX. We were in compliance with all covenants at December 31, 2011, and expect to remain in compliance throughout the next year. +See Part II, Item 7A, Quantitative and Qualitative Disclosures about Market Risk , for our discussion of credit risk. +Cash Flows +Operating Activities. Our net cash flow provided by operating activities is primarily impacted by commodity prices, production volumes, realized gains and losses from our derivative positions, operating costs and general and administrative expenses. Cash flows provided by operating activities increased in 2011 and 2010 compared to the respective prior year. In 2011, the increase was primarily due to the increase in natural gas, NGL and crude oil sales of $88 million, offset by the decrease in realized derivative gains related to natural gas and crude oil sales of $29.9 million, the increase in production costs of $8.5 million and the increase in general and administrative expense of $19.3 million. In 2010, the increase was primarily due to the increase in natural gas, NGL and crude oil sales of $37.1 million and the income tax refund of $25.9 million from our 2009 NOL carry-back received during the first half of 2010, offset by a decrease in realized derivative gains related to natural gas and crude oil sales of $60.2 million. The remaining changes in cash flows provided by operating activities were primarily due to changes in our assets and liabilities related to the timing of cash payments and receipts. The key components for the changes in our cash flows provided by operating activities are described in more detail in our Results of Operations above. +Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased in 2011 and decreased in 2010 compared to the respective prior year. These changes were primarily due to the same factors mentioned above for changes in cash flows provided by operating activities without regard to timing of cash payments and receipts of our assets and liabilities. Adjusted EBITDA, a non-U.S. GAAP financial measure, increased by $38.9 million in 2011 from 2010 due to a $7.2 million increase in net income attributable to shareholders; a $38.2 million combined increase in the impairment of natural gas and crude oil properties and depreciation, depletion and amortization; a $3.7 million increase in interest expense, net; and a $5.8 million increase in tax expense; offset in part by a $16.0 million increase in unrealized gains on derivatives, net. +43 +Adjusted EBITDA decreased by $18.5 million in 2010 from 2009 due to a $129.2 million increase in unrealized gains on derivatives, net; a $17.0 million combined decrease in the impairment of natural gas and crude oil properties and depreciation, depletion and amortization; a $3.8 million decrease in interest expense, net; offset in part by a $85.5 million increase in net income attributable to shareholders; and a $46.0 million increase in tax expense. +See Reconciliation of Non-U.S. GAAP Financial Measures , below, for a more detailed discussion of non-U.S. GAAP financial measures. +Investing Activities. Cash flows used in investing activities primarily consist of the acquisition, exploration and development of natural gas and crude oil properties net of dispositions of natural gas and crude oil properties. Our capital investment in natural gas and crude oil properties has increased significantly year-over-year as a result of our commitment to growth. In 2009, based on unstable economic conditions existing early in the year and uncertainty as to when commodity and financial markets would recover to a perceived normal level, we reduced our planned 2009 capital expenditures to approximately 33% of our 2008 level and began focusing our investment in the liquids-rich section of our Wattenberg Field. In 2010, as the economic condition showed signs of recovery and the differential between natural gas and liquids grew, we increased our capital spending by $177.7 million, including acquisitions, over that in 2009. Approximately 51% of our investment spending was directed toward organic development in our liquid-rich plays and the remaining 49% going toward the acquisition of natural gas and crude oil properties. In 2010, we sold our Michigan assets, which provided cash of $22 million. In 2011, we increased our capital spending by $159.6 million, including acquisitions, over that in 2010, and sold our North Dakota assets and our non-core Permian Basin assets, receiving cash of $23.1 million. Approximately 70% of our investment spending was directed toward organic development and the remaining 30% going toward the acquisition of natural gas and crude oil properties. See Part I, Operations - Drilling Activities , for additional details on our drilling activities. +Financing Activities. Net cash provided by financing activities increased significantly in 2011, primarily comprised of net borrowings under our bank credit facility of $233.5 million in order to execute our capital budget. Additionally, financing cash flows include $12.5 million, representing our proportionate share of capital contributed to PDCM by our investing partner. Cash flows provided by financing activities in 2010 included gross proceeds of $132.5 million and $115 million from our November 2010 sale of equity and issuance of convertible debt, respectively. During 2010, our investing partner in PDCM contributed $35 million, of which our proportionate share was $20.1 million. This capital raise was offset in part by the net repayment of borrowings under our bank credit facility of $80 million. Cash flows used in financing activities in 2009 were primarily related to our efforts to manage our balance sheet during the unstable economic conditions existing in 2009 and the uncertainty as to when the commodity and financial markets would recover to a perceived normal level. As a result, our net borrowings of $159.6 million in 2008 shifted to a net repayment of borrowings of $114.5 million in 2009. In 2009, we raised $48.5 million in capital through an equity offering and sold approximately half of our Eastern Operating Region assets, receiving $45 million as return of capital at the closing of the formation of PDCM. See Note 8, Long-Term Debt , Note 12, Common Stock , and Note 15, Noncontrolling Interest in Subsidiary , to our consolidated financial statements included in this report for further discussion on our debt and equity offerings and the formation of our joint venture. +44 +Contractual Obligations and Contingent Commitments +The table below presents our contractual obligations and contingent commitments as of December 31, 2011 . +Payments due by period +Less than +1-3 +3-5 +More than +Contractual Obligations and Contingent Commitments +Total +1 year +years +years +5 years +(in millions) +Long-term liabilities reflected on the consolidated balance sheets (1) +Long-term debt (2) +$ +551.0 +$ +— +$ +24.0 +$ +324.0 +$ +203.0 +Derivative contracts (3) +40.9 +19.8 +21.1 +— +— +Derivative contracts - affiliated partnerships (4) +6.1 +— +6.1 +— +— +Production tax liability +38.4 +19.0 +19.4 +— +— +Asset retirement obligations +46.6 +0.3 +0.4 +0.8 +45.1 +Other liabilities (5) +6.2 +0.3 +0.6 +0.6 +4.7 +689.2 +39.4 +71.6 +325.4 +252.8 +Commitments, contingencies and other arrangements (6) +Interest on long-term debt (7) +195.0 +36.3 +71.5 +59.8 +27.4 +Operating leases +10.8 +2.6 +4.8 +2.3 +1.1 +Drilling rig commitments (8) +16.5 +9.6 +6.9 +— +— +Drilling commitment +0.9 +— +— +— +0.9 +Firm transportation and processing agreements (9) +223.2 +15.3 +54.4 +50.2 +103.3 +Other +0.5 +0.1 +0.3 +0.1 +— +446.9 +63.9 +137.9 +112.4 +132.7 +Total +$ +1,136.1 +$ +103.3 +$ +209.5 +$ +437.8 +$ +385.5 +__________ +(1) +Table does not include deferred income tax liability to taxing authorities of $207.6 million , due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations. +(2) +Amount presented does not agree with the balance sheet in that it excludes $18.8 million in unamortized debt discount. See Note 8, Long-Term Debt, to our consolidated financial statements included in this report. +(3) +Represents our gross liability related to the fair value of derivative positions, including the fair value of derivative contracts we entered into on behalf of our affiliated partnerships as the managing general partner. We have a related receivable from the partnerships of $6.2 million . +(4) +Represents our affiliated partnerships' designated portion of the fair value of our gross derivative assets. +(5) +Includes funds held from revenue distribution to third party investors, including our affiliated partnerships, for plugging liabilities related to wells we operate and deferred officer compensation. +(6) +Table does not include an undrawn $18.7 million irrevocable standby letter of credit pending issuance to a transportation service provider. See Note 8, Long-Term Debt, to our consolidated financial statements included in this report. Additionally, the table does not include the annual repurchase obligations to investing partners or termination benefits related to employment agreements with our executive officers, due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations. See Note 11, Commitments and Contingencies - Partnership Repurchase Provision; Employment Agreements with Executive Officers, to our consolidated financial statements included in this report. +(7) +Amounts presented include $16.4 million payable to the holders of our 3.25% convertible senior notes due 2016 and $149.2 million to the holders of our 12% senior notes due 2018. Amounts also include $29.4 million payable to the participating banks of our revolving credit facilities, of which interest of $3.5 million is related to unutilized commitments at a rate of 0.5% per annum, $25.7 million related to the outstanding borrowings on our revolving credit facilities of $188.2 million and $0.2 million related to our undrawn letters of credit. +(8) +Drilling rig commitments in the above table reflect our maximum obligation for the services of drilling rigs, including $13.9 million related to a rig operating in the Permian Basin. The Permian rig commitment was assigned to the purchaser of our Permian assets on February 28, 2012. See Note 11, Commitments and Contingencies - Drilling Rig Contracts, Note 13, Assets Held for Sale, Divestitures and Discontinued Operations, and Note 18, Subsequent Event, to our consolidated financial statements included in this report. +(9) +Represents our gross commitment, including our proportionate share of PDCM. We will recognize in our financial statements our proportionate share based on our working interest; however, with the exception of contracts entered into by PDCM, the costs of all volume shortfalls will be borne by PDC only. See Note 11, Commitments and Contingencies - Firm Transportation Agreements, to our consolidated financial statements included in this report. +As the managing general partner of 21 partnerships, we have liability for potential casualty losses in excess of the partnership assets and insurance. We believe that the casualty insurance coverage we and our subcontractors carry is adequate to meet this potential liability. +For information regarding our legal proceedings, see Note 11, Commitments and Contingencies – Litigation , to our consolidated financial statements included in this report. From time to time we are a party to various other legal proceedings in the ordinary course of business. We are not currently a party to any litigation that we believe would have a materially adverse effect on our business, financial condition, results of operations or liquidity. +45 +Critical Accounting Policies and Estimates +We have identified the following policies as critical to business operations and the understanding of our results of operations. This is not a comprehensive list of all of the accounting policies. In many cases, the accounting treatment of a particular transaction is specifically dictated by U.S. GAAP, with no need for our judgment in the application. There are also areas in which our judgment in selecting any available alternative would not produce a materially different result. However, certain of our accounting policies are particularly important to the portrayal of our financial position and results of operations and we may use significant judgment in the application; as a result, they are subject to an inherent degree of uncertainty. In applying those policies, we use our judgment to determine the appropriate assumptions to be used in the determination of certain estimates. Those estimates are based on historical experience, observation of trends in the industry, and information available from other outside sources, as appropriate. For a more detailed discussion on the application of these and other accounting policies, see Note 2, Summary of Significant Accounting Policies , to our consolidated financial statements included in this report. Our critical accounting policies and estimates are as follows: +Natural Gas and Crude Oil Properties. We account for our natural gas and crude oil properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and development dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves . Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves. +Annually, we engage independent petroleum engineers to prepare reserve and economic evaluations of all our properties on a well-by-well basis as of December 31. We adjust our natural gas and crude oil reserves for major acquisitions, new drilling and divestitures during the year as needed. The process of estimating and evaluating natural gas and crude oil reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur. Although every reasonable effort is made to ensure that reserve estimates reported represent our most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates over time. Because estimates of reserves significantly affect our DD&A expense, a change in our estimated reserves could have an effect on our net income. +Exploration costs, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized but charged to expense if the well is determined to be nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as the well has found a sufficient quantity of reserves to justify our completion as a producing well and we are making sufficient progress assessing our reserves and economic and operating viability. If an in-progress exploratory well is found to be unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are expensed to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the well is classified as "suspended well costs" until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time when we are able to make a final determination of a well’s productive status, the well is removed from the suspended well status and the proper accounting treatment is applied. +The acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense when expired, impaired or amortized. Unproved natural gas and crude oil properties with individually significant acquisition costs are periodically assessed, and any impairment in value is charged to impairment of natural gas and crude oil properties. The amount of impairment recognized on unproved properties which are not individually significant is determined by amortizing the costs of such properties within appropriate fields based on our historical experience, acquisition dates and average lease terms, with the amortization recognized in impairment of natural gas and crude oil properties. The valuation of unproved properties is subjective and requires us to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual realizable values. +We assess our natural gas and crude oil properties for possible impairment upon a triggering event by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which we reasonably estimate the commodity to be sold. Any impairment in value is charged to impairment of natural gas and crude oil properties. The estimates of future prices may differ from current market prices of natural gas and crude oil. Any downward revisions in estimates to our reserve quantities, expectations of falling commodity prices or rising operating costs could result in a triggering event and therefore a reduction in undiscounted future net cash flows and an impairment of our natural gas and crude oil properties. Although our cash flow estimates are based on the relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results. +See Executive Summary - Operational Overview and Update, Potential for Future Asset Impairments above. +Consolidation and Accounting for Variable Interest Entities. Under applicable accounting guidance, a variable interest entity ("VIE") is consolidated by the entity's primary beneficiary. The primary beneficiary of a VIE has both the following characteristics: (1) the power to direct the activities of the VIE that most significantly impact the entity's economic performance and (2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. +46 +In determining whether we are the primary beneficiary of the VIE, we consider a number of factors, including our ability to direct the activities that most significantly affect the entity's economic success and our contractual rights and responsibilities under the arrangement. These considerations impact the way we account for our existing joint venture relationship. Further, as certain events occur, we reconsider whether those events have caused us to become the primary beneficiary. The consolidation status of our VIE may change if the composition of the board of managers changes or we enter into new or modified contractual arrangements. A reconsideration event may also occur when we acquire new or additional interests in a VIE. +As of September 30, 2011, we concluded that PDCM was no longer a variable interest entity ("VIE") because our voting rights had become proportionately equal to our economic interests and the activities of the entity were being conducted equally for the benefit of both investing partners. The status change of PDCM to a non-VIE did not have an impact on our financial statements, as we continue to proportionately consolidate PDCM in accordance with the voting interest model. See Note 1, Nature of Operations and Basis of Presentation , for more details regarding our interest in PDCM. +Natural Gas, NGL and Crude Oil Sales Revenue Recognition . Natural gas, NGL and crude oil sales are recognized when production is sold to a purchaser at a determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company measured volume readings. We then adjust our natural gas, NGL and crude oil sales in subsequent periods based on the data received from our purchasers that reflects actual volumes and prices received. We receive payment for sales from one to three months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded up to two months later. Historically, differences have been immaterial. +Fair Value of Financial Instruments. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as: +Level 1 – Quoted prices (unadjusted) in active markets for identical assets or liabilities. +Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including (i) quoted prices for similar assets or liabilities in active markets, (ii) quoted prices for identical or similar assets or liabilities in inactive markets, (iii) inputs other than quoted prices that are observable for the asset or liability and (iv) inputs that are derived from observable market data by correlation or other means. Includes our fixed-price swaps, basis swaps and physical purchases. +Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Includes our natural gas and crude oil collars, crude oil puts and physical sales. +Derivative Financial Instruments. We measure the fair value of our derivative instruments based on a pricing model that utilizes market-based inputs, including but not limited to the contractual price of the underlying position, current market prices, natural gas and crude oil forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of derivative liabilities and the effect of our counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position. +We validate our fair value measurement through (1) the review of counterparty statements and other supporting documentation, (2) the determination that the source of the inputs are valid, (3) the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and (4) monitoring changes in valuation methods and assumptions. While we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. While we believe our valuation method is appropriate and consistent with those used by other market participants, the use of a different methodology, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value. +We have evaluated the credit risk of the counterparties holding our derivative assets, which are primarily financial institutions who are also major lenders in our corporate credit facility agreement, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the impact of the nonperformance of our counterparties on the fair value of our derivative instruments is insignificant. +Deferred Income Tax Asset Valuation Allowance. Deferred income tax assets are recognized for deductible temporary differences, net operating loss carry-forwards and credit carry-forwards if it is more likely than not that the tax benefits will be realized. To the extent a deferred tax asset is not expected to be realized under the preceding criteria, we establish a valuation allowance. The factors which we +47 +consider in assessing whether we will realize the value of deferred income tax assets involve judgments and estimates of both amount and timing, which could differ from actual results, achieved in future periods. +The judgments used in applying the above policies are based on our evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results may differ from those estimates. +Accounting for Acquisitions Using Purchase Accounting. We utilize the purchase method to account for acquisitions. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. The purchase price allocations are based on appraisals, discounted cash flows, quoted market prices and estimates by management. When appropriate, we review comparable purchases and sales of natural gas and crude oil properties within the same regions, and use that data as a basis for fair market value; for example, the amount a willing buyer and seller would enter into an exchange for such properties. +In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing , proved undeveloped, unproved natural gas and crude oil properties and other non-natural gas and crude oil properties. To estimate the fair values of these properties, we prepare estimates of natural gas and crude oil reserves. We estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired, and estimates of future operating and development costs, to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted average cost of capital rate is subject to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors. +We record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. +Recent Accounting Standards +See Note 2, Summary of Significant Accounting Policies - Recent Accounting Standards , to our consolidated financial statements included in this report. +Reconciliation of Non-U.S. GAAP Financial Measures +Adjusted cash flow from operations. We define adjusted cash flow from operations as the cash flow earned or incurred from operating activities without regard to the collection or payment of associated receivables or payables. We believe it is important to consider adjusted cash flow from operations as well as cash flow from operations, as we believe it often provides more transparency into what drives the changes in our operating trends, such as production, prices, operating costs, and related operational factors, without regard to whether the earned or incurred item was collected or paid during the period. We also use this measure because the collection of our receivables or payment of our obligations has not been a significant issue for our business, but merely a timing issue from one period to the next, with fluctuations generally caused by significant changes in commodity prices. See the Consolidated Statements of Cash Flows in this report. +Adjusted net income (loss) attributable to shareholders. We define adjusted net income (loss) attributable to shareholders as net income (loss) attributable to shareholders plus unrealized derivative losses, provisions for underpayment of natural gas sales, minus unrealized derivative gains, each adjusted for tax effect. We believe it is important to consider adjusted net income (loss) attributable to shareholders as well as net income (loss) attributable to shareholders. We believe it often provides more transparency into our operating trends, such as production, prices, operating costs, realized gains and losses from derivatives and related factors, without regard to changes in our net income (loss) attributable to shareholders from our mark-to-market adjustments resulting from unrealized gains and losses from derivatives. Additionally, other items, such as the provision for underpayment of natural gas sales, which are not indicative of future results, may be excluded to clearly identify operational trends. +Adjusted EBITDA. We define adjusted EBITDA as net income (loss) plus unrealized derivative loss, interest expense, net of interest income, income taxes, impairment of natural gas and crude oil properties and depreciation, depletion and amortization for the period minus unrealized derivative gain. We believe adjusted EBITDA is relevant because it is a measure of cash available to fund our capital expenditures and service our debt and is a widely used industry metric which allows comparability of our results with our peers. +PV-10% . We define PV-10% as the estimated present value of the future net cash flows from our proved reserves before income taxes, discounted using a 10% discount rate. We believe that PV-10% provides useful information to investors as it is widely used by professional analysts and sophisticated investors when evaluating oil and gas companies. We believe that PV-10% is relevant and useful for evaluating the relative monetary significance of our reserves. Professional analysts and sophisticated investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies' reserves. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pretax measure is valuable in evaluating the Company and our reserves. PV-10% is not intended to represent the current market value of our estimated reserves. +48 +The following table presents a reconciliation of our non-U.S. GAAP financial measures to its nearest U.S. GAAP measure. +Year Ended December 31, +2011 +2010 +2009 +(in millions) +Adjusted cash flow from operations: +Adjusted cash flow from operations +$ +166.2 +$ +132.2 +$ +170.2 +Changes in current assets and liabilities +0.6 +19.6 +(26.3 +) +Net cash provided by operating activities +$ +166.8 +$ +151.8 +$ +143.9 +Adjusted net income (loss) attributable to shareholders: +Adjusted net income (loss) attributable to shareholders +$ +(4.3 +) +$ +0.4 +$ +(5.8 +) +Unrealized gain (loss) on derivatives, net +28.6 +12.6 +(116.6 +) +Provision for underpayment of natural gas sales +— +(3.3 +) +(2.7 +) +Tax effect of above adjustments +(10.9 +) +(3.5 +) +45.8 +Net income (loss) attributable to shareholders +$ +13.4 +$ +6.2 +$ +(79.3 +) +Adjusted EBITDA: +Adjusted EBITDA +$ +188.3 +$ +149.4 +$ +167.9 +Unrealized gain (loss) on derivatives, net +28.6 +12.6 +(116.6 +) +Interest expense, net +(36.9 +) +(33.2 +) +(37.0 +) +Income tax benefit (expense) +(6.2 +) +(0.4 +) +45.6 +Impairment of natural gas and crude oil properties +(25.2 +) +(11.1 +) +(8.2 +) +Depreciation, depletion and amortization +(135.2 +) +(111.1 +) +(131.0 +) +Net income (loss) attributable to shareholders +$ +13.4 +$ +6.2 +$ +(79.3 +) +PV-10%: +PV-10% +$ +1,350.3 +$ +693.1 +$ +359.5 +Present value of estimated future income tax discounted at 10% +(409.1 +) +(204.7 +) +(11.9 +) +Standardized measure of discounted future net cash flows +$ +941.2 +$ +488.4 +$ +347.6 +ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK +Market-Sensitive Instruments and Risk Management +We are exposed to market risks associated with interest rates, commodity prices and credit exposure. We have established risk management processes to monitor and manage these market risks. +Interest Rate Risk +Changes in interest rates affect the amount of interest we earn on our interest bearing cash, cash equivalents and restricted cash accounts and the interest we pay on borrowings under our bank credit facilities. All of our senior notes have a fixed rate and, therefore, near-term changes in interest rates do not expose us to risk of earnings or cash flow loss; however, near-term changes in interest rates may affect the fair value of our fixed-rate debt. +As of December 31, 2011, our interest-bearing deposit accounts included money market accounts, certificates of deposit and checking and savings accounts with various banks. The amount of our interest-bearing cash, cash equivalents and restricted cash as of December 31, 2011, was $13.9 million with an average interest rate of 0.1%. The $13.9 million represents our aggregate bank balances, which includes checks issued and outstanding. Based on a sensitivity analysis of our interest bearing deposits as of December 31, 2011, it was estimated that if market interest rates would have increased or decreased by 1% in 2011, the impact on our annual interest income would have been immaterial. +As of December 31, 2011, excluding the $18.8 million irrevocable standby letters of credit, we had outstanding borrowings on our corporate bank credit facility of $209 million and, representing our proportionate share, $24 million on PDCM's bank credit facility. We estimate that if market interest rates would have increased or decreased by 1%, our 2011 interest expense would have changed by approximately $2.3 million. +49 +Commodity Price Risk +We are exposed to commodity price risk, the potential risk of loss from adverse changes in the market price of natural gas and crude oil commodities. We employ established policies and procedures to manage a portion of the risks associated with these market fluctuations using derivative instruments. These instruments allow us to predict with greater certainty the effective natural gas and crude oil prices to be received for our hedged production as it is produced. We believe that our established derivative policies and procedures are effective in achieving our risk management objectives. +The following table presents our derivative positions (excluding the derivative positions designated to our affiliated partnerships) related to natural gas and crude oil sales in effect as of December 31, 2011 . +Floors +Collars +Fixed-Price Swaps +CIG +Basis Protection Swaps +Commodity/ Index/ +Maturity Period +Quantity +(Oil - MBbls) +Weighted +Average +Contract +Price +Quantity +(Gas - +BBtu (1) +Oil - MBbls) +Weighted Average +Contract Price +Quantity +(Gas - +BBtu (1) +Oil - MBbls) +Weighted +Average +Contract +Price +Quantity +(BBtu) (1) +Weighted +Average +Contract +Price +Fair Value +December 31, +2011 (2) +(in millions) +Floors +Ceilings +Natural Gas +NYMEX +2012 +— +$ +— +4,913.8 +$ +6.00 +$ +8.27 +13,109.7 +$ +5.74 +10,377.7 +$ +(1.81 +) +$ +30.1 +2013 +— +— +4,438.0 +6.10 +8.60 +11,217.5 +5.78 +9,380.3 +(1.81 +) +16.2 +2014 +— +— +— +— +— +5,100.0 +4.39 +— +— +0.2 +CIG +2012 +— +— +— +— +— +700.0 +4.11 +— +— +0.7 +2013 +— +— +235.0 +4.00 +5.45 +— +— +— +— +0.1 +2014 +— +— +1,115.0 +4.50 +5.67 +— +— +— +— +0.7 +2015 +— +— +— +1,040.0 +4.50 +5.67 +— +— +— +— +0.6 +PEPL +2012 +— +— +— +— +— +1,355.8 +6.18 +— +— +4.2 +2013 +— +— +— +— +— +990.4 +6.18 +— +— +2.4 +Total Natural Gas +— +11,741.8 +32,473.4 +19,758.0 +55.2 +Crude Oil +NYMEX +2012 +36.0 +65.38 +643.6 +81.41 +106.28 +684.0 +90.97 +— +— +(6.6 +) +2013 +— +— +617.6 +78.89 +104.27 +486.9 +90.19 +— +— +(4.2 +) +2014 +— +— +36.0 +90.00 +106.15 +— +— +— +— +0.1 +2015 +— +— +36.0 +90.00 +106.15 +— +— +— +— +0.2 +Total Crude Oil +36.0 +1,333.2 +1,170.9 +— +(10.5 +) +Total Natural Gas and Crude Oil +$ +44.7 +__________ +(1 +) +A standard unit of measurement for natural gas (one BBtu equals one MMcf). +(2 +) +Approximately 29.5% of the fair value of our derivative assets and 9.1% of our derivative liabilities were measured using significant unobservable inputs (Level 3); see Note 3, Fair Value Measurements, to the consolidated financial statements included in this report. +50 +The following table presents our derivative positions related to our natural gas marketing in effect as of December 31, 2011 . +Fixed-Price Swaps +NYMEX +Basis Protection Swaps +Commodity/ Derivative +Instrument/ Maturity Period +Quantity +(BBtu) (1) +Weighted +Average +Contract +Price +Quantity +(BBtu) (1) +Weighted +Average +Contract +Price +Fair Value +December 31, +2011 (2) +(in millions) +Natural Gas +Sales +Physical +2012 +33.8 +$ +5.16 +56.5 +$ +0.96 +$ +0.1 +2013 +2.8 +5.61 +— +— +— +Financial +2012 +871.6 +4.87 +227.6 +0.07 +1.5 +2013 +90.0 +5.00 +— +— +0.1 +Purchases +Physical +2012 +870.4 +4.85 +— +— +(1.3 +) +2013 +90.0 +4.99 +— +— +(0.1 +) +Financial +2012 +33.8 +4.23 +30.4 +0.13 +(0.1 +) +2013 +2.8 +4.18 +— +— +— +Total Natural Gas +1,995.2 +314.5 +$ +0.2 +__________ +(1 +) +A standard unit of measurement for natural gas (one BBtu equals one MMcf). +(2 +) +Approximately 6.1% of the fair value of our derivative assets and none of our derivative liabilities were measured using significant unobservable inputs (Level 3); see Note 3, Fair Value Measurements, to the consolidated financial statements included in this report. +The following table presents monthly average NYMEX and CIG closing prices for natural gas and crude oil for the years ended December 31, 2011 and 2010, as well as average sales prices we realized for the respective commodities. +Year Ended December 31, +2011 +2010 +Average Index Closing Price +Natural Gas (per MMBtu) +CIG +$ +3.79 +$ +3.92 +NYMEX +4.04 +4.39 +Crude Oil (per Bbl) +NYMEX +94.01 +77.32 +Average Sales Price Realized +Excluding realized derivative gains/(losses) +Natural Gas (per Mcf) +$ +3.27 +$ +3.61 +Crude Oil (per Bbl) +87.63 +73.96 +Including realized derivative gains/(losses) +Natural Gas (per Mcf) +4.23 +5.13 +Crude Oil (per Bbl) +80.69 +79.70 +Based on a sensitivity analysis as of December 31, 2011 , it was estimated that a 10% increase in natural gas and crude oil prices, inclusive of basis, over the entire period for which we have derivatives in place, including those designated to our affiliated partnerships, would have resulted in a decrease in fair value of $35.9 million; whereas a 10% decrease in prices would have resulted in an increase in fair value of $35.2 million. Excluding the derivatives designated to our affiliated partnerships, the same 10% increase or decrease in natural gas and crude oil prices would have resulted in a decrease in fair value of $34.6 million and an increase in fair value of $33.9 million, respectively. +51 +See Note 3, Fair Value of Financial Instruments , and Note 4, Derivative Financial Instruments , to our consolidated financial statements included in this report for a summary of our open derivative positions as well as a discussion of how we determine the fair value and account for our derivative contracts. +Credit Risk +Credit risk represents the loss that we would incur if a counterparty fails to perform under its contractual obligations. We attempt to reduce credit risk by diversifying our counterparty exposure and entering into transactions with high-quality counterparties. When exposed to credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis. +With regard to our Oil and Gas Exploration and Production segment, inherent to our industry is the concentration of natural gas, NGL and crude oil sales to a few customers. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions. As for our Gas Marketing segment, our receivables are from a diverse group of companies, including major energy companies, both upstream and mid-stream, financial institutions and end-users in various industries. We monitor their creditworthiness through credit reports and rating agency reports. To date, we have had no material counterparty default losses in either of our Oil and Gas Exploration and Production or Gas Marketing segments. See Note 5, Concentration of Risk , to our consolidated financial statements included in this report. +Our derivative financial instruments expose us to the credit risk of nonperformance by the counterparty to the contracts. We primarily use financial institutions, which are also major lenders in our credit facility, as counterparties to our derivative contracts. We have evaluated the credit risk of the counterparties holding our derivative assets using relevant credit market default rates, giving consideration to amounts outstanding from each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the impact of the nonperformance of our counterparties on the fair value of our derivative instruments is insignificant. +Disruption in the credit market may have a significant adverse impact on a number of financial institutions. We monitor the creditworthiness of the financial institutions with which we transact, giving consideration to the reports of credit agencies and their related ratings. While we believe that our monitoring procedures are sufficient and customary, no amount of analysis can assure performance by a financial institution. See Part I, Item 1A, Risk Factors - Credit and funding challenges of French banks who are participants in our revolving credit facility and counterparties to some of our natural gas and crude oil derivative holdings could have a material adverse effect on our operations and financial condition, included in this report. +Disclosure of Limitations +Because the information above included only those exposures that existed at December 31, 2011 , it does not consider those exposures or positions which could arise after that date. As a result, our ultimate realized gain or loss with respect to interest rate and commodity price fluctuations will depend on the exposures that arise during the period, our commodity price risk management strategies at the time, and interest rates and commodity prices at the time. +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +The response to this Item is set forth herein in a separate section of this report, beginning on Page F-1. +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 +As of December 31, 2011 , we carried out an evaluation under the supervision and with the participation of 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 pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e). Based on the results of this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2011 . +Changes in Internal Control over Financial Reporting +During the fourth quarter of 2011 , we made no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) that have materially affected or are reasonably likely to materially affect our internal control over financial reporting. +52 +ITEM 9B. OTHER INFORMATION +None. +PART III +ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2012 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 11. EXECUTIVE COMPENSATION +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2012 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2012 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2012 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2012 Annual Stockholders' meeting and is incorporated by reference in this report. +PART IV +ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES +(a) +(1 +) +Financial Statements: +See Index to Financial Statements and Schedules on page F-1. +(2 +) +Financial Statement Schedules: +See Index to Financial Statements and Schedules on page F-1. +Schedules and Financial Statements Omitted +All other financial statement schedules are omitted because they are not required, inapplicable, or the information is included in the Financial Statements or Notes thereto. +(3 +) +Exhibits: +See Exhibits Index on the following page. +53 +Exhibits Index +Incorporated by Reference +Exhibit +SEC File +Filed +Number +Exhibit Description +Form +Number +Exhibit +Filing Date +Herewith +3.1 +Second Amended and Restated Certificate of Incorporation of Petroleum Development Corporation. +8-K +000-07246 +3.1 +7/23/2008 +3.2 +Bylaws of Petroleum Development Corporation, amended and restated, effective October 11, 2007. +8-K +000-07246 +3.2 +10/17/2007 +4.1 +Rights Agreement by and between Petroleum Development Corporation and Transfer Online, Inc., as Rights Agent, dated as of September 11, 2007, including the forms of Rights Certificates and Summary of Stockholder Rights Plan attached thereto as Exhibits A and B. +8-K +000-07246 +4.1 +9/14/2007 +4.2 +Indenture dated as of February 8, 2008, by and among Petroleum Development Corporation and The Bank of New York. +8-K +000-07246 +4.1 +2/12/2008 +4.3 +First Supplemental Indenture dated as of February 8, 2008, by and among Petroleum Development Corporation and the Bank of New York. +8-K +000-07246 +4.2 +2/12/2008 +4.4 +Form of 12% Senior Note due 2018. +8-K +000-07246 +4.3 +2/12/2008 +4.5 +Indenture, dated November 23, 2010, between the Company and The Bank of New York Mellon. +8-K +000-07246 +4.1 +11/24/2010 +4.6 +Form of 3.25% Convertible Senior Note due 2016 +8-K +000-07246 +4.1 +11/24/2010 +10.1 +Purchase Agreement dated as of February 1, 2008, by and among Petroleum Development Corporation and the Initial Purchasers of 12% senior notes due 2018 named therein. +8-K +000-07246 +10.1 +2/7/2008 +10.2 +Registration Rights Agreement dated as of February 8, 2008, by and among Petroleum Development Corporation and the Initial Purchasers of 12% senior notes due 2018 named therein. +8-K +000-07246 +10.1 +2/12/2008 +10.3 +Underwriting Agreement dated August 11, 2009 among the Company and J.P. Morgan Securities Inc., as representative of the several Underwriters named therein. +8-K +000-07246 +1.1 +8/12/2009 +10.4* +Indemnification Agreement with Directors. +10-Q +000-07246 +10.1 +8/9/2007 +10.5* +The Petroleum Development Corporation 401(k) & Profit Sharing Plan. +10-K +000-07246 +10.6 +2/24/2011 +10.6 +Contribution Agreement by and among PDC Mountaineer, LLC, as the Company, Petroleum Development Corporation, as the Contributor, and LR-Mountaineer Holdings, L.P., as the Investor, dated October 29, 2009. +8-K +000-07246 +2.1 +11/4/2009 +10.7 +Limited Liability Company Agreement of PDC Mountaineer, LLC, dated October 29, 2009. +8-K +000-07246 +10.1 +11/4/2009 +10.8* +Non-Employee Director Deferred Compensation Plan. +S-8 +333-118222 +99.1 +8/13/2004 +10.9* +2004 Long-Term Equity Compensation Plan. +S-8 +333-118215 +8/13/2004 +10.10* +2004 Long-Term Equity Compensation Plan amended and restated as of March 8, 2008. +10-K +000-07246 +10.26 +2/27/2009 +10.11* +2010 Executive Officers Long-Term Incentive Compensation Share Agreement. +8-K +000-07246 +4/23/2010 +10.12* +2011 Executive Officers Long-Term Incentive Compensation Share Agreement, including Form of 2010 Performance Share Agreement as Exhibit 10.1. +8-K +000-07246 +3/17/2011 +10.13* +2012 Executive Officers Long-Term Incentive Compensation Share Agreement, including Form of 2012 Performance Share Agreement as Exhibit 10.1. +8-K +000-07246 +1/20/2012 +54 +Incorporated by Reference +Exhibit Number +Exhibit Description +Form +SEC File +Number +Exhibit +Filing Date +Filed +Herewith +10.14* +Employment Agreement with Richard W. McCullough, Chief Executive Officer, dated as of April 19, 2010. +8-K +000-07246 +10.1 +4/23/2010 +10.15* +Employment Agreement with Gysle R. Shellum, Chief Financial Officer, dated as of April 19, 2010. +8-K +000-07246 +10.2 +4/23/2010 +10.16* +Employment Agreement with Daniel W. Amidon, General Counsel and Corporate Secretary, dated as of April 19, 2010 +8-K +000-07246 +10.3 +4/23/2010 +10.17* +Employment Agreement with Lance A. Lauck, Senior Vice President of Business Development, dated as of April 19, 2010. +8-K +000-07246 +10.4 +4/23/2010 +10.18* +Employment Agreement with James M. Trimble, President and Chief Executive Officer, dated as of November 1, 2011. +10-Q +000-07246 +10.2 +11/3/2011 +10.19* +Separation Agreement and General Release with Richard W. McCullough, former Chairman and Chief Executive Officer, dated as of July 12, 2011. +8-K +000-07246 +10.1 +7/18/2011 +10.20* +Employment Agreement with Barton R. Brookman, Jr., Senior Vice President of Exploration and Production, dated as of April 19, 2010. +8-K +000-07246 +10.5 +4/23/2010 +10.21* +2010 Long-Term Equity Compensation Plan, dated as of April 11, 2010. +S-8 +333-167945 +99.1 +7/1/2010 +10.22 † +Domestic Crude Oil Purchase Agreement between Suncor Energy Marketing, Inc. and PDC, dated May 18, 2009. +10-Q +000-53201 +10.1 +5/18/2009 +10.23 † +Gas Purchase Agreement between Williams Production RMT Company, Riley Natural Gas and Petroleum Development Corporation, dated as of March 31, 2009. +10/A No. 3 +000-53201 +10.7 +3/31/2009 +10.24 † +First Amendment to the Gas Purchase Agreement between Williams Production RMT Company, Riley Natural Gas and Petroleum Development Corporation, dated as of June 1, 2011. +8-K +000-07246 +10.1 +8/2/2011 +10.25† +Gas Purchase and Processing Agreement between Duke Energy Field Services, Inc.; United States Exploration, Inc.; and Petroleum Development Corporation, dated as of October 28, 1999. +10/A No. 3 +000-53201 +10.3 +3/31/2009 +10.26 +Second Amended and Restated Credit Agreement dated as of November 5, 2010, Petroleum Development Corporation, as borrower and JPMorgan Chase Bank, N.A. and BNP Paribas, as lenders. +8-K +000-07246 +10.1 +11/12/2010 +10.27 +Underwriting Agreement dated November 18, 2010, among Petroleum Development Corporation and Wells Fargo Securities, LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representatives of the several underwriters. +8-K +000-07246 +1.1 +11/24/2010 +10.28 +Purchase Agreement, dated as of November 18, 2010, among Petroleum Development Corporation and Wells Fargo Securities, LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representatives of the initial purchasers. +8-K +000-07246 +1.1 +11/24/2010 +10.29 +First Amendment to Second Amended and Restated Credit Agreement, dated as of December 22, 2010. +10-K +000-07246 +10.29 +2/24/2011 +10.30 +Second Amendment to Second Amended and Restated Credit Agreement, dated as of October 12, 2011. +8-K +000-07246 +10.1 +10/18/2011 +10.31 +Purchase and Sale Agreement by and between Petroleum Development Corporation and COG Operating LLC, dated December 20, 2011. +X +12.1 +Computation of Ratio of Earnings to Fixed Charges. +X +14.1 +Code of Business Conduct and Ethics. +10-Q +000-17246 +14.1 +8/10/2009 +21.1 +Subsidiaries. +X +55 +Incorporated by Reference +Exhibit Number +Exhibit Description +Form +SEC File +Number +Exhibit +Filing Date +Filed +Herewith +23.1 +Consent of PricewaterhouseCoopers LLP. +X +23.2 +Consent of Ryder Scott Company, L.P., Petroleum Consultants. +X +31.1 +Certification by Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. +X +31.2 +Certification by Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. +X +32.1** +Certifications by Chief Executive Officer and Chief Financial Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002. +99.1 +Report of Independent Petroleum Consultants - Ryder Scott Company, L.P. +X +101.INS** +XBRL Instance Document +101.SCH** +XBRL Taxonomy Extension Schema Document +101.CAL** +XBRL Taxonomy Extension Calculation Linkbase Document +101.DEF** +XBRL Taxonomy Extension Definition Linkbase Document +101.LAB** +XBRL Taxonomy Extension Label Linkbase Document +101.PRE** +XBRL Taxonomy Extension Presentation Linkbase Document +*Management contract or compensatory plan or arrangement. +** Furnished herewith. +† Confidential portions of this document have been omitted and are filed separately with the SEC pursuant to Exchange Act Rule 24b-2. +56 +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. +PETROLEUM DEVELOPMENT CORPORATION +By /s/ James M. Trimble +James M. Trimble +President and Chief Executive Officer +March 1, 2012 +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/ James M. Trimble +President, Chief Executive Officer and Director +March 1, 2012 +James M. Trimble +(principal executive officer) +/s/ Gysle R. Shellum +Chief Financial Officer +March 1, 2012 +Gysle R. Shellum +(principal financial officer) +/s/ R. Scott Meyers +Chief Accounting Officer +March 1, 2012 +R. Scott Meyers +(principal accounting officer) +/s/ Jeffrey C. Swoveland +Chairman and Director +March 1, 2012 +Jeffrey C. Swoveland +/s/ Joseph E. Casabona +Director +March 1, 2012 +Joseph E. Casabona +/s/ Anthony J. Crisafio +Director +March 1, 2012 +Anthony J. Crisafio +/s/ Larry F. Mazza +Director +March 1, 2012 +Larry F. Mazza +/s/ David C. Parke +Director +March 1, 2012 +David C. Parke +/s/ Kimberly Luff Wakim +Director +March 1, 2012 +Kimberly Luff Wakim +57 +GLOSSARY OF UNITS OF MEASUREMENT AND INDUSTRY TERMS +UNITS OF MEASUREMENT +The following presents a list of units of measurement used throughout the document. +Bbl – One barrel of crude oil or NGL or 42 gallons of liquid volume. +Bcf – One billion cubic feet of natural gas volume. +Bcfe – One billion cubic feet of natural gas equivalent. +Btu – British thermal unit. +BBtu - One billion British thermal units. +MBbls – One thousand barrels of crude oil. +Mcf – One thousand cubic feet of natural gas volume. +Mcfe – One thousand cubic feet of natural gas equivalent (six Mcf of natural gas equals one Bbl of crude oil or NGL). +MMBtu – One million British thermal units. +MMcf – One million cubic feet of natural gas volume. +MMcfe – One million cubic feet of natural gas equivalent. +Tcfe – One trillion cubic feet of natural gas equivalent. +GLOSSARY OF INDUSTRY TERMS +The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report. +3P - See proved, probable and possible reserves. +Behind-pipe reserves - Natural gas and crude oil reserves expected to be recovered from zones in existing wells, which will require additional completion work or future recompletion prior to the start of production. Generally, these are reserves in reservoirs above currently producing zones. +CIG - Colorado Interstate Gas. +Completion - Refers to the work performed and the installation of permanent equipment for the production of natural gas and crude oil from a recently drilled well. +Delineation drilling - A drilling technique carried out to gain a better understanding of the structure and extent of a deposit in order to decide whether or not to conduct further drilling activities. +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 [natural] gas - Natural gas is considered dry when its composition is over 90% pure methane. +Dry hole - A well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion as an oil or gas well. +Exit rate - Rate of production as of the date specified. +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 gas in another reservoir. +Extensions and discoveries - As to any period, the increases to proved reserves from all sources other than the acquisition of proved properties or revisions of previous estimates. +Farm-out - Transfer of all or part of the operating rights from a working interest owner to an assignee, who assumes all or some of the burden of development in return for an interest in the property. The assignor usually retains an overriding royalty interest but may retain any type of interest. +Fracture or Fracturing - Procedure to stimulate production by forcing a mixture of fluid and proppant into the formation under high pressure. Fracturing creates artificial fractures in the reservoir rock to increase permeability and porosity, thereby allowing the release of trapped hydrocarbons. +Gross acres or wells - Refers to the total acres or wells in which we have a working interest. +Horizontal drilling - A drilling technique that permits the operator to drill a horizontal well shaft from the bottom of a vertical well and thereby to contact and intersect a larger portion of the producing horizon than conventional vertical drilling techniques and may, depending on the horizon, result in increased production rates and greater ultimate recoveries of hydrocarbons. +58 +Joint interest billing or JIB - Process of billing/invoicing the costs related to well drilling, completions and production operations among working interest partners. +Monitoring well - A well designed and installed to obtain representative groundwater quality samples and hydrogeologic information. +Natural gas liquid(s) or NGL(s) - Hydrocarbons which can be extracted from wet natural gas and become liquid under various combinations of increasing pressure and lower temperature. NGLs include ethane, propane, butane, and other natural gasolines. +Net acres or wells - Refers to gross acres or wells we own multiplied, in each case, by our percentage working interest. References to net acres or wells well include our proportionate share of PDCM's and our affiliated partnerships' net acres or wells. +Net production - Natural gas and crude oil production that we own, less royalties and production due to others. References to net production include our proportionate share of PDCM's and our affiliated partnerships' net production. +Non-operated - A project in which we are not the operator. +NYMEX - New York Mercantile Exchange. +Operator - The individual or company responsible for the exploration, development and/or production of an oil or gas well or lease. +Overriding royalty - An interest which is created out of the operating or working interest. Its term is coextensive with that of the operating interest. +PEPL - Panhandle Eastern Pipeline. +Possible reserves - Those reserves that are less certain to be recovered than probable reserves. When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability to exceed the sum of proved, probable and possible reserves. When probabilistic methods are used, there must be at least a 10 percent probability that the actual quantities recovered will equal or exceed the sum of proved, probable and possible estimates. +Present value of future net revenues or (PV-10%) - The present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, of proved reserves calculated in accordance with Financial Accounting Standards Board guidelines, net of estimated production and future development costs, using pricing and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debit service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. PV-10% is pretax and therefore a non-U.S. GAAP financial measure. +Probable reserves - Those reserves that are less certain to be recovered than proved reserves but which, in sum with proved reserves, are as likely as not to be recovered. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. Similarly, when probabilistic methods are used, there must be at least a 50 percent probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. +Proved developed non-producing reserves or PDNPs - Reserves that consist of (i) proved reserves from wells which have been completed and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and/or (ii) proved reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the wells. +Proved developed producing reserves or PDPs - Proved reserves that can be expected to be recovered from currently producing zones under the continuation of present operating methods. +Proved developed reserves - The combination of proved developed producing and proved developed non-producing reserves. +Proved, probable and possible or 3P reserves - Proved reserves plus probable reserves plus possible reserves. +Proved reserves - Those quantities of natural gas, NGL, crude oil and condensate, 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 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. +Proved undeveloped reserves or PUDs - Proved 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. +Recomplete or Recompletion - The modification of an existing well for the purpose of producing natural gas and crude oil from a different producing formation. +59 +Refracture - A refracture is when we stimulate by fracturing a producing zone of a well to increase its production as well as its PDP reserves. +Reserve replacement - Calculated by dividing the sum of reserve additions from all sources (revisions, extensions, discoveries and other additions and acquisitions) by the actual production for the corresponding period. The values used for reserve additions are derived directly from the proved reserves table located in Supplemental Information - Natural Gas and Crude Oil Operations to our consolidated financial statements included in this report. We use the reserve replacement ratio as an indicator of our ability to replenish annual production volumes and grow our reserves, thereby providing some information on the sources of future production. It should be noted that the reserve replacement ratio is a statistical indicator that has limitations. As an annual measure, the ratio is limited because it typically varies widely based on the extent and timing of new discoveries and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not embed the cost or timing of future production of new reserves, it cannot be used as a measure of value creation. +Reserves - Estimated remaining quantities of natural gas, NGLs crude oil and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering natural gas, NGLs and crude oil or related substances to market, and all permits and financing required to implement the project. +Royalty - An interest in a natural gas and crude oil lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner. +Spud - To begin drilling; the act of beginning a hole. Past tense: spudded . +Standardized measure of discounted future net cash flows or standardized measure - Future net cash flows discounted at a rate of 10%. Future net cash flows represent the estimated future revenues to be generated from the production of proved reserves determined in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, giving effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment and (ii) future income tax expense. +Unconventional resource(s) - Natural gas and crude oil that cannot be produced at economic flow rates in economic volumes unless the well is stimulated by a large hydraulic fracture treatment, a horizontal wellbore, or by using multilateral wellbores or some other techniques to expose more of the resources to the wellbore. +Undeveloped acreage - Leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and crude oil, regardless of whether such acreage contains proved reserves. +Wet [natural] gas - Natural gas that contains a larger quantity of hydrocarbon liquids than dry natural gas, such as NGLs, condensate and crude oil. +Working interest - An interest in a natural gas and crude oil lease that gives the owner of the interest the right to drill and produce natural gas and crude oil on the leased acreage. It requires the owner to pay all of their share of the costs of drilling and production operations. +Workover - Major remedial operations on a producing well to restore, maintain or improve the well's production. +60 +Index to Consolidated Financial Statements, Financial Statement Schedule and Supplemental Information +Management's Report on Internal Control Over Financial Reporting +62 +Financial Statements: +Report of Independent Registered Public Accounting Firm +63 +Consolidated Balance Sheets - December 31, 2011 and 2010 +64 +Consolidated Statements of Operations - Years Ended December 31, 2011, 2010 and 2009 +65 +Consolidated Statements of Cash Flows - Years Ended December 31, 2011, 2010 and 2009 +65 +Consolidated Statements of Equity - Years Ended December 31, 2011, 2010, and 2009 +65 +Notes to Consolidated Financial Statements +Note 1. Nature of Operations and Basis of Presentation +66 +Note 2. Summary of Significant Accounting Policies +66 +Note 3. Fair Value of Financial Instruments +72 +Note 4. Derivative Financial Instruments +74 +Note 5. Concentration of Risk +76 +Note 6. Properties and Equipment +77 +Note 7. Income Taxes +78 +Note 8. Long-Term Debt +80 +Note 9. Asset Retirement Obligations +82 +Note 10. Employee Benefit Plans +83 +Note 11. Commitments and Contingencies +83 +Note 12. Common Stock +86 +Note 13. Assets Held for Sale, Divestitures and Discontinued Operations +90 +Note 14. Acquisitions +92 +Note 15. Noncontrolling Interest in Subsidiary +93 +Note 16. Transactions with Affiliates +93 +Note 17. Business Segments +94 +Note 18. Subsequent Event +95 +Financial Statement Schedule +Schedule II - Valuation and Qualifying Accounts +104 +Supplemental Information - Unaudited +Natural Gas and Crude Oil Information +96 +Quarterly Financial Information +102 +61 +Management's Report on Internal Control Over Financial Reporting +Management is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. 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. 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 policies or procedures may deteriorate. +Management has assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2011, based upon the criteria established in "Internal Control – Integrated Framework" issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). Based on this evaluation, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2011 . +The effectiveness of the Company's internal control over financial reporting as of December 31, 2011 , has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein. +PETROLEUM DEVELOPMENT CORPORATION +/s/ James M. Trimble +James M. Trimble +President and Chief Executive Officer +/s/ Gysle R. Shellum +Gysle R. Shellum +Chief Financial Officer +/s/ R. Scott Meyers +R. Scott Meyers +Chief Accounting Officer +62 +Report of Independent Registered Public Accounting Firm +To the Board of Directors and Shareholders of Petroleum Development Corporation: +In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, equity, and cash flows present fairly, in all material respects, the financial position of Petroleum Development Corporation and its subsidiaries at 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. In addition, in our opinion, the financial statement schedule appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting 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 (COSO). The Company's management is responsible for these financial statements and financial statement schedule, 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 opinions on these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated 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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. +As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for the consolidation of variable interest entities in 2010. +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 (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 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. +/s/ PricewaterhouseCoopers LLP +Pittsburgh, Pennsylvania +March 1, 2012 +63 +Petroleum Development Corporation +(dba PDC Energy) +Consolidated Balance Sheets +(in thousands, except share and per share data) +As of December 31, +2011 +2010 +Assets +Current assets: +Cash and cash equivalents +$ +8,238 +$ +54,372 +Restricted cash +11,070 +2,474 +Accounts receivable, net +59,923 +53,978 +Accounts receivable affiliates +8,518 +11,448 +Fair value of derivatives +60,809 +42,953 +Prepaid expenses and other current assets +24,492 +11,598 +Total current assets +173,050 +176,823 +Properties and equipment, net +1,301,716 +1,008,670 +Assets held for sale +148,249 +116,559 +Fair value of derivatives +41,175 +44,464 +Accounts receivable affiliates +2,836 +8,478 +Other assets +30,979 +34,041 +Total Assets +$ +1,698,005 +$ +1,389,035 +Liabilities and Equity +Liabilities +Current liabilities: +Accounts payable +$ +76,027 +$ +47,271 +Accounts payable affiliates +10,176 +9,605 +Production tax liability +18,949 +16,226 +Fair value of derivatives +27,974 +29,998 +Funds held for distribution +28,594 +29,755 +Accrued interest payable +11,243 +10,051 +Other accrued expenses +22,083 +17,723 +Total current liabilities +195,046 +160,629 +Long-term debt +532,157 +295,695 +Deferred income taxes +207,573 +187,999 +Asset retirement obligation +46,316 +27,797 +Fair value of derivatives +21,106 +36,644 +Accounts payable affiliates +6,134 +12,111 +Other liabilities +25,561 +25,919 +Total liabilities +1,033,893 +746,794 +Commitments and contingent liabilities +Equity +Shareholders' equity: +Preferred shares, par value $0.01 per share; authorized 50,000,000 +shares; issued: none +— +— +Common shares, par value $0.01 per share; authorized 100,000,000 +shares; issued: 23,634,958 in 2011 and 23,462,326 in 2010 +236 +235 +Additional paid-in capital +217,707 +209,198 +Retained earnings +446,280 +432,843 +Treasury shares, at cost: 2,938 in 2011 and 2010 +(111 +) +(111 +) +Total shareholders' equity +664,112 +642,165 +Noncontrolling interest in subsidiary +— +76 +Total equity +664,112 +642,241 +Total Liabilities and Equity +$ +1,698,005 +$ +1,389,035 +See accompanying Notes to Consolidated Financial Statements +64 +Petroleum Development Corporation +(dba PDC Energy) +Consolidated Statements of Operations +(in thousands, except per share data) +Year Ended December 31, +2011 +2010 +2009 +Revenues: +Natural gas, NGL and crude oil sales +$ +276,605 +$ +205,029 +$ +171,242 +Sales from natural gas marketing +66,419 +69,071 +59,595 +Commodity price risk management gain (loss), net +46,090 +59,891 +(10,053 +) +Well operations, pipeline income and other +6,846 +9,030 +10,092 +Total revenues +395,960 +343,021 +230,876 +Costs, expenses and other: +Production costs +69,085 +64,872 +62,103 +Cost of natural gas marketing +65,465 +68,015 +57,618 +Exploration expense +6,253 +13,675 +14,069 +Impairment of natural gas and crude oil properties +25,159 +6,481 +5,034 +General and administrative expense +61,454 +42,188 +53,985 +Depreciation, depletion, and amortization +128,907 +108,095 +126,755 +Gain on sale of properties and equipment +(196 +) +(174 +) +(470 +) +Total cost, expenses and other +356,127 +303,152 +319,094 +Income (loss) from operations +39,833 +39,869 +(88,218 +) +Interest income +47 +71 +254 +Interest expense +(36,985 +) +(33,250 +) +(37,208 +) +Income (loss) from continuing operations before income taxes +2,895 +6,690 +(125,172 +) +Provision (benefit) for income taxes +(183 +) +652 +(45,054 +) +Income (loss) from continuing operations +3,078 +6,038 +(80,118 +) +Income (loss) from discontinued operations, net of tax +10,359 +(104 +) +(975 +) +Net income (loss) +13,437 +5,934 +(81,093 +) +Less: net loss attributable to noncontrolling interests +— +(280 +) +(1,816 +) +Net income (loss) attributable to shareholders +$ +13,437 +$ +6,214 +$ +(79,277 +) +Amounts attributable to Petroleum Development Corporation shareholders: +Income (loss) from continuing operations +$ +3,078 +$ +6,318 +$ +(78,302 +) +Income (loss) from discontinued operations, net of tax +10,359 +(104 +) +(975 +) +Net income (loss) attributable to shareholders +$ +13,437 +$ +6,214 +$ +(79,277 +) +Earnings (loss) per share attributable to shareholders: +Basic +Income (loss) from continuing operations +$ +0.13 +$ +0.33 +$ +(4.76 +) +Income (loss) from discontinued operations +0.44 +(0.01 +) +(0.06 +) +Net income (loss) attributable to shareholders +$ +0.57 +$ +0.32 +$ +(4.82 +) +Diluted +Income (loss) from continuing operations +$ +0.13 +$ +0.32 +$ +(4.76 +) +Income (loss) from discontinued operations +0.43 +(0.01 +) +(0.06 +) +Net income (loss) attributable to shareholders +$ +0.56 +$ +0.31 +$ +(4.82 +) +Weighted average common shares outstanding +Basic +23,521 +19,674 +16,448 +Diluted +23,871 +19,821 +16,448 +Petroleum Development Corporation +(dba PDC Energy) +Consolidated Statements of Cash Flows +(in thousands) +Year Ended December 31, +2011 +2010 +2009 +Cash flows from operating activities: +Net income (loss) +$ +13,437 +$ +5,934 +$ +(81,093 +) +Adjustments to net income (loss) to reconcile to net cash provided by operating activities: +Unrealized loss (gain) on derivatives, net +(28,601 +) +(12,625 +) +116,623 +Depreciation, depletion and amortization +135,154 +111,062 +131,004 +Impairment of natural gas and crude oil properties +25,159 +11,147 +8,205 +Exploratory dry hole costs +177 +4,199 +1,059 +Accretion of asset retirement obligation +1,897 +1,423 +1,368 +Stock-based compensation +8,781 +5,314 +5,935 +Excess tax benefits from stock-based compensation +(1,311 +) +(293 +) +— +Loss (gain) from sale of properties and equipment +(4,263 +) +299 +(105 +) +Amortization of debt discount and issuance costs +6,265 +4,618 +5,302 +Deferred income taxes +9,530 +1,179 +(18,084 +) +Total adjustments to net income (loss) to reconcile to net cash provided by operating activities: +152,788 +126,323 +251,307 +Changes in current assets and liabilities: +Decrease (increase) in restricted cash +(8,603 +) +219 +15,564 +Decrease (increase) in accounts receivable +(3,451 +) +2,122 +13,197 +Decrease (increase) in other current assets +(2,399 +) +23,591 +3,032 +Increase (decrease) in production tax liability +5,436 +(6,818 +) +(4,541 +) +Increase (decrease) in accounts payable and accrued expenses +12,422 +1,172 +(22,482 +) +Decrease in other current liabilities +(2,796 +) +(730 +) +(31,089 +) +Total changes in current assets and liabilities +609 +19,556 +(26,319 +) +Net cash provided by operating activities +166,834 +151,813 +143,895 +Cash flows from investing activities: +Capital expenditures +(334,496 +) +(162,723 +) +(143,033 +) +Acquisition of oil and gas properties, net of cash acquired +(145,894 +) +(158,051 +) +— +Proceeds from sale of properties and equipment +23,140 +23,369 +755 +Other +849 +(3,527 +) +— +Net cash used in investing activities +(456,401 +) +(300,932 +) +(142,278 +) +Cash flows from financing activities: +Proceeds from credit facility +417,194 +414,500 +285,086 +Proceeds from senior notes +— +115,000 +— +Payment of credit facility +(183,713 +) +(494,500 +) +(399,586 +) +Payment of debt issuance costs +(680 +) +(8,541 +) +(9,249 +) +Proceeds from sale of equity, net of issuance costs +— +125,506 +48,490 +Excess tax benefits from stock-based compensation +1,311 +293 +— +Contribution by investing partner in PDCM +12,464 +20,077 +55,000 +Purchase of treasury stock +(3,143 +) +(788 +) +(364 +) +Net cash provided by (used in) financing activities +243,433 +171,547 +(20,623 +) +Net increase (decrease) in cash and cash equivalents +(46,134 +) +22,428 +(19,006 +) +Cash and cash equivalents, beginning of year +54,372 +31,944 +50,950 +Cash and cash equivalents, end of year +$ +8,238 +$ +54,372 +$ +31,944 +Supplemental cash flow information: +Cash payments (receipts) for: +Interest, net of capitalized interest +$ +29,429 +$ +28,335 +$ +32,014 +Income tax refunds, net of income taxes +(1,498 +) +(27,322 +) +(3,355 +) +Non-cash investing activities: +Change in accounts payable related to purchases of properties and equipment +23,837 +15,787 +(36,765 +) +Change in asset retirement obligation, with a corresponding increase to natural gas and crude oil properties, net of disposals +17,538 +3,624 +5,110 +Non-cash financing activities: +Change in paid-in capital related to convertible debt, net of tax +— +12,850 +— +Petroleum Development Corporation +(dba PDC Energy) +Consolidated Statements of Equity +(in thousands, except share and per share data) +Year Ended December 31, +2011 +2010 +2009 +Common shares, issued: +Shares beginning of year +23,462,326 +19,242,219 +14,871,870 +Shares issued pursuant to sale of equity +— +4,140,000 +4,312,500 +Exercise of stock options +2,814 +— +— +Issuance of stock awards, net of forfeitures +242,334 +110,680 +79,246 +Retirement of treasury shares +(72,516 +) +(30,573 +) +(21,397 +) +Shares end of year +23,634,958 +23,462,326 +19,242,219 +Treasury shares: +Shares beginning of year +2,938 +8,273 +7,066 +Purchase of treasury shares +87,588 +30,573 +21,397 +Issuance of treasury shares +(15,072 +) +— +— +Retirement of treasury shares +(72,516 +) +(30,573 +) +(21,397 +) +Non-employee directors' deferred compensation plan +— +(5,335 +) +1,207 +Shares end of year +2,938 +2,938 +8,273 +Common shares outstanding +23,632,020 +23,459,388 +19,233,946 +Equity: +Shareholders' equity +Preferred shares, par value $0.01 per share: +Balance beginning and end of year +$ +— +$ +— +$ +— +Common shares, par value $0.01 per share: +Balance beginning of year +235 +192 +149 +Shares issued pursuant to sale of equity +— +41 +43 +Issuance of stock awards, net of forfeitures +1 +2 +— +Balance end of year +236 +235 +192 +Additional paid-in capital: +Balance beginning of year +209,198 +64,406 +5,818 +Proceeds from sale of equity, net of issuance costs +— +125,465 +48,447 +Convertible debt discount, net of issuance costs and tax +— +12,165 +— +Issuance of stock awards, net of forfeitures +(1 +) +(2 +) +— +Stock-based compensation expense +8,781 +5,314 +5,935 +Issuance of treasury shares +(472 +) +— +— +Retirement of treasury shares +(2,671 +) +(788 +) +(364 +) +Tax benefit (detriment) of stock-based compensation +786 +(164 +) +(1,630 +) +Contribution by investing partner in PDCM +12,464 +20,077 +55,000 +Effect of PDCM deconsolidation/change in ownership interest +(10,378 +) +(17,275 +) +(48,800 +) +Balance end of year +217,707 +209,198 +64,406 +Retained earnings: +Balance beginning of year +432,843 +426,629 +505,906 +Net income (loss) attributable to shareholders +13,437 +6,214 +(79,277 +) +Balance end of year +446,280 +432,843 +426,629 +Treasury shares, at cost: +Balance beginning of year +(111 +) +(312 +) +(292 +) +Purchase of treasury shares +(3,143 +) +(788 +) +(364 +) +Issuance of treasury shares +472 +— +— +Retirement of treasury shares +2,671 +788 +364 +Non-employee directors' deferred compensation plan +— +201 +(20 +) +Balance end of year +(111 +) +(111 +) +(312 +) +Total shareholders' equity +664,112 +642,165 +490,915 +Noncontrolling interests in subsidiary +Balance beginning of year +76 +47,678 +694 +Noncontrolling interest in PDC Mountaineer, LLC +— +(47,322 +) +48,800 +Net loss attributed to noncontrolling interest in subsidiary +(76 +) +(280 +) +(1,816 +) +Balance end of year +— +76 +47,678 +Total noncontrolling interests in subsidiary +— +76 +47,678 +Total Equity +$ +664,112 +$ +642,241 +$ +538,593 +See accompanying Notes to Consolidated Financial Statements +65 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +NOTE 1 - NATURE OF OPERATIONS AND BASIS OF PRESENTATION +Petroleum Development Corporation ("PDC," "PDC Energy," "we," "us" or "the Company") is a domestic independent natural gas and crude oil company engaged in the exploration for and the acquisition, development, production and marketing of natural gas, natural gas liquids ("NGLs") and crude oil. As of December 31, 2011 , we owned an interest in approximately 6,500 gross wells located primarily in the Appalachian Basin, Wattenberg Field, northeast Colorado and Piceance Basin. We are engaged in two business segments: (1) Oil and Gas Exploration and Production and (2) Gas Marketing. +The consolidated financial statements include the accounts of PDC, our wholly owned subsidiaries, an entity in which we have a controlling financial interest and our proportionate share of PDC Mountaineer, LLC ("PDCM") and 21 of our affiliated partnerships. Pursuant to the proportionate consolidation method, our accompanying consolidated financial statements include our pro rata share of assets, liabilities, revenues and expenses of the entities which we proportionately consolidate. All material intercompany accounts and transactions have been eliminated in consolidation. +On January 1, 2010, pursuant to the adoption of new accounting changes related to variable interest entities ("VIE"), PDCM, a VIE, was deconsolidated from 100% and proportionately consolidated at 67.4%, representing only our ownership interest. Through a series of capital contributions by our investing partner, our ownership interest in PDCM decreased to 50% as of September 30, 2011. Each change in our ownership interest resulted in a decrease in our proportionate share of net assets and any future earnings. As of September 30, 2011, we concluded that PDCM was no longer a VIE because our voting rights had become proportionately equal to our economic interests and the activities of the entity were being conducted equally for the benefit of both investing partners. The status change of PDCM to a non-VIE subject to the voting interest model did not have an impact on our financial statements, as we continue to proportionately consolidate PDCM. +The following table presents a detailed summary of the capital contributions made by our investing partner and our resulting ownership interest. +Date of Contribution +Investing +Partner +Contribution +PDC's +Ownership Interest +in PDCM +(in thousands) +April 1, 2010 +$ +28,000 +57.8% +November 1, 2010 +7,000 +55.8% +January 1, 2011 +7,000 +53.9% +March 1, 2011 +5,000 +52.7% +September 23, 2011 +11,500 +50.0% +The preparation of our consolidated financial statements in accordance with generally accepted accounting principles in the United States of America ("U.S. GAAP") requires us to make estimates and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to our consolidated financial statements include estimates of natural gas, NGL and crude oil sales revenue, natural gas, NGL and crude oil reserves, future cash flows from natural gas and crude oil properties, valuation of derivative instruments and valuation of deferred income tax assets. +Certain reclassifications have been made to prior period financial statements to conform to the current year presentation. The reclassifications are mainly related to our discontinued operations. See Note 13 for additional information regarding our discontinued operations. We also reclassified (1) impairment and amortization charges recorded for unproved properties out of the statement of operations' line item exploration expense and into impairment of natural gas and crude oil properties, and (2) the derivatives fair value hierarchy level of our NYMEX-based natural gas fixed-price swaps from Level 1 to Level 2 and, our PEPL and CIG-based natural gas fixed-price swaps, crude oil fixed-price swaps, basis swaps and natural gas physical purchases from Level 3 to Level 2. These reclassifications had no impact on previously reported cash flows, net income, earnings per share or shareholders' equity. +NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Consolidation and Accounting for Variable Interest Entities. A VIE is consolidated if it is determined that we are the entity's primary beneficiary. The primary beneficiary of a VIE has both the following characteristics: (1) the power to direct the activities of the VIE that most significantly impact the entity's economic performance and (2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. In determining whether we are the primary beneficiary of a VIE, we consider a number of factors, including our ability to direct the activities that most significantly affect the entity's economic success and our contractual rights and responsibilities under arrangements with the entity. As certain events occur, we may reconsider whether those events have caused us to become the primary beneficiary. A reconsideration event may also occur when we acquire new or additional interests in a VIE. +66 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the carrying amount and classification of our proportionate share of PDCM's assets and liabilities included in our balance sheets. +As of December 31, +2011 +2010 +Balance Sheets +(in thousands) +Cash and cash equivalents +$ +748 +$ +1,560 +Other current assets +8,568 +3,206 +Property, plant and equipment, net +211,150 +101,679 +Other assets +4,833 +1,986 +Total assets +$ +225,299 +$ +108,431 +Other current liabilities +$ +9,076 +$ +4,641 +Long-term debt +24,000 +— +Asset retirement obligation +18,917 +8,681 +Other liabilities +2,103 +1,370 +Equity +171,203 +93,739 +Total liabilities and equity +$ +225,299 +$ +108,431 +Cash Equivalents. We consider all highly liquid investments with original maturities of three months or less to be cash equivalents. +Restricted Cash. Pursuant to an oral litigation settlement agreement, in July 2011, we funded an escrow account in the amount of $8.7 million. Final approval of the settlement was received in January 2012, with payment of settlement amount to be distributed during the first half of 2012. See Note 11 for a discussion of this settlement. +We are required by certain government agencies or agreements to maintain bonds or cash accounts for various operating activities. As of December 31, 2011, we had collateral in the form of certificates of deposit and cash totaling $3.8 million which consisted of $2.3 million and $1.5 million included in restricted cash and other assets, respectively. As of December 31, 2010, we had collateral in the form of certificates of deposit and cash totaling $5.1 million, which consisted of $2.5 million and $2.6 included in restricted cash and other assets, respectively. +Inventory. Inventory consists of crude oil, stated at the lower of cost to produce or market, and other production supplies intended to be used in our natural gas and crude oil operations. As of December 31, 2011 and 2010, inventory of $1.1 million and $1.4 million, respectively, is included in prepaid expenses and other current assets on the balance sheets. +Derivative Financial Instruments. We are exposed to the effect of market fluctuations in the prices of natural gas and crude oil. We employ established policies and procedures to manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. Our policy prohibits the use of natural gas and crude oil derivative instruments for speculative purposes. +All derivative assets and liabilities are recorded on our balance sheets at fair value. We have elected not to designate any of our derivative instruments as hedges. Classification of realized and unrealized gains and losses resulting from maturities and changes in fair value of open derivatives depends on the purpose for issuing or holding the derivative. Accordingly, changes in the fair value of our derivative instruments are recorded in the statements of operations, with the exception of changes in fair value related to those derivatives we designated to our affiliated partnerships. Changes in the fair value of derivative instruments related to our Oil and Gas Exploration and Production segment are recorded in commodity price risk management, net. Changes in the fair value of derivative instruments related to our Gas Marketing segment are recorded in sales from and cost of natural gas marketing. Changes in the fair value of the derivative instruments designated to our affiliated partnerships are recorded on the balance sheets in accounts payable affiliates and accounts receivable affiliates. As positions designated to our affiliated partnerships settle, the realized gains and losses are netted for distribution. Net realized gains are paid to the partnerships and net realized losses are deducted from the partnerships’ cash distributions from production. The affiliated partnerships bear their designated share of counterparty risk. +The validation of the derivative instrument's fair value is performed internally and, while we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. See Notes 3 and 4 for a discussion of our derivative fair value measurements and a summary fair value table of our open positions as of December 31, 2011 and 2010, respectively. +Properties and Equipment. Significant accounting polices related to our properties and equipment are discussed below. +Natural Gas and Crude Oil Properties. We account for our natural gas and crude oil properties under the successful efforts method +67 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves. We calculate quarterly depreciation, depletion and amortization ("DD&A") expense by using our estimated prior period-end reserves as the denominator, with the exception of our fourth quarter where we use the year-end reserve estimate adjusted to add back fourth quarter production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized in the statement of operations as a gain or loss. Upon the sale of individual wells or a portion of a field, the proceeds are credited to accumulated DD&A. +Exploration costs, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized but charged to expense if the well is determined to be nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as we have found a sufficient quantity of reserves to justify our completion as a producing well, we are making sufficient progress assessing our reserves and economic and operating viability or we have not made sufficient progress to allow for final determination of productivity. If an in-progress exploratory well is found to be unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are expensed to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the costs associated with the well are classified as "suspended well costs" until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time we are able to make a final determination of a well’s productive status, the same well is removed from the suspended well status and the proper accounting treatment is recorded. See Note 6 for disclosure related to changes in our capitalized exploratory well costs. +Impairment of Natural Gas and Crude Oil Properties. The following table presents impairment charges recorded for natural gas and crude oil properties. +Year Ended December 31, +2011 +2010 +2009 +(in thousands) +Continuing operations: +Impairment of proved properties +$ +22,460 +$ +— +$ +926 +Impairment of individually significant unproved properties +1,108 +1,477 +982 +Amortization of individually insignificant unproved properties +1,591 +5,004 +3,126 +Total in continuing operations +25,159 +6,481 +5,034 +Discontinued operations: +Impairment of proved properties +— +4,666 +— +Impairment of individually significant unproved properties +— +— +3,171 +Total in discontinued operations +— +4,666 +3,171 +Total impairment of natural gas and crude oil properties +$ +25,159 +$ +11,147 +$ +8,205 +Proved Property Impairment. We assess our producing natural gas and crude oil properties for possible impairment, upon a triggering event, by comparing net capitalized costs, or carrying value, to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which we reasonably estimate the commodity to be sold. The estimates of future prices may differ from current market prices of natural gas and crude oil. Certain events, including but not limited to, downward revisions in estimates to our reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event and, therefore, a possible impairment of our proved natural gas and crude oil properties. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis and is measured by the amount by which the net capitalized costs exceed their fair value. +In October 2011, pursuant to our plan to divest our northeast Colorado ("NECO") assets, we reclassified our NECO assets as held for sale. Long lived assets held for sale are required to be measured at the lower of carrying value or fair value less costs to sell. We compared the fair value, estimated using Level 3 inputs, which included unrelated third party bids, less costs to sell the assets to their carrying value. The results of the comparison identified that the assets' carrying value exceeded the estimated fair value and, therefore, resulted in an impairment charge of $22.5 million to write-down the assets to fair value. The impairment charge was included in the statement of operations' line item impairment of natural gas and crude oil properties. Late in the fourth quarter, subsequent to the impairment charge, we reversed our decision to divest the assets and the assets were reclassified as held and used as of December 31, 2011. The subsequent decision not to divest the NECO assets did not result in any further write-downs of the related net assets. See Note 13. +68 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +In May 2010, pursuant to our entry into an agreement to sell our Michigan assets, we reclassified our Michigan assets as held for sale. We compared the transactional sales price, considered a Level 3 input, less costs to sell to the carrying value of our Michigan net assets. The net carrying value exceeded the net sales price and, therefore, during the second quarter of 2010, we recognized an impairment charge of $4.7 million to reduce the carrying value of the net assets to reflect the net sales price. The impairment charge was included in discontinued operations on the statement of operations. See Note 13. +Unproved Property Impairment. The acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense when expired, impaired or amortized. Unproved natural gas and crude oil properties with individually significant acquisition costs are periodically assessed for impairment. Unproved natural gas and crude oil properties which are not individually significant are amortized, by field, based on our historical experience, acquisition dates and average lease terms. Impairment and amortization charges related to unproved natural gas and crude oil properties are charged to the statement of operations' line item impairment of natural gas and crude oil properties. +Other Property and Equipment. The following table presents the estimated useful lives of our other property and equipment. +Pipelines and related facilities +10 - 17 years +Transportation and other equipment +3 - 20 years +Buildings +30 - 40 years +Other property and equipment are carried at cost. Depreciation is provided principally on the straight-line method over the assets estimated useful lives. We review these long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying +amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds our estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. No impairment was recognized in 2011. Impairments recognized in 2010 and 2009 were immaterial. +Maintenance and repairs on other property and equipment are charged to expense as incurred. Major renewals and improvements are capitalized and depreciated over the remaining useful life of the asset. Upon the sale or other disposition of assets, the cost and related accumulated DD&A are removed from the accounts, the proceeds are applied thereto and any resulting gain or loss is reflected in income. Total depreciation expense related to other property and equipment was $6.7 million, $7.5 million and $8.1 million in 2011 , 2010 and 2009, respectively. +Capitalized Interest. Interest costs are capitalized as part of the historical cost of acquiring assets. Investments in unproved natural gas and crude oil properties and major development projects, on which DD&A is not currently recorded and on which exploration or development activities are in progress, qualify for capitalization of interest. Major construction projects also qualify for interest capitalization until the asset is ready for service. Capitalized interest is calculated by multiplying our weighted-average interest rate on our debt outstanding by the qualifying costs. Interest capitalized may not exceed gross interest expense for the period. As the qualifying asset is moved to the DD&A pool, the related capitalized interest is also transferred and is amortized over the useful life of the asset. Capitalized interest totaled $1.7 million, $0.3 million and $0.8 million in 2011 , 2010 and 2009, respectively. +Assets Held for Sale. Assets held for sale are valued at the lower of their carrying amount or estimated fair value less costs to sell. If the carrying amount of the assets exceed their estimated fair value, an impairment loss is recognized. Fair values are estimated using accepted valuation techniques such as a discounted cash flow model, valuations performed by third parties, earnings multiples or indicative bids, when available. Management considers historical experience and all available information at the time the estimates are made; however, the fair values that are ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial statements. Depreciation, depletion, and amortization expense is not recorded on assets to be divested once they are classified as held for sale. +Assets to be divested are classified in the consolidated financial statements as held for sale, and the activities of assets to be divested are classified either as discontinued operations or continuing operations. For assets classified as discontinued operations, the balance sheet amounts and results of operations are reclassified from their historical presentation to assets and liabilities held for sale on the consolidated balance sheets and to discontinued operations on the consolidated statements of operations, respectively, for all periods presented. The gains or losses associated with these divested assets are recorded in discontinued operations on the consolidated statements of operations. Management does not expect any continuing involvement with businesses classified as discontinued operations following their divestiture. Businesses classified as held for sale are expected to be disposed of within one year. For businesses classified as held for sale that do not qualify for discontinued operations treatment, the balance sheet amounts are reclassified from their historical presentation to assets and liabilities held for sale for all periods presented. The results of operations continue to be reported in continuing operations. +Production Tax Liability. Production tax liability represents estimated taxes, primarily severance, ad valorem and property, to be paid to the states and counties in which we produce natural gas, NGLs and crude oil, including the production of our affiliated partnerships. Our share of these taxes is expensed to production costs. The partnerships' share, not owned by us, is recognized as a receivable in accounts receivable affiliates on the balance sheets. The long-term portion of the production tax liability is included in other liabilities on the balance sheets, and was $19.4 million and $16.4 million in December 31, 2011 and 2010, respectively. +69 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Income Taxes. We account for income taxes under the asset and liability method. We recognize deferred tax assets and liabilities for the future tax consequences attributable to operating loss and future credit carryforwards, and differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. If we determine that it is more likely than not that some portion or all of the deferred tax assets will not be realized, we record a valuation allowance thereby reducing the deferred tax assets to what we consider realizable. As of December 31, 2011 and 2010, we had no valuation allowance. +Debt Issuance Costs. Debt issuance costs are capitalized and amortized over the life of the respective borrowings using the effective interest method. As of December 31, 2011 and 2010, included in other assets was $12.3 million and $14.6 million, respectively, related to debt issuance costs. The December 31, 2011, amount included $2.4 million in costs related to the issuance of our 3.25% convertible senior notes due 2016, $3.4 million related to our 12% senior notes due 2018 and $6.5 million related to our bank credit facilities. +Asset Retirement Obligations. We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the well is completely drilled. Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the long-lived asset by the same amount as the liability. Over time, the liabilities are accreted for the change in their present value, through charges to production costs. The initial capitalized costs, net of salvage value, are depleted over the useful lives of the related assets, through charges to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from changes in retirement costs or the estimated timing of settling asset retirement obligations. See Note 9 for a reconciliation of the changes in our asset retirement obligation from January 1, 2010, to December 31, 2011 . +Treasury Shares. We record treasury share purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as reductions in shareholders’ equity in the consolidated balance sheets. When we retire treasury shares, we charge any excess of cost over the par value entirely to additional paid-in-capital, to the extent we have amounts in additional paid-in-capital, with any remaining excess cost being charged to retained earnings. +Revenue Recognition. Significant accounting polices related to our revenue recognition are discussed below. +Natural gas, NGL and crude oil sales. Natural gas, NGL and crude oil revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. We currently use the "net-back" method of accounting for transportation and processing arrangements of our sales when the transportation and/or processing is provided by or through the purchaser. Under these arrangements, we sell gas at the wellhead and collect a price and recognize revenues based on the wellhead sales price since transportation and processing costs downstream of the wellhead are incurred by the purchasers and reflected in the wellhead price. The majority of our natural gas and NGLs in Colorado are sold on a long-term basis ranging from 15 years to the life of the lease. Sales of natural gas and NGLs in other regions, along with crude oil, are sold under contracts with terms ranging from one month to three years. Virtually all of our contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the natural gas and prevailing supply and demand conditions. +Well operations and pipeline income . We are paid a monthly operating fee for each well we operate and the natural gas transported for outside owners including the limited partnerships we sponsored. Well operations and pipeline income is recognized when persuasive evidence of an arrangement exists, services have been rendered, collection of revenues is reasonably assured and the sales price is fixed or determinable. +Natural gas marketing. Natural gas marketing is reported on the gross method of accounting, based on the nature of the agreements between Riley Natural Gas ("RNG"), our suppliers and our customers. RNG, our marketing subsidiary, purchases gas from many small producers and bundles the gas together to sell in larger amounts to purchasers of natural gas for a price advantage. RNG has latitude in establishing price and discretion in supplier and purchaser selection. Natural gas marketing revenues and expenses reflect the full cost and revenue of those transactions because RNG takes title to the gas it purchases from the various producers and bears the risks and rewards of that ownership. Both the realized and unrealized gains and losses of the RNG commodity-based derivative transactions for natural gas marketing are included in sales from or cost of natural gas marketing, as applicable. +Stock-Based Compensation. Stock-based compensation is recognized in our financial statements based on the fair value, on the date of grant or modification, of the equity instrument awarded. Stock-based compensation expense is recognized in the financial statements on a straight-line basis over the vesting period for the entire award. To the extent compensation cost relates to employees directly involved in natural gas and crude oil exploration and development activities, such amounts may be capitalized to properties and equipment. Amounts not capitalized to properties and equipment are recognized in the related cost and expense line item in the statement of operations. No amounts for stock-based compensation were capitalized in 2011 , 2010 or 2009. +Earnings Per Share. Basic earnings (loss) per common share ("EPS") is computed by dividing net income (loss), the numerator, by the weighted-average number of common shares outstanding for the period, the denominator. Diluted EPS is similarly computed except that the +70 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +denominator includes the effect, using the treasury stock method, of our unamortized portion of restricted stock, outstanding stock appreciation rights ("SARs"), stock options, convertible notes and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive. +The following table presents a reconciliation of the weighted average diluted shares outstanding. +Year Ended December 31, +2011 +2010 +2009 +(in thousands) +Weighted average common shares outstanding - basic +23,521 +19,674 +16,448 +Dilutive effect of share-based compensation: +Restricted stock +307 +119 +— +SARs +40 +21 +— +Non employee director deferred compensation +3 +7 +— +Weighted average common and common share equivalents outstanding - diluted +23,871 +19,821 +16,448 +For 2009, the weighted average common shares outstanding for both basic and diluted were the same, as the effect of dilutive securities were anti-dilutive due to our net loss. The following table presents the weighted average common share equivalents excluded from the calculation of diluted earnings (loss) per share due to their anti-dilutive effect. +Year Ended December 31, +2011 +2010 +2009 +(in thousands) +Weighted average common share equivalents excluded from diluted earnings +per share due to their anti-dilutive effect: +Restricted stock +220 +204 +284 +SARs +22 +— +— +Stock options +9 +10 +10 +Non employee director deferred compensation +— +— +8 +Total anti-dilutive common share equivalents +251 +214 +302 +In November 2010, we issued 115,000 convertible senior notes, $1,000 principal amount, that give the holders the right to convert the principal amount into 2.7 million common shares at a conversion price of $42.40 per share. These convertible notes could have a dilutive impact on our earnings per share if the average market share price exceeds the conversion price. The table above does not include those shares issuable upon conversion as the average share price of our common stock did not exceed the conversion price during the period. +Recent Accounting Standards. +The following standard was recently adopted: +Fair Value Measurements and Disclosures. In January 2010, the FASB issued changes related to fair value measurements requiring gross presentation of activities within the Level 3 roll forward, whereby entities must present separately information about purchases, sales, issuances and settlements. These changes were effective for our financial statements issued for annual reporting periods beginning after December 15, 2010. The adoption of this change did not have a material impact on our financial statements. +The following standards were recently issued: +Fair Value Measurement. On May 12, 2011, the FASB issued changes related to fair value measurement. The changes represent the converged guidance of the FASB and the International Accounting Standards Board ("IASB") on fair value measurement. Many of the changes eliminate unnecessary wording differences between International Financial Reporting Standards ("IFRS") and U.S. GAAP. The changes expand existing disclosure requirements for fair value measurements categorized in Level 3 by requiring (1) a quantitative disclosure of the unobservable inputs and assumptions used in the measurement, (2) a description of the valuation processes in place and (3) a narrative description of the sensitivity of the fair value to changes in unobservable inputs and the interrelationships between those inputs. In addition, the changes require the categorization by level in the fair value hierarchy of items that are not measured at fair value in the statement of financial position whose fair value must be disclosed. These changes are to be applied prospectively and are effective for public entities during interim and annual periods beginning after December 15, 2011. Early application is not permitted. With the exception of the disclosure requirements, the adoption of these changes is not expected to have a significant impact on our financial statements. +71 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Presentation of Comprehensive Income. On June 16, 2011, the FASB issued changes related to the presentation of comprehensive income. These changes eliminate the current option to report other comprehensive income and its components in the statement of changes in equity. These changes are intended to enhance comparability between entities that report under U.S. GAAP and those that report under IFRS, and to provide a more consistent method of presenting non-owner transactions that affect an entity's equity. An entity may elect to present items of net income and other comprehensive income in one continuous statement, referred to as the statement of comprehensive income, or in two separate, but consecutive, statements. Each component of net income and each component of other comprehensive income, together with totals for comprehensive income and its two parts, net income and other comprehensive income, would need to be displayed under either alternative. The statement(s) would need to be presented with equal prominence as the other primary financial statements. The new requirement is effective for public entities as of the beginning of a fiscal year that begins after December 15, 2011, and interim and annual periods thereafter. Early adoption is permitted, but full retrospective application is required under both sets of accounting standards. We do not expect the adoption of these changes to have a material impact on our financial statements. +NOTE 3 - FAIR VALUE OF FINANCIAL INSTRUMENTS +Derivative Financial Instruments +Determination of fair value. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as: +Level 1 – Quoted prices (unadjusted) in active markets for identical assets or liabilities. +Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including (i) quoted prices for similar assets or liabilities in active markets, (ii) quoted prices for identical or similar assets or liabilities in inactive markets, (iii) inputs other than quoted prices that are observable for the asset or liability and (iv) inputs that are derived from observable market data by correlation or other means. Includes our fixed-price swaps, basis swaps and physical purchases. +Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Includes our natural gas and crude oil collars, crude oil puts and physical sales. +Derivative Financial Instruments. We measure the fair value of our derivative instruments based on a pricing model that utilizes market-based inputs, including but not limited to the contractual price of the underlying position, current market prices, natural gas and crude oil forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of derivative liabilities and the effect of our counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position. +We validate our fair value measurement through (1) the review of counterparty statements and other supporting documentation, (2) the determination that the source of the inputs is valid, (3) the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and (4) monitoring changes in valuation methods and assumptions. While we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. While we believe our valuation method is appropriate and consistent with those used by other market participants, the use of a different methodology, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value. +We have evaluated the credit risk of the counterparties holding our derivative assets, which are primarily financial institutions who are also major lenders in our corporate credit facility agreement, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the impact of the nonperformance of our counterparties on the fair value of our derivative instruments is insignificant. +72 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents, for each hierarchy level, our assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis. +As of December 31, +2011 +2010 (a) +Significant other +observable +Inputs +(Level 2) +Significant +Unobservable +Inputs +(Level 3) +Total +Significant other +observable +Inputs +(Level 2) +Significant +Unobservable +Inputs +(Level 3) +Total +(in thousands) +Assets: +Commodity based derivatives +$ +76,104 +$ +25,837 +$ +101,941 +$ +72,880 +$ +14,426 +$ +87,306 +Basis protection derivative contracts +5 +38 +43 +10 +101 +111 +Total assets +76,109 +25,875 +101,984 +72,890 +14,527 +87,417 +Liabilities: +Commodity based derivatives +9,888 +3,768 +13,656 +16,304 +3,758 +20,062 +Basis protection derivative contracts +35,424 +— +35,424 +46,573 +7 +46,580 +Total liabilities +45,312 +3,768 +49,080 +62,877 +3,765 +66,642 +Net asset (liability) +$ +30,797 +$ +22,107 +$ +52,904 +$ +10,013 +$ +10,762 +$ +20,775 +__________ +(a) +We reclassified our NYMEX-based natural gas fixed-price swaps from Level 1 to Level 2 (decreasing the previously reported net asset in Level 1 by $64.1 million, with a corresponding increase in Level 2), Panhandle Eastern Pipeline ("PEPL") and Colorado Interstate Gas ("CIG") -based natural gas fixed-price swaps, crude oil fixed-price swaps, basis swaps and natural gas physical purchases from Level 3 to Level 2 (decreasing the previously reported net liability in Level 3 by $54.1 million, with a corresponding increase in Level 2). The amounts presented reflect these reclassifications and conform to current period presentation. +The following table presents a reconciliation of our Level 3 fair value measurements. +2011 +2010 (1) +2009 (1) +(in thousands) +Fair value, net asset beginning of year, January 1 +$ +10,762 +$ +15,048 +$ +51,229 +Changes in fair value included in statement of operations line item: +Commodity price risk management gain (loss), net +13,487 +11,591 +20,686 +Sales from natural gas marketing +114 +580 +(388 +) +Cost of natural gas marketing +— +23 +— +Changes in fair value included in balance sheet line item (2): +Accounts receivable affiliates +49 +231 +(10 +) +Accounts payable affiliates +(454 +) +(1,737 +) +(8,941 +) +Settlements included in statement of operations line items: +Commodity price risk management gain (loss), net +(1,712 +) +(14,467 +) +— +Sales from natural gas marketing +(139 +) +(484 +) +(47,469 +) +Cost of natural gas marketing +— +(23 +) +(59 +) +Fair value, net asset end of year, December 31 +$ +22,107 +$ +10,762 +$ +15,048 +Changes in unrealized gains (losses) relating to assets (liabilities) still held +as of December 31, 2011, included in statement of operations line item: +Commodity price risk management gain (loss), net +$ +11,669 +$ +9,594 +$ +2,614 +Sales from natural gas marketing +(3 +) +54 +29 +$ +11,666 +$ +9,648 +$ +2,643 +__________ +(1) +We reclassified our PEPL and CIG-based natural gas fixed-price swaps, crude oil fixed-price swaps, basis swaps and natural gas physical purchases from Level 3 to Level 2 (decreasing the reported net liability at the beginning of 2010 by $44 million and the reported net asset at the beginning of 2009 by $83.6 million). The amounts presented reflect these reclassifications and conform to current period presentation. +(2) +Represents the change in fair value related to derivative instruments entered into by us and designated to our affiliated partnerships. +See Note 4 for additional disclosure related to our derivative financial instruments. +73 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Non-Derivative Financial Assets and Liabilities +The carrying values of the financial instruments comprising current assets and current liabilities approximate fair value due to the short-term maturities of these instruments. +The portion of our long-term debt related to our credit facility approximates fair value due to the variable nature of its related interest rate. We have not elected to account for the portion of our long-term debt related to our senior notes under the fair value option; however, as of December 31, 2011, we estimate the fair value of the portion of our long-term debt related to the 3.25% convertible senior notes due 2016 to be $123.8 million or 107.7% of par value and the portion related to our 12% senior notes due 2018 to be $222.3 million or 109.5% of par value. We determined these valuations based upon measurements of trading activity and broker and/or dealer quotes, respectively. +See Note 2, subsections Property and Equipment, Natural Gas and Crude Oil Properties and Asset Retirement Obligations for a discussion of how we determined fair value for these assets and liabilities. +NOTE 4 - DERIVATIVE FINANCIAL INSTRUMENTS +Our results of operations and operating cash flows are affected by changes in market prices for natural gas and crude oil. To manage a portion of our exposure to price volatility from producing natural gas and crude oil, we utilize the following economic hedging strategies for each of our business segments. +• +For natural gas and crude oil sales, we enter into derivative contracts to protect against price declines in future periods. While we structure these derivatives to reduce our exposure to changes in price associated with the derivative commodity, they also limit the benefit we might otherwise have received from price increases in the physical market. +• +For natural gas marketing, we enter into fixed-price physical purchase and sale agreements that qualify as derivative contracts. In order to offset the fixed-price physical derivatives in our natural gas marketing, we enter into financial derivative instruments that have the effect of locking in the prices we will receive or pay for the same volumes and period, offsetting the physical derivative. +We believe our derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. As of December 31, 2011 , we had derivative instruments in place for a portion of our anticipated production through 2015 for a total of 44,215 BBtu of natural gas and 2,540 MBbls of crude oil. +As of December 31, 2011 , our derivative instruments were comprised of commodity floors, collars and swaps, basis protection swaps and physical sales and purchases. +• +Floor options (puts) are arrangements where, if the index price falls below the fixed put strike price, we receive the market price from the purchaser and receive the difference between the put strike price and index price from the counterparty. If the index price exceeds the fixed put strike price, then no payment is due from us to the counterparty. +• +Collars contain a fixed floor price and ceiling price (call). If the index price falls below the fixed put strike price, we receive the market price from the purchaser and receive the difference between the put strike price and index price from the counterparty. If the index price exceeds the fixed call strike price, we receive the market price from the purchaser and pay the difference between the call strike price and index price to the counterparty. If the index price is between the put and call strike price, no payments are due to or from the counterparty. +• +Swaps are arrangements that guarantee a fixed price. If the index price is below the fixed contract price, we receive the market price from the purchaser and receive the difference between the index price and the fixed contract price from the counterparty. If the index price is above the fixed contract price, we receive the market price from the purchaser and pay the difference between the index price and the fixed contract price to the counterparty. If the index price and contract price are the same, no payment is due to or from the counterparty. +• +Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point. For CIG-basis protection swaps, which have negative differentials to NYMEX, we receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract. If the market price and contract price are the same, no payment is due to or from the counterparty. +• +Physical sales and purchases are derivatives for fixed-priced physical transactions where we sell or purchase third party supply at fixed rates. These physical derivatives are offset by financial swaps: for a physical sale the offset is a swap purchase and for a physical purchase the offset is a swap sale. +74 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the location and fair value amounts of our derivative instruments on the balance sheets as of December 31, 2011 and 2010. +Fair Value As of December 31, +Derivatives instruments not designated as hedges (1): +Balance sheet line item +2011 +2010 +(in thousands) +Derivative assets: +Current +Commodity contracts +Related to natural gas and crude oil sales +Fair value of derivatives +$ +51,220 +$ +32,837 +Related to affiliated partnerships (2) +Fair value of derivatives +8,018 +8,231 +Related to natural gas marketing +Fair value of derivatives +1,528 +1,811 +Basis protection contracts +Related to natural gas marketing +Fair value of derivatives +43 +74 +60,809 +42,953 +Non Current +Commodity contracts +Related to natural gas and crude oil sales +Fair value of derivatives +34,938 +32,270 +Related to affiliated partnerships (2) +Fair value of derivatives +6,134 +12,111 +Related to natural gas marketing +Fair value of derivatives +103 +46 +Basis protection contracts +Related to natural gas marketing +Fair value of derivatives +— +37 +41,175 +44,464 +Total derivative assets +$ +101,984 +$ +87,417 +Derivative liabilities: +Current +Commodity contracts +Related to natural gas and crude oil sales +Fair value of derivatives +$ +7,498 +$ +10,636 +Related to affiliated partnerships (3) +Fair value of derivatives +211 +1,676 +Related to natural gas marketing +Fair value of derivatives +1,384 +1,492 +Basis protection contracts +Related to natural gas and crude oil sales +Fair value of derivatives +15,762 +11,725 +Related to affiliated partnerships (3) +Fair value of derivatives +3,116 +4,462 +Related to natural gas marketing +Fair value of derivatives +3 +7 +27,974 +29,998 +Non Current +Commodity contracts +Related to natural gas and crude oil sales +Fair value of derivatives +4,357 +6,231 +Related to affiliated partnerships (3) +Fair value of derivatives +113 +(3 +) +Related to natural gas marketing +Fair value of derivatives +93 +30 +Basis protection contracts +Related to natural gas and crude oil sales +Fair value of derivatives +13,820 +21,905 +Related to affiliated partnerships (3) +Fair value of derivatives +2,723 +8,481 +21,106 +36,644 +Total derivative liabilities +$ +49,080 +$ +66,642 +__________ +(1) +As of December 31, 2011 , and December 31, 2010, none of our derivative instruments were designated as hedges. +(2) +Represents derivative positions designated to our affiliated partnerships; accordingly, our accompanying balance sheets include a corresponding payable to our affiliated partnerships representing their proportionate share of the derivative assets. +(3) +Represents derivative positions designated to our affiliated partnerships; accordingly, our accompanying balance sheets include a corresponding receivable from our affiliated partnerships representing their proportionate share of the derivative liabilities. +75 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the impact of our derivative instruments on our statements of operations. +Year Ended December 31, +2011 +2010 +2009 +Statement of operations line item +Reclassification +of Realized +Gains (Losses) +Included in Prior Periods +Unrealized +Realized and Unrealized +Gains +(Losses) For +the +Current +Period +Total +Reclassification +of Realized +Gains (Losses) +Included in Prior Periods +Unrealized +Realized and Unrealized +Gains +(Losses) For +the +Current +Period +Total +Reclassification +of Realized +Gains (Losses) +Included in Prior Periods +Unrealized +Realized and Unrealized +Gains +(Losses) For +the +Current +Period +Total +(in thousands) +Commodity price risk management gain (loss), net +Realized gains +$ +10,329 +$ +6,914 +$ +17,243 +$ +20,148 +$ +26,947 +$ +47,095 +$ +84,655 +$ +22,690 +$ +107,345 +Unrealized gains (losses) +(10,329 +) +39,176 +28,847 +(20,148 +) +32,944 +12,796 +(84,655 +) +(32,743 +) +(117,398 +) +Total commodity price risk management gain (loss), net +$ +— +$ +46,090 +$ +46,090 +$ +— +$ +59,891 +$ +59,891 +$ +— +$ +(10,053 +) +$ +(10,053 +) +Sales from natural gas marketing +Realized gains +$ +1,827 +$ +1,143 +$ +2,970 +$ +2,390 +$ +3,991 +$ +6,381 +$ +4,798 +$ +3,744 +$ +8,542 +Unrealized gains (losses) +(1,827 +) +1,666 +(161 +) +(2,390 +) +1,745 +(645 +) +(4,798 +) +1,295 +(3,503 +) +Total sales from natural gas marketing +$ +— +$ +2,809 +$ +2,809 +$ +— +$ +5,736 +$ +5,736 +$ +— +$ +5,039 +$ +5,039 +Cost of natural gas marketing +Realized losses +$ +(1,441 +) +$ +(1,130 +) +$ +(2,571 +) +$ +(1,905 +) +$ +(3,996 +) +$ +(5,901 +) +$ +(4,719 +) +$ +(4,127 +) +$ +(8,846 +) +Unrealized gains (losses) +1,441 +(1,526 +) +(85 +) +1,905 +(1,431 +) +474 +4,719 +(441 +) +4,278 +Total cost of natural gas marketing +$ +— +$ +(2,656 +) +$ +(2,656 +) +$ +— +$ +(5,427 +) +$ +(5,427 +) +$ +— +$ +(4,568 +) +$ +(4,568 +) +NOTE 5 - CONCENTRATION OF RISK +Accounts Receivable. The following table presents the components of accounts receivable, net. +As of December 31, +2011 +2010 +(in thousands) +Natural gas, NGL and crude oil sales +$ +42,388 +$ +27,730 +Joint interest billings +7,465 +12,142 +Natural gas marketing +6,225 +8,279 +Other +4,766 +6,513 +Allowance for doubtful accounts +(921 +) +(686 +) +Accounts receivable, net +$ +59,923 +$ +53,978 +Our accounts receivable are primarily from purchasers of our natural gas, NGL and crude oil production, derivative counterparties and other third parties which own working interests in the properties that we operate. Inherent to our industry is the concentration of natural gas, NGL and crude oil sales to a few customers. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions. We record an allowance for doubtful accounts for receivables that we estimate to be uncollectible. In making our +estimate, we consider, among other things, our historical write-offs and overall creditworthiness of our customers. Further, consideration is given to well production data for receivables related to well operations. It is reasonably possible that our estimate of uncollectible amounts will change periodically. For the each of the years in the three-year period ended December 31, 2011, amounts written off to allowance for doubtful accounts were not material. As of December 31, 2011 , we had one customer representing 10% or greater of our accounts receivable balance, Suncor Energy Marketing, Inc., which represented 16% of our accounts receivable balance. +76 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Major Customers. The following table presents the individual customers constituting 10% or more of total revenues. +Year Ended December 31, +Customer +2011 +2010 +2009 +Suncor Energy Marketing, Inc. +25.7 +% +19.6 +% +18.6 +% +Williams Production RMT Company +9.9 +% +12.5 +% +16.1 +% +DCP Midstream, LP +11.5 +% +9.6 +% +11.9 +% +Derivative Counterparties. A significant portion of our liquidity is concentrated in derivative instruments that enable us to manage a portion of our exposure to price volatility from producing natural gas and crude oil. These arrangements expose us to credit risk of nonperformance by our counterparties. We primarily use financial institutions, who are also major lenders in our credit facility agreement, as counterparties to our derivative contracts. To date, we have had no counterparty default losses. We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, the impact of the nonperformance of our counterparties on the fair value of our derivative instruments is not significant. +The following table presents the counterparties that expose us to credit risk as of December 31, 2011 , with regard to our derivative assets. +Fair Value of +Derivative Assets +Counterparty Name +As of December 31, 2011 +(in thousands) +JPMorgan Chase Bank, N.A. (1) +$ +48,855 +Crèdit Agricole CIB (1) +21,597 +Wells Fargo Bank, N.A. (1) +20,519 +Various (2) +11,013 +Total +$ +101,984 +________________________ +(1) Major lender in our credit facility, see Note 8. +(2) Represents a total of 14 counterparties, including three lenders in our credit facility. +NOTE 6 - PROPERTIES AND EQUIPMENT +As of December 31, +2011 +2010 +(in thousands) +Properties and equipment, net: +Natural gas and crude oil properties +Proved +$ +1,694,694 +$ +1,362,491 +Unproved +102,466 +33,740 +Total natural gas and crude oil properties +1,797,160 +1,396,231 +Pipelines and related facilities +40,721 +34,262 +Transportation and other equipment +32,475 +32,382 +Land and buildings +14,572 +13,379 +Construction in progress +69,633 +42,128 +1,954,561 +1,518,382 +Accumulated DD&A +(652,845 +) +(509,712 +) +Properties and equipment, net +$ +1,301,716 +$ +1,008,670 +77 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Suspended Well Costs +The following table presents the capitalized exploratory well costs pending determination of proved reserves and included in properties and equipment on the balance sheets. +2011 +2010 +2009 +(in thousands, except for number of wells) +Balance beginning of year, January 1 +$ +2,297 +$ +1,174 +$ +1,180 +Deconsolidation of PDCM and change in ownership interest +— +(462 +) +— +Additions to capitalized exploratory well costs +pending the determination of proved reserves +3,692 +4,353 +10,226 +Reclassifications to wells, facilities and equipment +based on the determination of proved reserves +(1,557 +) +(2,231 +) +(9,914 +) +Capitalized exploratory well costs charged to expense +— +(537 +) +(318 +) +Balance end of year, December 31 +$ +4,432 +$ +2,297 +$ +1,174 +Number of wells pending determination at December 31 +6 +3 +2 +As of December 31, 2011 , there were two wells pending determination of proved reserves that had been capitalized for a period greater than one year after the completion of drilling. One well, located in the Wattenberg Field, has been utilized as a monitoring well in the early stages of our horizontal Niobrara program and will be tested in several zones during 2012, since the monitoring process has been completed. The second well, located in the Appalachian Basin, is expected to be tested in 2012 when feasible. Total capitalized costs related to these wells were $0.5 million and $0.6 million as of December 31, 2011, respectively. There were no exploratory well costs that were capitalized for a period greater than one year after the completion of drilling as of December 31, 2010 and 2009. +NOTE 7 - INCOME TAXES +The table below presents the components of tax expense (benefit) from continuing operations for the years presented. +Year Ended December 31, +2011 +2010 +2009 +(in thousands) +Current: +Federal +$ +(3,172 +) +$ +(1,616 +) +$ +(29,071 +) +State +(172 +) +904 +312 +Total current income taxes +(3,344 +) +(712 +) +(28,759 +) +Deferred: +Federal +2,868 +3,990 +(11,546 +) +State +293 +(2,626 +) +(4,749 +) +Total deferred income taxes +3,161 +1,364 +(16,295 +) +Income tax provision (benefit) from continuing operations +$ +(183 +) +$ +652 +$ +(45,054 +) +For 2011, we plan to utilize statutory 100% bonus depreciation and not to expense any intangible drilling costs ("IDC"). For 2010 and 2009, we elected to expense approximately $8.5 million and $80 million, respectively, of IDC. We also continued to utilize other tax deferral strategies such as statutory bonus and accelerated depreciation, special partnership formation statutes and regulations and Internal Revenue Code ("IRC") Section 1031 like-kind exchange ("LKE") strategies to reduce our current tax expense, resulting in a correspondingly higher deferred tax expense. As a result of these elections and deferral strategies, we have generated federal and state tax net operating losses (“NOLs”) in 2011, 2010 and 2009. The 2010 NOL was carried back to 2008 generating a refund of $4.6 million, which was received in the fourth quarter of 2011. This benefit is reflected in the 2010 current federal provision. Our 2011 federal NOL is being carried forward to 2012 and is expected to provide a $11.7 million tax benefit as an offset to 2012 taxable income. This benefit is reflected in the 2011 deferred federal provision. The Worker, Homeownership, and Business Assistance Act of 2009 increased the statutory carry-back from two years to five years for losses incurred in 2008 and 2009. We carried back our 2009 tax loss to the 2005 and 2006 tax years, generating a refund of $25.9 million, which was received in the second quarter of 2010. The benefit is reflected in the 2009 current federal provision. Our state NOLs from the years ended 2011, 2010 and 2009 were statutorily not permitted to be “carried back” in the majority of our state taxing jurisdictions. These state NOLs provide a deferred tax benefit and are noted below in the table of deferred tax assets and liabilities. +78 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents a reconciliation of the statutory rate to the effective tax rate related to income from continuing operations. +Year Ended December, 31, +2011 +2010 +2009 +Statutory tax rate +35.0 +% +35.0 +% +35.0 +% +State income tax, net +(9.4 +) +1.3 +3.3 +Percentage depletion +(29.5 +) +(11.3 +) +0.5 +Non-deductible compensation +— +4.4 +0.1 +Non-deductible meals and entertainment +3.1 +— +— +State deferred rate change +15.4 +(26.2 +) +(0.9 +) +Unrecognized tax benefits +(30.3 +) +2.4 +0.7 +State tax credits +— +(3.3 +) +0.3 +2007-2009 federal return examination adjustments +4.2 +4.7 +— +2010 return to provision adjustments +3.7 +— +— +Non-deductible expenditures - PDCM +— +— +(1.8 +) +Other +1.5 +2.7 +(1.2 +) +Effective tax rate +(6.3 +)% +9.7 +% +36.0 +% +The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2011 and 2010, are presented below. +As of December 31, +2011 +2010 +(in thousands) +Deferred tax assets: +Provision for underpayment of natural gas sales +$ +3,334 +$ +2,711 +Deferred compensation +4,319 +3,986 +Asset retirement obligations +9,438 +6,716 +State NOL and tax credit carryforwards, net +5,240 +4,624 +Percentage depletion - carryforward +3,733 +2,422 +Alternative minimum tax - credit carryforward +2,351 +2,069 +Federal NOL carryforward +12,210 +— +Other +2,621 +2,247 +Total gross deferred tax assets +43,246 +24,775 +Deferred tax assets +43,246 +24,775 +Deferred tax liabilities: +Properties and equipment +(184,657 +) +(164,586 +) +Investment in PDCM +(30,919 +) +(31,149 +) +Unrealized gains - derivatives +(12,612 +) +(3,082 +) +Convertible debt +(6,504 +) +(7,873 +) +Total gross deferred tax liabilities +(234,692 +) +(206,690 +) +Net deferred tax liability +$ +(191,446 +) +$ +(181,915 +) +Classification in the balance sheets: +Prepaid expenses and other current assets +$ +16,127 +$ +6,084 +Deferred income taxes +(207,573 +) +(187,999 +) +Net deferred tax liability +$ +(191,446 +) +$ +(181,915 +) +Deferred tax liabilities for properties and equipment increased in 2011, primarily as a result of our continued utilization of statutory provisions for bonus and accelerated tax depreciation. +As of December 31, 2011, we have state NOL carryforwards of $124.1 million that begin to expire in 2029, state credit carryforwards of $1.3 million that begin to expire in 2020 and federal NOL carryforwards of $34.9 million that will expire in 2030. +79 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents a reconciliation of the total amounts of unrecognized tax benefits. +2011 +2010 +2009 +(in thousands) +Balance beginning of year, January 1 +$ +1,093 +$ +566 +$ +1,271 +Additions for tax positions of prior years +— +253 +43 +Additions for tax positions of current year +— +274 +7 +Reductions due to settlements +(782 +) +— +(406 +) +Reductions due to lapse of statute of limitations +(132 +) +— +(349 +) +Balance end of year, December 31 +$ +179 +$ +1,093 +$ +566 +Interest and penalties related to uncertain tax positions are recognized in income tax expense. Accrued interest and penalties related to uncertain tax positions were immaterial for each of the years in the three-year period ended December 31, 2011. The total amount of unrecognized tax benefits that would affect the effective tax rate, if recognized, was $0.2 million as of December 31, 2011 and $1 million as of December 31, 2010. As of December 31, 2011, we do not expect a decrease in the unrecognized tax benefit in the next twelve months. +In June 2011, the Internal Revenue Service ("IRS") completed its examination of our 2007, 2008 and 2009 tax years. In addition, in accordance with the Compliance Assurance Process ("CAP"), the IRS completed its “post filing review” of our 2010 tax return and have issued a “no change” letter. The CAP audit employs a real-time review of our books and tax records by the IRS that is intended to permit issue resolution prior to, or shortly after, the filing of the tax returns. During the twelve months ended 2011, we reduced our liability by $0.8 million for uncertain tax benefits that were resolved. The statute of limitation for most of our state tax jurisdictions is open from 2007 forward. +NOTE 8 - LONG-TERM DEBT +Long-term debt consists of the following: +As of December 31, +2011 +2010 +(in thousands) +Senior notes +3.25% Convertible senior notes due 2016: +Principal amount +$ +115,000 +$ +115,000 +Unamortized discount +(17,079 +) +(20,252 +) +3.25% Convertible senior notes due 2016, net of discount +97,921 +94,748 +12% Senior notes due 2018: +Principal amount +203,000 +203,000 +Unamortized discount +(1,764 +) +(2,053 +) +12% Senior notes due 2018, net of discount +201,236 +200,947 +Total senior notes +299,157 +295,695 +Credit facilities +Corporate +209,000 +— +PDCM +24,000 +— +Total credit facilities +233,000 +— +Total long-term debt +$ +532,157 +$ +295,695 +Senior Notes +3.25% Convertible Senior Notes Due 2016. In November 2010, we issued $115 million of 3.25% convertible senior notes due 2016 in a private placement to qualified institutional buyers. The convertible notes and the common stock issuable upon conversion of the convertible notes, if any, have not been registered under the Securities Act of 1933 ("Securities Act") or any state securities laws, nor are we required to register such convertible notes or common shares. The convertible notes are governed by an indenture dated November 23, 2010, between the Company and the Bank of New York Mellon, as trustee. The maturity for the payment of principal is May 15, 2016. Interest at the rate of 3.25% per year is payable in cash semiannually in arrears on each May 15 and November 15, commencing on May 15, 2011. The +80 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +convertible notes are senior, unsecured obligations and rank senior in right of payment to our existing and future indebtedness that is expressly subordinated in right of payment to the convertible notes; equal in right of payment to our existing and future unsecured indebtedness that is not so subordinated (including our 12% senior notes due 2018); effectively junior in right of payment to any of our secured indebtedness (including our obligations under our senior secured credit facility) to the extent of the value of the assets securing such indebtedness; and structurally junior to all existing and future indebtedness (including trade payables) incurred by our subsidiaries. The indenture governing the convertible notes does not contain any restrictive financial covenants. +We may not redeem the convertible notes prior to the maturity date of the convertible notes. However, prior to November 15, 2015, holders of the convertible notes may convert upon specified events and periods as defined in the governing indenture. The notes are convertible at any time thereafter at an initial conversion rate of 23.5849 per $1,000 principal amount of the convertible notes, which is equal to a conversion price of approximately $42.40 per share. The conversion rate is subject to adjustment upon certain events. Upon conversion, the convertible notes may be settled, at our election, in shares of our common stock, cash or a combination of cash and shares of our common stock. We have initially elected a net-settlement method to satisfy our conversion obligation, which allows us to settle the $1,000 principal amount of the convertible notes in cash and to settle the excess conversion value in shares, as well as cash in lieu of fractional shares. +We allocated the gross proceeds of the convertible notes between the liability and equity components of the debt. The initial $94.3 million liability component was determined based on the fair value of similar debt instruments with similar terms, excluding the conversion feature, and priced on the same day we issued our convertible notes. The initial $20.7 million equity component represents the debt discount and was calculated as the difference between the liability component of the debt and the gross proceeds of the convertible notes. As of December 31, 2011, the unamortized debt discount will be amortized over the remaining contractual term to maturity of the convertible notes of 4.4 years using an effective interest rate of 7.4%. For 2011, interest expense related to the indebtedness and the amortization of the discount were $3.7 million and $3.2 million, respectively, compared to $0.4 million and $0.5 million, respectively, in 2010. As of December 31, 2011 and 2010, notwithstanding the inability to convert, assuming conversion, the value of the convertible notes did not exceed the principal amount. +12% Senior Notes Due 2018. In 2008, we issued $203 million of 12% senior notes due 2018 in a private placement. The notes have not been registered under the Securities Act or any state securities laws, nor are we required to register such notes. The notes are governed by an indenture dated February 8, 2008, between the Company and the Bank of New York, as trustee, as supplemented by the first supplement indenture dated said date. The maturity for the payment of principal is February 15, 2018. Interest at the rate of 12% per year is payable in cash semiannually in arrears on each February 15 and August 15. The senior notes were issued at a discount, 98.572% of the principal amount. The notes are senior unsecured obligations and rank, in right of payment, equally with all of our existing and future senior unsecured indebtedness and senior to any of our existing and future subordinated indebtedness. The notes are effectively subordinated to any of our existing or future secured indebtedness to the extent of the assets securing such indebtedness. +The indenture governing the notes contains customary representations and warranties as well as typical restrictive covenants, with the most restrictive being two incurrence covenants: 1) earnings before interest, taxes, DD&A expense and capital expenditures ("EBITDAX") of at least two times interest expense and 2) total debt of less than 4.0 times EBITDAX. We were in compliance with all covenants as of December 31, 2011 , and expect to remain in compliance throughout the next year. +The indenture provides that we may, at our option, redeem all or part of the notes at any time prior to February 15, 2013, at the make-whole price set forth in the indenture, and on or after February 15, 2013, at fixed redemption prices, plus accrued and unpaid interest, if any, to the date of redemption. Further, the indenture provides that upon a change of control, we must give holders of the notes the opportunity to put their notes to us for repurchase at a repurchase price of 101% of the principal amount, plus accrued and unpaid interest. +Bank Credit Facilities +Corporate Credit Facility. We operate under a credit facility dated November 5, 2010, as amended last on October 12, 2011, with an aggregate revolving commitment or borrowing base of $400 million. The maximum allowable facility amount is $600 million. The credit facility is with certain commercial lending institutions and is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes, and to support letters of credit. +Our credit facility borrowing base is subject to size redetermination semiannually based on a quantification of our reserves at December 31 and June 30 and is also subject to a redetermination upon the occurrence of certain events. The borrowing base of the credit facility will be the loan value assigned to the proved reserves attributable to our and our subsidiaries’ natural gas and crude oil interests. The credit facility is secured by a pledge of the stock of certain of our subsidiaries, mortgages of certain producing natural gas and crude oil properties and substantially all of our and such subsidiaries’ other assets. Neither PDCM nor the various limited partnerships for which we have sponsored and continue to serve as the managing general partner are guarantors of the credit facility. +Our outstanding principal amount accrues interest at a varying interest rate that fluctuates with an alternate base rate (equal to the greater of JPMorgan Chase Bank, N.A.'s prime rate, the federal funds rate plus a premium and 1-month LIBOR plus a premium), or at our election, a rate equal to the rate for dollar deposits in the London interbank market for certain time periods. Additionally, commitment fees, interest margin and other bank fees, charged as a component of interest, vary with our utilization of the facility. No principal payments are required until the credit agreement expires on November 5, 2015, or in the event that the borrowing base would fall below the outstanding balance. We pay a fee of 0.5% per annum on the unutilized commitment on our available funds under our credit facility. +81 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests and maintaining certain financial ratios on a quarterly basis. The financial tests and ratios include requirements to: (a) maintain a minimum current ratio, as defined per credit facility, of 1.00 to 1.00 and (b) not exceed a maximum leverage ratio of 4.25 to 1.00 through December 31, 2011, and 4.00 to 1.00 thereafter. +The credit facility contains restrictions as to when we can directly or indirectly, retire, redeem, repurchase or prepay in cash, any part of the principal of the 12% Senior Notes Due 2018 or the 3.25% Convertible Senior Notes Due 2016. Among others, the restriction requires that immediately after giving effect to any such retirement, redemption, defeasance, repurchase, settlement or prepayment the aggregate commitment exceed the aggregate credit exposure by at least the greater of (1) $115 million or (2) an amount equal to or greater than 30% of the aggregate commitment. +We have outstanding an $18.7 million irrevocable standby letter of credit in favor of a third party transportation service provider to secure the construction of certain additions and/or replacements to its facilities to provide firm transportation of the natural gas produced by us and others for whom we market their production in the West Virginia and Southwestern Pennsylvania areas. The letter of credit reduces the amount of available funds under our credit facility by an equal amount. We pay a fronting fee of 0.125% per annum and an additional quarterly maintenance fee equivalent to the spread over Eurodollar loans (2.5% per annum as of December 31, 2011 ) for the period the letter of credit remains outstanding. The letter of credit expires on May 22, 2012. +As of December 31, 2011 , the available funds under our credit facility, including a reduction for the $18.7 million irrevocable standby letter of credit in effect, was $172.3 million. The weighted average borrowing rate on our credit facility, exclusive of the letter of credit, was 3.8% and 4.9% in 2011 and 2010, respectively. We were in compliance with all covenants at December 31, 2011 , and expect to remain in compliance throughout the next year. +PDCM Credit Facility. PDCM has a credit facility dated April 30, 2010, as amended last on November 18, 2011, with an aggregate revolving commitment or borrowing base of $80 million. The maximum allowable facility amount is $400 million. PDCM is required to pay a commitment fee of 0.5% per annum on the unutilized portion of the activated credit facility. Based upon PDCM's discretion, interest accrues at either an alternative base rate ("ABR") or an adjusted LIBOR. The ABR is the greater of BNP Paribas' prime rate, the federal funds effective rate plus 0.5% or the adjusted LIBOR for a three month interest period plus 1%. ABR and adjusted LIBOR borrowings are assessed an additional margin based upon the outstanding balance as a percentage of the available balance. ABR borrowings are assessed an additional margin of 1.0% to 1.75%. Adjusted LIBOR borrowings are assessed an additional margin spread of 2.0% to 2.75%. No principal payments are required until the credit agreement expires on April 30, 2014, or in the event that the borrowing base would fall below the outstanding balance. The credit facility is subject to and secured by PDCM's properties, with no recourse to us. The credit facility borrowing base is subject to size redetermination semiannually based upon a quantification of PDCM's reserves at December 31 and June 30; further, either PDCM or the lenders may request a redetermination upon the occurrence of certain events. Pursuant to the interests of the joint venture, the credit facility will be utilized by PDCM for the exploration and development of its Marcellus assets. +The credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests and maintaining certain financial ratios on a quarterly basis. The financial tests and ratios include requirements to: (a) maintain a minimum current ratio of 1.0 to 1.0, (b) not to exceed a debt to EBITDAX ratio of 4.0 to 1.0 and (c) maintain a minimum interest coverage ratio of 2.5 to 1.0. As of December 31, 2011, PDCM was in compliance with all bank credit facility covenants and expects to remain in compliance throughout the next twelve-month period. +NOTE 9 - ASSET RETIREMENT OBLIGATIONS +The following table presents the changes in carrying amounts of the asset retirement obligations associated with our working interest in natural gas and crude oil properties. +2011 +2010 +(in thousands) +Balance beginning of year, January 1 +$ +28,047 +$ +29,564 +Deconsolidation of PDCM and change in ownership interest +(916 +) +(6,564 +) +Obligations incurred with development activities and assumed with acquisitions +9,625 +4,549 +Accretion expense +1,897 +1,423 +Obligations discharged with disposal of properties and asset retirements +(990 +) +(925 +) +Revisions in estimated cash flows +8,903 +— +Balance end of year, December 31 (1) +46,566 +28,047 +Less current portion +(250 +) +(250 +) +Long-term portion +$ +46,316 +$ +27,797 +__________ +(1) +Includes $2 million and $2.6 million as of December 31, 2011 and 2010, respectively, related to assets held for sale. +82 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +In 2011, we revised our assumptions related to the cash outlay expected to be incurred to plug uneconomic wells. The revision in the asset retirement obligation did not have an immediate effect in the current year statement of operations, as the increase in the revised obligation will be accreted and the offsetting capitalized amount will be depreciated over the useful lives of respective wells. +NOTE 10 - EMPLOYEE BENEFIT PLANS +We sponsor a qualified retirement plan covering substantially all of our employees. The plan consists of both a traditional and a Roth 401(k) component as well as a profit sharing component. The 401(k) components enable eligible employees to contribute a portion of their compensation through payroll deductions in accordance with specific guidelines. We provide a discretionary matching contribution based on a percentage of the employees' contributions up to certain limits. Our contribution to the profit sharing component is discretionary. Our total combined expense for the plan for each of the years 2011 and 2010 was $2.6 million and for 2009 was $1.7 million. +We provide a supplemental retirement benefit of deferred compensation under terms of the various employment agreements with certain former executive officers. Expenses related to this plan are charged to general and administrative expenses, such expenses were immaterial in 2011, 2010 and 2009. As of December 31, 2011 and 2010, the liability related to this benefit was $2.2 million and $2.3 million, respectively, which was included in other liabilities on the balance sheets, with the exception of $0.3 million included in other accrued expenses as of December 31, 2011 and 2010. +We provide a supplemental health care benefit covering certain former executive officers and their spouses in accordance with each officer's employment agreement. Expenses incurred during 2011, 2010 and 2009 related to this plan were immaterial. As of December 31, 2011 and 2010, included in other liabilities on the balance sheets was a related liability of $0.7 million and $0.6 million, respectively. +We maintain a non-qualified deferred compensation plan for our non-employee directors. The amount of compensation deferred by each participant is based on participant elections. The amounts deferred pursuant to the plan are invested in our common stock, maintained in a rabbi trust and are classified in the balance sheets as treasury shares as a component of shareholders' equity. The plan may be settled in either cash or shares as requested by the participant. The liability related to this plan, which was included in other liabilities on the balance sheets, was immaterial as of December 31, 2011 and 2010. +NOTE 11 - COMMITMENTS AND CONTINGENCIES +Utica Shale Leasehold Agreements. During the third quarter of 2011, we entered into a series of leasehold agreements with multiple parties for the option to acquire acreage targeting the wet natural gas and crude oil phases of the Utica Shale play throughout southeastern Ohio. Pursuant to the agreements, we have the right, after confirmation of title, to acquire an estimated 30,000 net acres in the prospective Utica Shale play. Should we confirm title on all 30,000 acres, we estimate that the purchase price of these leaseholds will approximate $50 million. Further, during the fourth quarter of 2011, we entered into additional leasehold agreements giving us the opportunity to purchase an estimated additional 10,000 acres, subject to confirmation of title, for up to $20 million. +Drilling Rig Contracts. We enter into long-term contracts to secure the services of drilling rigs. As of December 31, 2011, we had outstanding commitments of $17.9 million, which included a $13.9 million commitment for a rig in the Permian Basin. Our Permian Basin Assets were subject to a purchase and sale agreement as of December 31, 2011. On February 28, 2012, the purchase and sale agreement was closed upon and, thereby, resulted in the assignment of our $13.9 million commitment to the purchaser of our Permian Basin assets. See Note 18. +Firm Transportation Agreements. We enter into contracts that provide firm transportation, sales and processing charges on pipeline systems through which we transport or sell our natural gas and the natural gas of working interest owners, PDCM, our affiliated partnerships and other third parties. These contracts require us to pay these transportation and processing charges whether the required volumes are delivered or not. Satisfaction of the volume requirements includes volumes produced by us, volumes purchased from third parties and volumes produced by PDCM and affiliated partnerships. We record in our financial statements only our share of costs based upon our working interest in the wells; however, with the exception of contracts entered into by PDCM, the costs of all volume shortfalls will be borne by PDC. +As of December 31, 2010, we had a liability in the amount of $3.1 million included in other liabilities on the balance sheet related to an agreement in the Piceance Basin. On July 27, 2011, we entered into an amendment with the unrelated third party subject to this agreement whereby the accrued liability was relieved; consequently, during the third quarter of 2011, the accrued liability was eliminated with a corresponding reduction in the statement of operations line item production costs. The amendment did not extend the expiration date of the original agreement. The table below includes the impact of this amendment. +83 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents gross volume information, including our proportionate share of PDCM, related to our long-term firm sales, processing and transportation agreements for pipeline capacity. +Year Ending December 31, +Area +2012 +2013 +2014 +2015 +2016 +Through +Expiration +Total +Expiration +Date +Volume (MMcf) +Piceance +18,000 +30,760 +36,168 +30,603 +111,948 +227,479 +May 31, 2021 +Appalachian Basin (1) +12,016 +20,117 +21,955 +23,361 +190,108 +267,557 +August 31, 2022 +NECO +3,650 +1,825 +1,825 +1,825 +1,825 +10,950 +December 31, 2016 +Total +33,666 +52,702 +59,948 +55,789 +303,881 +505,986 +Dollar commitment +(in thousands) +$ +15,318 +$ +25,597 +$ +28,805 +$ +26,164 +$ +127,353 +$ +223,237 +_____________ +(1) +Includes a precedent agreement that becomes effective when a planned pipeline is placed in service, currently expected to be September 2012 and represents 3,917 MMcf of the total MMcf presented for the year ending December 31, 2012, 10,992 MMcf for each of the years ending December 31, 2013 through 2015, respectively, and 73,028 MMcf thereafter. This agreement will be null and void if the pipeline is not completed. In August 2009, we issued a letter of credit related to this agreement, see Note 8. +Litigation. The Company is involved in various legal proceedings that it considers normal to its business. The Company reviews the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in the best interests of the Company. There are no assurances that settlements can be reached on acceptable terms or that adverse judgments, if any, in the remaining litigation will not exceed the amounts reserved. +Alleged Class Action Filed Regarding 2010 and 2011 Partnership Purchases +On December 21, 2011 the Company and its wholly-owned merger subsidiary were served with an alleged class action on behalf of certain former partnership unit holders, related to 11 partnership repurchases completed by mergers in 2010 and 2011. The action was filed in United States ("U.S.") District Court for the Central District of California, and is titled Schulein v. Petroleum Development Corp . The Company was managing general partner for each of these partnerships and the mergers were each approved by a majority of the partnership units held by non-affiliated investor partners. The complaint alleges a claim that the proxy statements issued in connection with the mergers were inadequate, and a state law breach of fiduciary duty claim. On February 10, 2012, the Company filed a motion to dismiss. We believe the suit is without merit and we intend to defend vigorously. +Royalty Owner Class Action +Gobel et al v. Petroleum Development Corporation, filed on January 27, 2009, in Circuit Court of Harrison County, CA No. 09-C-40-2 +David W. Gobel, individually and allegedly as representative of all royalty owners in the Company's West Virginia oil and gas wells, filed a lawsuit against the Company alleging that we failed to properly pay royalties. The allegations stated that the Company improperly deducted certain charges and costs before applying the royalty percentage. Punitive damages were requested in addition to breach of contract, tort and fraud allegations. On October 27, 2010, the state court set a trial date of April 2012. +In April 2011, the Company entered into an oral settlement agreement with respect to this lawsuit, settling all claims between the parties for an aggregate payment of $8.7 million. On June 15, 2011, subject to court approval, a written settlement agreement was signed confirming these terms. On June 30, 2011, the state court granted initial approval of the settlement agreement, subject to notice to class members and final court approval. Initial notice was then sent to the class members. The date for objection by class members was October 24, 2011, with no objections received. Final approval of the settlement was received in January 2012. As of December 31, 2011, the total settlement amount was included in other accrued expenses on the balance sheet with the related escrow account included in restricted cash - current on the balance sheet. +Environmental. Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures to avoid environmental contamination and mitigate the risks from environmental contamination. We conduct periodic reviews to identify changes in our environmental risk profile. Liabilities are accrued when environmental damages resulting from past events are probable and the costs can be reasonably estimated. As of December 31, 2011, and December 31, 2010, we had accrued environmental liabilities in the amount of $2.5 million and $1.7 million, respectively, included in other accrued expenses on the balance sheet. We are not aware of any environmental claims existing as of December 31, 2011, which have not been provided for or would otherwise have a material impact on our financial statements. However, there can be no assurance that current regulatory requirements will not change or unknown past non-compliance with environmental laws will not be discovered on our properties. +84 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Partnership Repurchase Provision. Substantially all of our drilling programs contain a repurchase provision where investing partners may request that we purchase their partnership units at any time beginning with the third anniversary of the first cash distribution. The provision provides that we are obligated to purchase an aggregate of 10% of the initial subscriptions per calendar year (at a minimum price of four times the most recent 12 months' cash distributions from production), if repurchase is requested by investors, subject to our financial ability to do so. As of December 31, 2011 , the maximum annual repurchase obligation for 2012, based upon the minimum price described above, was approximately $6.3 million. We believe we have adequate liquidity to meet this obligation. During 2011 , 2010 and 2009, we paid $0.2 million, $0.6 million and $1.7 million, respectively, under this provision for the repurchase of partnership units. +Lease Agreements. We entered into operating leases principally for the leasing of natural gas compressors, office space in Denver and Bridgeport, and general office equipment. The following table presents the minimum future lease payments under the non-cancelable operating leases as of December 31, 2011 . +Year Ending December 31, +2012 +2013 +2014 +2015 +2016 +Thereafter +Total +(in thousands) +Minimum Lease Payments +$ +2,575 +$ +2,500 +$ +2,286 +$ +1,867 +$ +402 +$ +1,138 +$ +10,768 +Operating lease expense for the years ended December 31, 2011 , 2010 and 2009, was $5.9 million, $4.9 million and $4.3 million, respectively. +Employment Agreements with Executive Officers . We have employment agreements with our executive officers. The employment agreements provide for annual base salaries, eligibility for performance bonus compensation and other various benefits, including severance benefits. +If, within two years following a change in control of the Company ("change in control period"), either the Company terminates the executive officer without cause or the executive officer terminates employment for good reason, then the severance benefits owed equals three times the sum of the executive's highest annual base salary during the previous two years of employment immediately preceding the termination date and the executive's highest annual bonus paid or, in the case of one executive officer, paid or payable during the same two-year period. Mr. Trimble became President and Chief Executive Officer in June 2011 and under his employment agreement, if he is terminated without cause, he is to receive payment of salary and bonus through June 30, 2013, provided such amount will equal at least one year's salary and bonus. Where the Company terminates the executive officer without cause or the executive officer terminates employment for good reason outside of the change in control period, the severance benefits range from two times to three times, specific to the executive officer, the benefits noted above. For this purpose, a change of control and good reason correspond to the respective definitions of change of control and good reason under IRC Section 409A and the supporting Treasury regulations, with some differences. Under any of the above circumstances, the executive officer is also entitled under his employment agreement to (i) vesting of any unvested equity compensation (excluding all long-term incentive shares), (ii) reimbursement for any unpaid expenses, (iii) retirement benefits earned under the current and/or previous agreements, (iv) continued coverage under our medical plan at the Company's cost for the federal COBRA health continuation coverage period and (v) payment of any earned and unpaid bonus amounts. In addition, the executive officer is entitled to receive any benefits that he would have otherwise been entitled to receive under our qualified retirement plan, although those benefits are not increased or payment accelerated. +In the event that an executive officer is terminated for just cause, we are required to pay the executive officer his base salary through the termination date plus a partial year bonus, incentive, deferred, retirement or other compensation and to provide any other benefits, which have been earned or become payable as of the termination date. +In the event that an executive officer voluntarily terminates his employment for other than good reason, he is entitled to receive (i) his base salary and bonus, provided, however, that with respect to the bonus, for certain executive officers, there will be no proration of the bonus if such executive leaves prior to the last day of the year and, with respect to one executive officer, there will be no proration of the bonus in the event such executive officer leaves prior to March 31 in the year of his termination, (ii) any incentive, deferred or other compensation which has been earned or has become payable, but which has not yet been paid under the schedule originally contemplated in the agreement under which they were granted, (iii) any unpaid expense reimbursement and (iv) any other payments for benefits earned under the employment agreement or our plans. +In the event of death or disability, the executive is entitled to receive certain benefits. For this purpose, the definition of "disability" corresponds to the definition under IRC Section 409A and the supporting Treasury regulations. The benefits will (i) in the case of death be paid in a lump sum and be equal to the base salary that would otherwise have been paid for a six-month period following the termination date and (ii) in the case of disability be up to thirteen weeks of ongoing base salary plus a lump sum equal to six months of base salary. +See Note 16 for a discussion related to the separation agreement entered into with our former chief executive officer in 2011. +85 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 12 - COMMON STOCK +Sale of Equity Securities +The following offerings were made pursuant to an effective shelf registration statement on Form S-3 filed with the SEC on November 26, 2008, and declared effective on January 30, 2009. +• +In November 2010, we sold 4,140,000 shares of our common stock in an underwritten public offering at a price of $32.00 per share. The net proceeds of $125.5 million were used, together with other proceeds, to fund an acquisition of additional assets in the Wolfberry Trend in the Permian Basin of West Texas, which closed in November 2010, our acquisition of the 2004 and 2005 partnerships and other acquisitions and for general corporate purposes. Pending such uses, we applied the net proceeds from this offering and other proceeds to temporarily repay the entire outstanding amount under our credit facility, with the remaining balance being deposited in an interest bearing account and held as cash and cash equivalents until utilized as contemplated above. +• +In August 2009, we sold 4,312,500 shares of our common stock in an underwritten public offering at a price of $12.00 per share. We used the net proceeds of $48.5 million to pay down our credit facility and for general corporate purposes. +Stock-Based Compensation Plans +2010 Long-Term Equity Compensation Plan. In June 2010, our shareholders approved a long-term equity compensation plan for our employees and non-employee directors (the "2010 Plan"). In accordance with the 2010 Plan, up to 1,400,000 new shares of our common stock are authorized for issuance. Shares issued may be either authorized but unissued shares, treasury shares or any combination of these shares. Additionally, the 2010 Plan permits the reuse or reissuance of shares of common stock which were canceled, expired, forfeited or, in the case of stock appreciation rights ("SARs"), paid out in the form of cash. Awards may be issued to our employees in the form of incentive or non-qualified stock options, SARs, restricted stock, restricted stock units ("RSUs"), performance shares and performance units and to our non-employee directors in the form of non-qualified stock options, SARs, restricted stock and RSUs. Awards may vest over periods set at the discretion of the Compensation Committee of our Board of Directors (the "Compensation Committee") with certain minimum vesting periods. With regard to options and SARs, awards have a maximum exercisable period of ten years. In no event may an award be granted under the 2010 Plan on or after April 1, 2020. As of December 31, 2011, 895,663 shares remain available for issuance pursuant to the 2010 Plan. +2004 Long-Term Equity Compensation Plan. As approved by the shareholders in June 2004, we maintain a long-term equity compensation plan for our officers and certain key employees (the "2004 Plan"). Awards pursuant to the plan vest over periods set at the discretion of the Compensation Committee and, with regard to options, have a maximum exercisable period of ten years. As of December 31, 2011, there were no shares remaining available for issuance pursuant to the 2004 Plan. All outstanding and non-vested awards pursuant to the 2004 Plan will continue to be outstanding and vest pursuant to their original terms on or before April 19, 2020. +The following table provides a summary of the impact of our outstanding stock-based compensation plans on the results of operations for the periods presented. +Year Ended December 31, +2011 +2010 +2009 +(in thousands) +Total stock-based compensation +$ +8,781 +$ +5,314 +$ +5,935 +Income tax benefit +(3,344 +) +(2,019 +) +(2,277 +) +Net expense +$ +5,437 +$ +3,295 +$ +3,658 +Stock Option Awards +We have granted stock options pursuant to various stock compensation plans. Outstanding options expire ten years from the date of grant and become exercisable ratably over a four year period. We have not issued any new stock options awards since 2006. As of December 31, 2011, all compensation cost related to stock options has been fully recognized in our statements of operations. +86 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the changes in our stock option awards. The aggregate intrinsic value of options outstanding for each period presented was immaterial. +Year Ended December 31, +2011 +2010 +2009 +Number of +Shares +Underlying +Options +Weighted +Average +Exercise +Price +Per Share +Weighted +Average +Remaining +Contractual +Term (years) +Number of +Shares +Underlying +Options +Weighted +Average +Exercise +Price +Per Share +Number of +Shares +Underlying +Options +Weighted +Average +Exercise +Price +Per Share +Outstanding beginning of year, January 1 +10,306 +$ +41.90 +— +10,306 +$ +41.90 +18,351 +$ +41.68 +Forfeited +(3,333 +) +43.60 +— +— +— +(8,045 +) +41.39 +Outstanding end of year, December 31 +6,973 +41.09 +3.6 +10,306 +41.90 +10,306 +41.90 +Exercisable at December 31 +6,973 +41.09 +3.6 +10,306 +41.60 +8,591 +41.42 +SARs +In March 2011, the Compensation Committee awarded 31,552 SARs to our executive officers. The SARs will vest ratably over a three-year period and may be exercised at any point after vesting through March 2021. Pursuant to the terms of the awards, upon exercise, the executive officers will receive, in shares of common stock, the excess of the market price of the award on the date of exercise over the market price of the award on the date of issuance. +The fair value of each SAR award was estimated on the date of grant using a Black-Scholes pricing model using the assumptions presented in the table below. The expected life of the award was estimated using historical stock option exercise behavior data. The risk-free interest rate was based on the U.S. Treasury yields approximating the expected life of the award in effect at the time of grant. Expected volatilities were based on our historical volatility. We do not expect to pay dividends, nor do we expect to declare dividends in the foreseeable future. There were no SARs awards in 2009. +Year Ended December 31, +2011 +2010 +Expected term of the award +6 years +5 years +Risk-free interest rate +2.5 +% +2.5 +% +Volatility +60.2 +% +62.0 +% +Weighted average grant date fair value per share +$ +25.22 +$ +13.26 +The following table presents the changes in our SARs. +Year Ended December 31, +2011 +2010 +Number of +SARs +Weighted +Average +Exercise +Price +Average Remaining Contractual +Term (in years) +Aggregate Intrinsic +Value (in thousands) +Number of +SARs +Weighted +Average +Exercise +Price +Average Remaining Contractual +Term +(in years) +Aggregate Intrinsic +Value (in thousands) +Outstanding beginning of year, January 1 +57,282 +$ +24.44 +— +$ +1,020 +— +$ +— +$ +— +$ +— +Awarded +31,552 +43.95 +— +— +57,282 +24.44 +— +— +Exercised +(25,371 +) +24.44 +— +77 +— +— +— +— +Forfeited +(12,992 +) +43.95 +— +— +— +— +— +— +Outstanding end of year, December 31 +50,471 +31.61 +8.6 +341 +57,282 +24.44 +9.3 +1,020 +Exercisable at December 31 +10,636 +24.44 +8.3 +114 +— +— +— +— +Pursuant to a separation agreement with our former chief executive officer and the original terms of the award, during the year ended December 31, 2011, the vesting of 29,906 SARs was accelerated, resulting in the acceleration of $0.6 million in stock-based compensation expense. This former executive officer subsequently exercised 25,371 SARs. The fair market price on the exercise date was +87 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +$27.49 per share, resulting in the issuance of 2,814 shares of common stock. The total compensation cost related to SARs granted and not yet recognized in our statement of operations as of December 31, 2011, was $0.5 million. The cost is expected to be recognized over a weighted average period of 1.8 years. +Restricted Stock Awards +Time-Based Awards. For the year ended December 31, 2011, the Compensation Committee awarded a total of 113,243 time-based restricted shares to our executive officers that primarily vest ratably over three years from date of grant and 23,360 time-based restricted shares to our non-employee directors also vesting ratably over three years from date of grant. +Pursuant to a separation agreement with our former chief executive officer and the original terms of the award, during the year ended December 31, 2011, the vesting of 64,442 time-based restricted shares was accelerated, resulting in the acceleration of $1.9 million in stock-based compensation expense. The total compensation cost related to non-vested time-based awards expected to vest and not yet recognized in our statements of operations as of December 31, 2011, was $10.9 million. This cost is expected to be recognized over a weighted average period of 2.4 years. +The following table presents the changes in non-vested time-based awards during 2011 . +Shares +Weighted Average +Grant-Date +Fair Value +Non-vested at December 31, 2010 +525,715 +$ +25.53 +Granted +295,239 +33.71 +Vested +(256,311 +) +26.97 +Forfeited +(36,842 +) +27.22 +Non-vested at December 31, 2011 +527,801 +29.29 +As of/Year Ended December 31, +2011 +2010 +2009 +(in thousands, except per share data) +Total intrinsic value of time-based awards vested +$ +9,030 +$ +3,219 +$ +1,731 +Total intrinsic value of time-based awards non-vested +18,531 +22,211 +5,560 +Market price per common share as of December 31 +35.11 +42.25 +18.21 +Weighted average grant date fair value per share +33.71 +25.04 +14.02 +Market-Based Awards. The fair value of the market-based restricted shares is amortized ratably over the requisite service period, primarily three years. Generally, the market-based shares vest if the participant is continuously employed throughout the performance period and the market-based performance measure is achieved, with a maximum vesting period of five years. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. +In March 2011, the Compensation Committee awarded a total of 13,531 market-based restricted shares to our executive officers. In addition to continuous employment, the vesting of these shares is contingent on the Company's total shareholder return ("TSR"), which is essentially the Company’s stock price change including any dividends, as compared to the TSR of a set group of 11 peer companies. The shares are measured over a three-year period ending on December 31, 2013, and can result in a payout between zero and 200% of the total shares awarded. The weighted average grant date fair value per market-based share for these awards granted was computed using the Monte Carlo pricing model using the weighted average assumptions presented in the table below. There were no market-based awards in 2010. +Year Ended December 31, +2011 +2009 +Expected term of award +3 years +3 years +Risk-free interest rate +1.1 +% +2.0 +% +Volatility +74.2 +% +59.0 +% +Weighted average grant date fair value per share +$ +58.53 +$ +6.47 +For our 2011 awards, the expected volatility was based on our historical volatility and, for our 2009 awards, the expected volatility was based on a blend of our historical and implied volatilities. The expected lives of the awards were based on the requisite service period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant or modification and extrapolated to approximate the life of the award. We do not expect to pay dividends, nor do we expect to declare dividends in the foreseeable future. +88 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the change in non-vested market-based awards during 2011. +Shares +Weighted Average +Grant-Date +Fair Value per Share +Non-vested at December 31, 2010 +79,550 +$ +32.52 +Granted +13,531 +58.53 +Vested +(10,690 +) +6.47 +Forfeited +(39,310 +) +38.11 +Non-vested at December 31, 2011 +43,081 +42.05 +As of/Year Ended December 31, +2011 +2010 +2009 +(in thousands, except per share data) +Total intrinsic value of market-based awards vested +$ +366 +$ +— +$ +— +Total intrinsic value of market-based awards non-vested +1,513 +3,361 +1,449 +Market price per common share as of December 31 +35.11 +42.25 +18.21 +Weighted average grant date fair value per share +58.53 +— +6.47 +Pursuant to a separation agreement with our former chief executive officer and the original terms of the award, during 2011, the vesting of 4,109 market-based restricted shares was accelerated and 21,927 market-based restricted shares were forfeited. The impact on stock-based compensation for the vesting and forfeiture of these market-based restricted shares was immaterial. The total compensation cost related to non-vested market-based awards expected to vest and not yet recognized in our statement of operations as of December 31, 2011, was immaterial. This cost is expected to be recognized over a weighted average period of 2 years. +Treasury Share Purchases +In accordance with our stock-based compensation plans, employees and directors may surrender shares of the Company's common stock to cover tax withholding obligations upon the vesting and exercise of share-based awards. The shares acquired may be retired or reissued to service awards under our 2010 Plan. For shares that are retired, we first charge any excess of cost over the par value to additional paid-in-capital ("APIC") to the extent we have amounts in APIC, with any remaining excess cost charged to retained earnings. For shares reissued to service awards under the 2010 Plan, shares are recorded at cost and upon reissuance, we reduce the carrying value of shares acquired and held pursuant to the 2010 Plan by the weighted average cost per share with an offsetting charge to APIC. During the year ended December 31, 2011, we acquired 87,588 shares pursuant to our stock-based compensation plans for payment of tax liabilities, of which 15,072 shares were reissued pursuant to our 2010 Plan and the remaining 72,516 shares retired. +Shareholders’ Rights Agreement +In 2007, we entered into a rights agreement. The rights agreement is designed to improve the ability of our Board to protect the interest of our shareholders in the event of an unsolicited takeover attempt. Our Board declared a dividend of one right for each outstanding share of our common stock. The right dividend was paid to shareholders of record on September 14, 2007. A "distribution date," as defined in the rights agreement, can occur after any individual shareholder exceeds 15% ownership of our outstanding common stock. After the occurrence of a "distribution date," the right entitles each registered holder (other than the acquiring shareholder who triggered the "distribution date"), to purchase shares of our common stock (or, in certain circumstances, cash, property or other securities) having a then-current value equal to two times the exercise price of the right (i.e., for the $240 exercise price, the rights holder receives $480 worth of common stock). The exercise price is subject to adjustment for various corporate actions which affect all shareholders, such as a stock split. The rights agreement and all rights will expire on September 11, 2017. +Preferred stock +We are authorized, pursuant to shareholder approval in 2008, to issue 50,000,000 shares of Company preferred stock, par value $0.01, which may be issued in one or more series, with such rights, preferences, privileges and restrictions as shall be fixed by our Board from time to time. As of December 31, 2011 , no preferred shares had been issued. +89 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 13 - ASSETS HELD FOR SALE, DIVESTITURES AND DISCONTINUED OPERATIONS +Selected financial information . The tables below set forth selected financial information related to net assets divested, net assets related to discontinued operations and operating results related to discontinued operations. Net assets held for sale represents the assets that were or are expected to be sold net of liabilities that were or are expected to be assumed by the purchaser. Net assets related to discontinued operations presents those assets that were or are expected to be sold less liabilities that were or are expected to be assumed by the purchaser, as well as all other related assets and liabilities, consisting of accounts receivable and production tax liability, which were not sold. While the reclassification of revenues and expenses related to discontinued operations for prior periods had no impact upon previously reported net earnings, the statement of operations table presents the revenues and expenses that were reclassified from the specified statement of operations line items to discontinued operations. +The following table presents balance sheet data related to assets held for sale. +As of December 31, +2011 +2010 +Balance Sheet +Net Assets Held for Sale +Net Assets +Related to Discontinued Operations +Net Assets Held for Sale +Net Assets +Related to Discontinued Operations +(in thousands) +Assets +Current assets +Accounts receivable, net +$ +— +$ +3,198 +$ +— +$ +1,971 +Oil inventory +— +89 +— +59 +Total current assets +— +3,287 +— +2,030 +Properties and equipment +168,218 +168,218 +129,093 +129,093 +Accumulated DD&A +(19,969 +) +(19,969 +) +(12,534 +) +(12,534 +) +Total assets +148,249 +151,536 +116,559 +118,589 +Liabilities +Current liabilities +Accounts payable +— +1,907 +— +1,630 +Production tax liability +— +262 +— +120 +Total current liabilities +— +2,169 +— +1,750 +Asset retirement obligation +2,022 +2,022 +2,644 +2,644 +Total liabilities +$ +2,022 +$ +4,191 +$ +2,644 +$ +4,394 +Net assets +$ +146,227 +$ +147,345 +$ +113,915 +$ +114,195 +90 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents statement of operations data related to our discontinued operations. +Year Ended December 31, +Statements of Operations - Discontinued Operations +2011 +2010 +2009 +(in thousands) +Revenues +Natural gas, NGL and crude oil sales +$ +27,552 +$ +11,130 +$ +7,851 +Sales from natural gas marketing +— +3,328 +5,040 +Natural gas and crude oil well drilling +— +— +193 +Well operations, pipeline income and other +128 +560 +951 +Total revenues +27,680 +15,018 +14,035 +Costs, expenses and other +Production costs +8,529 +4,303 +2,643 +Cost of natural gas marketing +— +3,265 +4,916 +Exploration expense +36 +135 +613 +Impairment of natural gas and crude oil properties +— +4,666 +3,171 +Gain on sale of properties and equipment +(3,854 +) +— +— +Depreciation, depletion and amortization +6,247 +2,967 +4,249 +Total costs, expenses and other +10,958 +15,336 +15,592 +Income (loss) from discontinued operations +16,722 +(318 +) +(1,557 +) +Provision (benefit) for income taxes +6,363 +(214 +) +(582 +) +Income (loss) from discontinued operations, net of tax +$ +10,359 +$ +(104 +) +$ +(975 +) +Permian Basin. In October 2011, we developed a plan to divest our Permian Basin asset group. The plan includes 100% of our Permian Basin assets, consisting of producing wells and undeveloped leaseholds. During the fourth quarter of 2011, we completed the sale of our non-core Permian assets to unrelated third parties for a total of $13.2 million. On December 20, 2011, we executed a purchase and sale agreement with COG Operating LLC (“COG”), a wholly owned subsidiary of Concho Resources Inc., an unrelated third party, for the sale of our core Permian Basin assets for a sale price of $173.9 million, subject to customary terms and adjustments, including adjustments based on title and environmental due diligence to be conducted by COG. The effective date of the closing is November 1, 2011. Accordingly, the Permian assets were reclassified as held for sale as of December 31, 2011 and 2010, and the results of operations related to those assets have been reported as discontinued operations in the consolidated statements of operations in 2010, year of acquisition, and 2011. On February 28, 2012, the divestiture closed with total proceeds received of $184.4 million after preliminary closing adjustments. See Note 18. +North Dakota . During the fourth quarter of 2010, we developed a plan to divest our North Dakota assets. The plan included 100% of our North Dakota assets, consisting of producing wells, undeveloped leaseholds and related facilities primarily located in Burke County. The plan received approval from our Board of Directors (the "Board") and, in December 2010, we effected a letter of intent with an unrelated third party. Following the sale to the unrelated party, we do not have significant continuing involvement in the operations of or cash flows from these assets; accordingly, the North Dakota assets were reclassified as held for sale as of December 31, 2010, and the results of operations related to those assets have been reported as discontinued operations in the consolidated statement of operations in all periods presented. In February 2011, we executed a purchase and sale agreement and subsequently closed with the same unrelated party. Proceeds from the sale were $9.5 million, net of non-affiliated investor partners' share of $3.8 million, resulting in a pretax gain on sale of $3.9 million. +Michigan . During the third quarter of 2010, we divested our Michigan asset group and related liabilities for net cash proceeds of $22 million and realized a loss on sale of $4.7 million in the form of an impairment charge recorded during the year ended 2010 (see Note 2 regarding the impairment charge). We do not have significant continuing involvement in the operations of or cash flows from this asset group. Accordingly, the Michigan assets were reclassified as held for sale as of December 31, 2010, and the results of operations related to the those assets have been reported as discontinued operations in the consolidated statement of operations for 2010 and 2009. +Natural Gas and Crude Oil Well Drilling Activities . We offered our last sponsored drilling partnership in October 2007. In January 2008, we first announced that we had no plans to sponsor a new drilling partnership in 2008 and this decision was upheld again in 2009. As of June 30, 2009, all remaining contractual drilling and completion obligations were completed for all partnerships and we did not have any plans in the foreseeable future to sponsor a drilling partnership; accordingly, we reclassified our natural gas and crude oil well drilling activities as discontinued operations. +91 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 14 - ACQUISITIONS +The following table presents the adjusted purchase price and the allocations thereof, based on our estimates of fair value, for the acquisition of natural gas and crude oil properties during 2011 and 2010. +Year Ended December 31, +2011 +2010 +Seneca-Upshur +2003/2002-D Partnerships +2005 Partnerships +Permian +2004 +Partnerships +(in thousands) +Total acquisition cost +$ +81,465 +$ +29,960 +$ +43,015 +$ +114,273 +$ +34,768 +Recognized amounts of identifiable assets acquired and liabilities assumed: +Assets acquired: +Natural gas and crude oil properties - proved +$ +20,175 +$ +27,940 +$ +39,825 +$ +45,592 +$ +32,730 +Natural gas and crude oil properties - unproved +60,965 +— +— +71,647 +— +Other assets +10,196 +3,455 +3,848 +— +3,396 +Total assets acquired +91,336 +31,395 +43,673 +117,239 +36,126 +Liabilities assumed: +Asset retirement obligation +8,175 +497 +300 +2,351 +912 +Environmental liability +— +— +— +615 +126 +Other liabilities +1,696 +938 +358 +— +320 +Total liabilities assumed +9,871 +1,435 +658 +2,966 +1,358 +Total identifiable net assets acquired +$ +81,465 +$ +29,960 +$ +43,015 +$ +114,273 +$ +34,768 +Pro Forma Information . The results of operations for the above acquisitions have been included in our consolidated financial statements from the date of acquisition. Pro forma information is not presented as the pro forma results would not be materially different from the information presented in the accompanying statements of operations. +2011 Acquisitions +Seneca-Upshur . In October 2011, PDCM acquired from an unrelated third party 100% of the membership interests of Seneca-Upshur Petroleum, LLC ("Seneca-Upshur"), a West Virginia limited liability company, for the purchase price of $162.9 million ($81.5 million net to PDC), including a post-closing working capital adjustment of $10.4 million. Pursuant to the terms of the purchase agreement, there will be certain post-closing adjustments through April 1, 2012, including with respect to title, environmental and plugging and abandonment matters. In conformity with the transaction, the Company took over certain ordinary course litigation. However, the seller retained certain specific litigation matters. The acquisition included approximately 1,340 wells producing from the shallow Devonian Shale and Mississippian formations and all rights and depths to an estimated 100,000 net acres in West Virginia, of which 90,000 acres are prospective for the Marcellus Shale. We estimate that the acquisition added approximately 8 Bcfe to our total proved reserves as of December 31, 2011. Substantially all of the acreage acquired is held by production, prospective for the Marcellus Shale and is in close proximity to PDCM's existing properties. +2003/2002-D Partnerships . On October 28, 2011, we acquired from non-affiliated investor partners' the remaining working interest in five of our affiliated partnerships: PDC 2003-A Limited Partnership, PDC 2003-B Limited Partnership, PDC 2003-C Limited Partnership, PDC 2003-D Limited Partnership and PDC 2002-D Limited Partnership ("2003/2002-D Partnerships"). We purchased these partnerships for an aggregate amount of $30 million, which was funded from our corporate credit facility during the fourth quarter of 2011. These purchases included the non-affiliated investor partners remaining working interests in a total of 153 gross, 99.7 net, wells located in Wattenberg and Piceance. The acquisitions allow us the opportunity, assuming favorable capital and commodity markets, to accelerate the pace of refracturing the wells acquired, thus allowing us to optimize revenue opportunities. +2005 Partnerships . On June 15, 2011, we acquired from non-affiliated investor partners' the remaining working interest in three of our affiliated partnerships: PDC 2005-A Limited Partnership, PDC 2005-B Limited Partnership and Rockies Region Private Limited Partnership ("2005 Partnerships"). We purchased these partnerships for an aggregate amount of $43.0 million, which was funded from our corporate credit facility during the third quarter of 2011. These purchases included the non-affiliated investor partners' remaining working interests in a total of 146 gross, 104.5 net, wells located in Wattenberg and Piceance. The acquisitions allow us the opportunity, assuming favorable capital and commodity markets, to accelerate the pace of refracturing the wells acquired, thus allowing us to optimize revenue opportunities. +92 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +2010 Acquisitions +2004 Partnerships . In December 2010, we acquired the remaining working interest in four of our affiliated partnerships: PDC 2004-A Limited Partnership, PDC 2004-B Limited Partnership, PDC 2004-C Limited Partnership and PDC 2004-D Limited Partnership. We purchased these partnerships for an aggregate amount of $36.5 million. These purchases included the remaining working interests in a total of 122 gross, 88.6 net, wells located in Wattenberg and Piceance. The acquisitions allowed us the opportunity to accelerate the pace of refracturing the wells acquired, thus allowing us to optimize revenue opportunities. +Permian Basin . In July 2010, we acquired various producing assets located in the Wolfberry Trend in the Permian Basin in West Texas. In conjunction with the divestiture of our Michigan asset group we entered into a like-kind exchange agreement, in accordance with IRC Section 1031, with a qualified intermediary. The Wolfberry assets were identified as our replacement property in accordance with IRC Section 1031. Sales proceeds in the amount of $19.3 million from the Michigan divestiture were transferred directly to the qualified intermediary and, along with $55.7 million from our credit facility, funded the our Wolfberry acquisition. The sale of our Michigan assets resulted in a gain for income tax purposes of $19.2 million, which then resulted in a tax liability of $7.3 million. With the favorable deferral aspects of IRC Section 1031, we were able to defer $6.5 million of this tax liability. +In November 2010, we acquired for $39.4 million in cash a second position in the Wolfberry oil trend including 100% of the interest in producing assets and undeveloped acreage. The assets included seven producing wells that are located on a primarily contiguous 5,760 net acre block. +See Note 13 for a discussion of the divestiture of our Permian assets. +NOTE 15 - NONCONTROLLING INTEREST IN SUBSIDIARY +In 2007, we contributed $0.8 million for a 50% interest in WWWV, LLC (the "LLC"), a limited liability company for which we serve as the managing member. The LLC's only asset was an aircraft and was formed for the purpose of owning and operating the aircraft. We consolidated the entity based on a controlling financial interest. In 2011, we divested the asset and dissolved the entity with no material impact on our financial statements. +NOTE 16 - TRANSACTIONS WITH AFFILIATES +Former Executive Officer. In June 2011, Richard W. McCullough resigned from his positions as our Chief Executive Officer and the Chairman of the Board, effective immediately. In connection with his resignation, in July 2011, Mr. McCullough and the Company executed a separation agreement, whereby Mr. McCullough will receive those benefits to which he was entitled under Section 7(d) of his employment agreement, dated as of April 19, 2010, including without limitation: (i) separation compensation in the amount of $4.1 million, less required withholdings; (ii) his annual non-qualified deferred supplemental retirement benefit equal to $30,000 for each of the years 2012 through 2021 (not accelerated), less required withholdings; (iii) continued coverage under the Company’s group health plans at the Company’s cost for a period equal to the lesser of 18 months or such period ending as of the date Mr. McCullough is eligible to participate in another employer’s group health plan; (iv) immediate vesting of any unvested Company stock options, SARs and restricted stock; and (v) issuance of shares representing the vested portion of his 2009 performance share awards. Related to this separation agreement, the statement of operations for 2011 reflects a charge to general and administrative expense of $6.7 million. +Affiliated Partnerships. Our Gas Marketing segment markets the natural gas produced by our affiliated partnerships in the Eastern Operating Region. Our sales from natural gas marketing include $1.3 million, $0.7 million and $0.5 million in 2011 , 2010 and 2009, respectively, related to the marketing of natural gas on behalf of our affiliated partnerships. Our cost of natural gas marketing include $1.3 million, $0.6 million and $0.5 million in 2011 , 2010 and 2009, respectively, related to these sales. +Amounts due from/to the affiliated partnerships are primarily related to derivative positions and, to a lesser extent, unbilled well lease operating expenses, and costs resulting from audit and tax preparation services. We have entered into derivative instruments on behalf of our affiliated partnerships for their estimated production. As of December 31, 2011 and 2010, we had a payable to affiliates of $14.2 million and $20.3 million, respectively, representing their designated portion of the fair value of our gross derivative assets and a receivable from affiliates of $6.2 million and $14.6 million, respectively, representing their designated portion of the fair value of our gross derivative liabilities. +We provide well operations and pipeline services to our affiliated partnerships. The majority of all of our revenue and expenses related to well operations and pipeline income are associated with services provided to our affiliated partnerships. Further, through June 2009, we provided natural gas and crude oil well drilling services to our affiliated partnerships. For the year ended December 31, 2009, we recognized $0.2 million in revenue related to these services, which have been reclassified on our statement of operations for inclusion in discontinued operations. See Note 13. +PDCM . Our Gas Marketing segment markets the natural gas produced by PDCM. Our sales from natural gas marketing include $9.7 million and $4.3 million 2011 and 2010, respectively, related to the marketing of natural gas on behalf of PDCM. Our cost of natural gas marketing include $9.5 million and $4.2 million in 2011 and 2010, respectively, related to these sales. +93 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +We provide certain well operating and administrative services for PDCM. Amounts billed to PDCM for these services were $10.4 million and $11.1 million in 2011 and 2010, respectively. Our statements of operations include only our proportionate share of these billings. The following table presents the statement of operations line item in which our proportionate share is recorded and the amount for each of the periods presented. +Year Ended December 31, +Statement of Operations Line Item +2011 +2010 +(in thousands) +Production Costs +$ +3,441 +$ +3,862 +Exploration Expense +430 +883 +General and Administrative Expense +1,543 +1,899 +NOTE 17 - BUSINESS SEGMENTS +We separate our operating activities into two segments: Oil and Gas Exploration and Production and Gas Marketing. All material inter-company accounts and transactions between segments have been eliminated. +Oil and Gas Exploration and Production. Our Oil and Gas Exploration and Production segment includes all of our natural gas and crude oil properties. The segment represents revenues and expenses from the production and sale of natural gas, NGLs and crude oil. Segment revenue includes natural gas, NGL and crude oil sales, commodity price risk management, net and well operation and pipeline income. Segment income (loss) consists of segment revenue less production cost, exploration expense, impairment of natural gas and crude oil properties, direct general and administrative expense and DD&A expense. Segment DD&A expense was $122.2 million in 2011, $105.9 million in 2010 and $123.2 million in 2009. +Gas Marketing. Our Gas Marketing segment purchases, aggregates and resells natural gas produced by us and others. Segment income (loss) primarily represents sales from natural gas marketing and direct interest income less costs of natural gas marketing and direct general and administrative expense. +Unallocated amounts. Unallocated income includes unallocated other revenue less corporate general administrative expense, corporate DD&A expense, interest income and interest expense. +94 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following tables present our segment information. +2011 +2010 +2009 +(in thousands) +Year Ended December 31, +Revenues: +Oil and Gas Exploration and Production +$ +329,541 +$ +273,950 +$ +171,262 +Gas Marketing +66,419 +69,071 +59,595 +Unallocated +— +— +19 +Total Revenues +$ +395,960 +$ +343,021 +$ +230,876 +Segment income (loss) from continuing operations before income taxes: +Oil and Gas Exploration and Production +$ +106,832 +$ +84,387 +$ +(34,382 +) +Gas Marketing +954 +1,063 +1,967 +Unallocated +(104,891 +) +(78,760 +) +(92,757 +) +Total +$ +2,895 +$ +6,690 +$ +(125,172 +) +Expenditures for segment long-lived assets: +Oil and Gas Exploration and Production +$ +479,027 +$ +319,268 +$ +140,431 +Unallocated +1,363 +1,506 +2,602 +Total +$ +480,390 +$ +320,774 +$ +143,033 +As of December 31, +Segment assets: +Oil and Gas Exploration and Production +$ +1,461,130 +$ +1,202,474 +Gas Marketing +14,713 +16,338 +Unallocated +73,913 +53,701 +Assets held for sale +148,249 +116,522 +Total Assets +$ +1,698,005 +$ +1,389,035 +NOTE 18 - SUBSEQUENT EVENT +In October 2011, we announced our intention to divest our acreage located in the Wolfberry Trend in the Permian Basin in West Texas to refocus our efforts in our horizontal drilling programs and to provide funds for our 2012 capital program. On December 20, 2011, we executed a purchase and sales agreement with COG for the sale of our Permian Basin Wolfberry assets for a total price of $173.9 million, subject to customary post-closing adjustments. The transaction closed on February 28, 2012 with total proceeds received of $184.4 million after preliminary closing adjustments . The proceeds from the sale will be used to pay down our corporate credit facility and provide liquidity to fund our 2012 capital budget. The divestiture is expected to provide us with capital funding to allow us to accelerate the development of our liquid-rich inventory of projects in the Wattenberg Field. Our Permian Basin assets were classified as held for sale as of December 31, 2011 and 2010, and the results of operations related to those assets were reported as discontinued operations in the consolidated statements of operations in 2010, year of acquisition, and 2011. See Note 13. +95 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +SUPPLEMENTAL INFORMATION - UNAUDITED +NATURAL GAS AND CRUDE OIL INFORMATION - UNAUDITED +Net Proved Reserves +All of our natural gas, NGL and crude oil reserves are located in the U.S. We utilize the services of independent petroleum engineers to estimate our natural gas, crude oil, condensate and NGL reserves. As of December 31, 2011 , all of our reserve estimates were based on a reserve report prepared by Ryder Scott Company, L.P. ("Ryder Scott"). These reserve estimates have been prepared in compliance with professional standards and the reserves definitions prescribed by the SEC. +Proved reserves estimates may change, either positively or negatively, as additional information becomes available and as contractual, economic and political conditions change. Our net proved reserve estimates have been adjusted as necessary to reflect all contractual agreements, royalty obligations and interests owned by others at the time of the estimate. Proved developed reserves are the quantities of natural gas, NGL and crude oil expected to be recovered through existing wells with existing equipment and operating methods. In some cases, proved undeveloped reserves may require substantial new investments in additional wells and related facilities. +The price used to estimate our reserves, by commodity, are presented below. +Price Used to Estimate Reserves +As of December 31, +Natural Gas +(per Mcf) +NGLs +(per Bbl) +Crude Oil +(per Bbl) +2011 +$ +3.41 +$ +39.59 +$ +88.94 +2010 +3.54 +34.12 +71.95 +2009 (1) +3.17 +— +54.64 +__________ +(1) +Prior to 2010, NGLs were included in natural gas, which impacts the comparability for 2011 and 2010 to 2009. +96 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +The following tables present the changes in our estimated quantities of proved reserves. +Natural Gas +(MMcf) +NGLs +(MBbls) (1) +Crude Oil, Condensate (MBbls) +Total +(MMcfe) +Proved Reserves: +Proved reserves, January 1, 2009 +662,857 +— +15,037 +753,079 +Revisions of previous estimates +(101,923 +) +— +2,957 +(84,181 +) +Extensions, discoveries and other additions +Western Operating Region +79,574 +— +1,322 +87,506 +Eastern Operating Region +3,190 +— +— +3,190 +Purchases of reserves +Western Operating Region +648 +— +47 +930 +Eastern Operating Region +59 +— +— +59 +Other +63 +— +— +63 +Dispositions +(7 +) +— +(1 +) +(13 +) +Production +(35,536 +) +— +(1,292 +) +(43,288 +) +Proved reserves, December 31, 2009 +608,925 +— +18,070 +717,345 +Revisions of previous estimates +6,504 +8,908 +(85 +) +59,442 +Extensions, discoveries and other additions +Western Operating Region +56,524 +811 +2,247 +74,872 +Eastern Operating Region +35,092 +— +— +35,092 +Purchases of reserves +Western Operating Region +20,920 +1,531 +4,367 +56,308 +Eastern Operating Region +220 +— +— +220 +Dispositions +(43,690 +) +— +(55 +) +(44,020 +) +Production +(27,189 +) +(601 +) +(1,308 +) +(38,643 +) +Proved reserves, December 31, 2010 +657,306 +10,649 +23,236 +860,616 +Revisions of previous estimates +(161,654 +) +3,163 +(1,904 +) +(154,100 +) +Extensions, discoveries and other additions +Western Operating Region +125,374 +5,633 +17,092 +261,724 +Eastern Operating Region +51,315 +— +— +51,315 +Purchases of reserves +Western Operating Region +24,776 +1,052 +1,581 +40,574 +Eastern Operating Region +7,985 +— +24 +8,129 +Dispositions +(2,070 +) +(94 +) +(435 +) +(5,244 +) +Production +(30,887 +) +(815 +) +(1,958 +) +(47,525 +) +Proved reserves, December 31, 2011 (2) +672,145 +19,588 +37,636 +1,015,489 +Proved Developed Reserves, as of: +January 1, 2009 +297,041 +— +5,438 +329,669 +December 31, 2009 +258,375 +— +6,244 +295,839 +December 31, 2010 +227,341 +4,013 +8,287 +301,141 +December 31, 2011 (2) +299,369 +11,753 +16,910 +471,347 +Proved Undeveloped Reserves, as of: +January 1, 2009 +365,816 +— +9,599 +423,410 +December 31, 2009 +350,550 +— +11,826 +421,506 +December 31, 2010 +429,965 +6,636 +14,949 +559,475 +December 31, 2011 (2) +372,776 +7,835 +20,726 +544,142 +__________ +(1) +Prior to 2010, NGLs were included in natural gas, which impacts the comparability for 2011 and 2010 to 2009. +(2) +Includes estimated reserve data related to our Permian asset group, which was held for sale and under a purchase and sale agreement. The divestiture of our Permian assets closed on February 28, 2012. See Note 11, Commitments and Contingencies - Purchase and Sale Agreement, and Note 13, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included in this report for additional details related to the divestiture of our Permian asset group. Total proved reserves include 6,242 MMcf of natural gas, 7,825 MBbls of crude oil, 1,971 MBbls of NGLs and 65,018 MMcfe of natural gas equivalent related to our Permian asset group. Similarly, total proved developed reserves include 1,750 MMcf, 1,815 MBbls, 550 MBbls and 15,940 MMcfe, respectively, and proved undeveloped reserves include 4,492 MMcf, 6,010 MBbls, 1,421 MBbls and 49,078 MMcfe, respectively. +97 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +Developed +Undeveloped +Total +(MMcfe) +Beginning proved reserves, January 1, 2010 +295,839 +421,506 +717,345 +Undeveloped reserves transferred to developed +17,967 +(17,967 +) +— +Revisions of previous estimates +16,782 +42,660 +59,442 +Extensions, discoveries and other additions +21,572 +88,392 +109,964 +Purchases of reserves +28,728 +27,800 +56,528 +Dispositions +(41,104 +) +(2,916 +) +(44,020 +) +Production +(38,643 +) +— +(38,643 +) +Ending proved reserves, December 31, 2010 +301,141 +559,475 +860,616 +Undeveloped reserves transferred to developed +43,597 +(43,597 +) +— +Revisions of previous estimates +73,643 +(227,743 +) +(154,100 +) +Extensions, discoveries and other additions +58,979 +254,060 +313,039 +Purchases of reserves +46,756 +1,947 +48,703 +Dispositions +(5,244 +) +— +(5,244 +) +Production +(47,525 +) +— +(47,525 +) +Ending proved reserves, December 31, 2011 +471,347 +544,142 +1,015,489 +2011 Activity. In 2011, we recorded a downward revision of our previous estimate of proved reserves of approximately 154 Bcfe. The revision was primarily due to a decrease of approximately 4 Bcfe due to lower gas pricing and approximately 173 Bcfe was removed from proved undeveloped reserves to satisfy the SEC's five year rule. This was partially offset by an increase of approximately 6 Bcfe due to increased efficiencies in operating costs, approximately 5 Bcfe due to non-acquisition interest adjustments and approximately 12 Bcfe due to asset performance. In addition, approximately 125 Bcfe were transfered from proved undeveloped to proved developed as a result of the Company's determination that costs related to a refracture becoming less significant as compared to the costs associated with drilling a new well. New discoveries and extensions of approximately 313 Bcfe in 2011 are due to the drilling of 195 gross wells and the addition of new proved undeveloped reserves. Approximately 51 Bcfe were added in the Eastern Operating Region, approximately 262 Bcfe were added in the Western Operating Region (141 Bcfe in the Wattenberg Field, 80 Bcfe in the Piceance Basin and 41 Bcfe in the Permian Basin). We acquired approximately 49 Bcfe of proved reserves, approximately 8 Bcfe through acquisitions in the Eastern Operating Region, and approximately 41 Bcfe in the Western Operating Region (28 Bcfe were acquired in the Wattenberg Field and 13 Bcfe were acquired in the Piceance Basin) due to the repurchase of the 2003/2002-D and 2005 Partnerships as well as the purchase of interest in some of our other existing properties. We divested a total of approximately 5 Bcfe in 2011. This included the sale of 100% of of our North Dakota assets, or 2 Bcfe, to an unrelated third party and our non-core Permian Basin assets, or 3 Bcfe, to another unrelated third party. Based on the economic conditions on December 31, 2011, we are reasonably certain that we would develop the balance of our proved undeveloped reserves within five years. +2010 Activity. In 2010, we revised our previous estimate of proved reserves upward by 59.4 Bcfe. The revision was primarily due to an increase of 55.6 Bcfe due to asset performance, 35.9 Bcfe due to higher commodity pricing, 28.1 Bcfe due to the impact of evaluating NGLs as a separate stream and 1.5 Bcfe due to interest adjustments. This was partially offset by a decrease of 58.7 Bcfe due to adjustments for reserve decreases for geological reasons or reclassification of prior period proved undeveloped reserves to probable reserves due to aging and 3 Bcfe due to increased operating costs. New discoveries and extensions of 110 Bcfe in 2010 are due to drilling of 213 gross wells and the addition of new proved undeveloped reserves: 35.1 Bcfe were added in the Eastern Operating Region and 74.9 Bcfe were added in the Western Operating Region (29.4 Bcfe in Wattenberg Field, 36.2 Bcfe in Piceance Basin, 9.1 Bcfe in the NECO area and 0.2 Bcfe in North Dakota) and Permian Basin. We acquired 56.5 Bcfe of proved reserves, approximately 32.6 Bcfe through two acquisitions in the Permian Basin and 23.9 Bcfe in both the Western and Eastern Operating Regions due to the repurchase of the 2004 Partnerships as well as the purchase of interest in some of our other existing properties. Of the 23.9 Bcfe, 12.8 Bcfe were acquired in the Wattenberg Field and 10.9 Bcfe were acquired in the Piceance Basin. Total dispositions of 44 Bcfe in 2010 includes the deconsolidation of PDCM, or 28.9 Bcfe, and the sale of all of our Michigan assets, or 15.1 Bcfe, to an unaffiliated third party. +2009 Activity. In 2009, we revised our previous estimate of proved reserves downward by 84.2 Bcfe. The revision was primarily due to a decrease of 99.5 Bcfe due to lower commodity pricing and 45.1 Bcfe due to adjustments to reserves removed or reclassified due to new rules limiting proved undeveloped reserves locations to those scheduled to be drilled within the next five years. The downward adjustments were partially offset by an increase of 41.4 Bcfe due to decreased operating costs, 1 Bcfe due to interest adjustments and 17.9 Bcfe due to asset performance. New discoveries and extensions of 90.7 Bcfe in 2009 were due to drilling of 100 gross wells and the addition of new proved undeveloped reserves: 3.2 Bcfe in the Eastern Operating Region and 87.5 Bcfe in the Western Operating Region (13.7 Bcfe in Wattenberg Field, 73.3 Bcfe in the Piceance Basin and 0.5 Bcfe in North Dakota). We acquired 1.1 Bcfe of proved reserves through the purchase of interest in some of our existing properties. Reserves acquired were primarily in the Wattenberg Field, as were the reserves divested. +98 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +Results of Operations for Natural Gas and Crude Oil Producing Activities +The results of operations for natural gas and crude oil producing activities are presented below. The results include activities related to both continuing and discontinued operations and exclude activities related to natural gas marketing and well operations and pipeline services. +Year Ended December 31, +2011 +2010 +2009 +(in thousands) +Revenue: +Natural gas, NGL and crude oil sales +$ +304,157 +$ +216,159 +$ +179,093 +Commodity price risk management gain (loss), net +46,090 +59,891 +(10,053 +) +350,247 +276,050 +169,040 +Expenses: +Production costs +77,614 +61,544 +57,825 +Exploration expense +6,289 +20,291 +21,961 +Depreciation, depletion, and amortization +128,458 +103,303 +125,415 +Impairment of proved natural gas and oil properties +25,159 +4,666 +926 +Gain on sale of properties and equipment +(4,050 +) +(174 +) +(470 +) +233,470 +189,630 +205,657 +Results of operations for natural gas and crude oil producing +activities before provision for income taxes +116,777 +86,420 +(36,617 +) +Provision (benefit) for income taxes +36,785 +5,937 +(13,186 +) +Results of operations for natural gas and crude oil producing activities, excluding corporate overhead and interest costs +$ +79,992 +$ +80,483 +$ +(23,431 +) +Production costs include those costs incurred to operate and maintain productive wells and related equipment, including costs such as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance, production and severance taxes and associated administrative expenses. DD&A expense includes those costs associated with capitalized acquisition, exploration and development costs, but does not include the depreciation applicable to support equipment. The provision for income taxes is computed using effective tax rates. +Costs Incurred in Natural Gas and Crude Oil Property Acquisition, Exploration and Development Activities +Costs incurred in natural gas and crude oil property acquisition, exploration and development are presented below. +Year Ended December 31, +2011 +2010 +2009 +(in thousands) +Acquisition of properties: (1) +Proved properties +$ +79,554 +$ +87,241 +$ +2,251 +Unproved properties +95,081 +84,636 +5,867 +Development costs (2) +301,008 +138,018 +72,416 +Exploration costs: (3) +Exploratory drilling +3,626 +21,223 +18,317 +Geological and geophysical +1,846 +2,367 +1,788 +Total costs incurred +$ +481,115 +$ +333,485 +$ +100,639 +__________ +(1) +Property acquisition costs - represent costs incurred to purchase, lease or otherwise acquire a property. +(2) +Development costs - represents costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells, recompletions and to provide facilities to extract, treat, gather and store natural gas, NGLs and crude oil. Of these costs incurred for the years ended December 31, 2011 , 2010 and 2009, $80.6 million, $37.4 million and $44.4 million, respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end. +(3) +Exploration costs - represents costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing natural gas, NGL and crude oil reserves. +99 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +Capitalized Costs Related to Natural Gas and Crude Oil Producing Activities +Aggregate capitalized costs related to natural gas and crude oil exploration and production activities with applicable accumulated DD&A are presented below: +As of December 31, +2011 +2010 +(in thousands) +Proved natural gas and crude oil properties (1) +$ +1,694,847 +$ +1,481,191 +Unproved natural gas and crude oil properties +102,466 +85,502 +1,797,313 +1,566,693 +Less accumulated DD&A +621,074 +492,501 +$ +1,176,239 +$ +1,074,192 +__________ +(1) +As of December 31, 2011, we had no capitalized proved undeveloped natural gas and crude oil properties disclosed as such for longer than 5 years. +Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves +The standardized measure below has been prepared in accordance with U.S. GAAP. Future estimated cash flows were based on a 12-month average price calculated as the unweighted arithmetic average of the prices on the first day of each month, January through December applied to our year-end estimated proved reserves. Prices for each of the three years were adjusted by field for Btu content, transportation and regional price differences; however, they were not adjusted to reflect the value of our commodity derivatives. Production and development costs were based on prices as of December 31 for each of the respective years presented. The amounts shown do not give effect to non-property related expenses, such as corporate general and administrative expenses, debt service or to depreciation, depletion and amortization expense. Production and development costs include those cash flows associated with the ultimate settlement of our asset retirement obligation. Future estimated income tax expense is computed by applying the statutory rate in effect at the end of each year to the future pretax net cash flows, less the tax basis of the properties and gives effect to permanent differences, tax credits and allowances related to the properties. +The following table presents information with respect to the standardized measure of discounted future net cash flows relating to proved reserves. Changes in the demand for natural gas, NGLs and crude oil, inflation, and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of our proved reserves. +As of December 31, +2011 +2010 +2009 +(in thousands) +Future estimated cash flows +$ +6,415,255 +$ +4,361,095 +$ +2,915,377 +Future estimated production costs +(1,704,645 +) +(1,418,044 +) +(1,088,337 +) +Future estimated development costs +(1,474,137 +) +(1,119,604 +) +(825,139 +) +Future estimated income tax expense +(946,849 +) +(508,805 +) +(237,790 +) +Future net cash flows +2,289,624 +1,314,642 +764,111 +10% annual discount for estimated timing of cash flows +(1,348,415 +) +(826,224 +) +(416,475 +) +Standardized measure of discounted future estimated net cash flows +$ +941,209 +$ +488,418 +$ +347,636 +100 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +The following table presents the principal sources of change in the standardized measure of discounted future estimated net cash flows. +Year Ended December 31, +2011 +2010 +2009 +(in thousands) +Sales of natural gas, NGL and crude oil production, net of production costs +$ +(226,227 +) +$ +(163,104 +) +$ +(136,568 +) +Net changes in prices and production costs +383,293 +180,124 +(107,766 +) +Extensions, discoveries, and improved recovery, less related costs +467,347 +88,637 +30,851 +Sales of reserves +(4,224 +) +(24,174 +) +(21 +) +Purchases of reserves +64,761 +45,538 +1,266 +Development costs incurred during the period +94,941 +44,491 +40,603 +Revisions of previous quantity estimates +(112,468 +) +47,884 +(46,226 +) +Changes in estimated income taxes +(204,377 +) +(105,557 +) +38,371 +Net changes in future development costs +(29,827 +) +(41,595 +) +101,765 +Accretion of discount +65,284 +35,951 +49,434 +Timing and other +(45,712 +) +32,587 +19,122 +Total +$ +452,791 +$ +140,782 +$ +(9,169 +) +It is necessary to emphasize that the data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the recent average prices and current costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein. +101 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +QUARTERLY FINANCIAL INFORMATION - UNAUDITED +Quarterly financial data for the years ended December 31, 2011 and 2010, is presented below. The sum of the quarters may not equal the total of the year's net income or loss per share attributable to shareholders due to changes in the weighted average shares outstanding throughout the year. +2011 +Quarter Ended +March 31 +June 30 +September 30 +December 31 +Year Ended +(in thousands, except per share data) +Revenues: +Natural gas, NGL and crude oil sales +$ +58,810 +$ +65,762 +$ +72,044 +$ +79,989 +$ +276,605 +Sales from natural gas marketing +15,202 +18,897 +17,209 +15,111 +66,419 +Commodity price risk management gain (loss), net +(23,882 +) +20,537 +46,706 +2,729 +46,090 +Well operations, pipeline income and other +1,843 +1,755 +1,670 +1,578 +6,846 +Total revenues +51,973 +106,951 +137,629 +99,407 +395,960 +Costs, expenses and other: +Production costs +18,472 +16,895 +14,016 +19,702 +69,085 +Cost of natural gas marketing +14,993 +18,207 +17,227 +15,038 +65,465 +Exploration expense +1,669 +1,215 +1,135 +2,234 +6,253 +Impairment of natural gas and crude oil properties +453 +499 +531 +23,676 +25,159 +General and administrative expense +13,873 +19,509 +13,683 +14,389 +61,454 +Depreciation, depletion and amortization +30,985 +30,592 +31,523 +35,807 +128,907 +Gain on sale of properties and equipment +— +— +(32 +) +(164 +) +(196 +) +Total costs, expenses and other +80,445 +86,917 +78,083 +110,682 +356,127 +Income (loss) from operations +(28,472 +) +20,034 +59,546 +(11,275 +) +39,833 +Interest income +9 +2 +36 +— +47 +Interest expense +(9,062 +) +(9,067 +) +(9,496 +) +(9,360 +) +(36,985 +) +Income (loss) from continuing operations before income taxes +(37,525 +) +10,969 +50,086 +(20,635 +) +2,895 +Provision (benefit) for income taxes +(14,278 +) +2,804 +19,218 +(7,927 +) +(183 +) +Income (loss) from continuing operations +(23,247 +) +8,165 +30,868 +(12,708 +) +3,078 +Income from discontinued operations, net of tax +3,323 +1,000 +1,692 +4,344 +10,359 +Net income (loss) +$ +(19,924 +) +$ +9,165 +$ +32,560 +$ +(8,364 +) +$ +13,437 +Earnings (loss) per share: +Basic +Income (loss) from continuing operations +$ +(0.99 +) +$ +0.35 +$ +1.31 +$ +(0.54 +) +$ +0.13 +Income from discontinued operations +0.14 +0.04 +0.07 +0.18 +0.44 +Net income (loss) +$ +(0.85 +) +$ +0.39 +$ +1.38 +$ +(0.35 +) +$ +0.57 +Diluted +Income (loss) from continuing operations +$ +(0.99 +) +$ +0.34 +$ +1.30 +$ +(0.54 +) +$ +0.13 +Income from discontinued operations +0.14 +0.04 +0.07 +0.18 +0.43 +Net income (loss) +$ +(0.85 +) +$ +0.39 +$ +1.37 +$ +(0.35 +) +$ +0.56 +Weighted average common shares outstanding +Basic +23,428 +23,491 +23,569 +23,592 +23,521 +Diluted +23,428 +23,723 +23,783 +23,592 +23,871 +102 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +2010 +Quarter Ended +March 31 +June 30 +September 30 +December 31 +Year Ended +(in thousands, except per share data) +Revenues: +Natural gas, NGL and crude oil sales +$ +57,827 +$ +48,729 +$ +45,904 +$ +52,569 +$ +205,029 +Sales from natural gas marketing +22,687 +12,589 +18,337 +15,458 +69,071 +Commodity price risk management gain (loss), net +43,222 +12,257 +19,029 +(14,617 +) +59,891 +Well operations, pipeline income and other +2,589 +2,148 +2,157 +2,136 +9,030 +Total revenues +126,325 +75,723 +85,427 +55,546 +343,021 +Costs, expenses and other: +Production costs +14,961 +16,004 +15,925 +17,982 +64,872 +Cost of natural gas marketing +22,323 +12,207 +18,300 +15,185 +68,015 +Exploration expense +5,818 +3,274 +2,679 +1,904 +13,675 +Impairment of natural gas and crude oil properties +600 +556 +1,033 +4,292 +6,481 +General and administrative expense +10,694 +9,855 +10,426 +11,213 +42,188 +Depreciation, depletion and amortization +27,458 +26,945 +27,664 +26,028 +108,095 +Gain on sale of properties and equipment +— +(96 +) +(57 +) +(21 +) +(174 +) +Total costs, expenses and other +81,854 +68,745 +75,970 +76,583 +303,152 +Income (loss) from operations +44,471 +6,978 +9,457 +(21,037 +) +39,869 +Interest income +5 +34 +21 +11 +71 +Interest expense +(7,800 +) +(7,672 +) +(8,174 +) +(9,604 +) +(33,250 +) +Income (loss) from continuing operations before income taxes +36,676 +(660 +) +1,304 +(30,630 +) +6,690 +Provision (benefit) for income taxes +13,804 +(238 +) +(1,321 +) +(11,593 +) +652 +Income (loss) from continuing operations +22,872 +(422 +) +2,625 +(19,037 +) +6,038 +Income (loss) from discontinued operations, net of tax +797 +(2,313 +) +729 +683 +(104 +) +Net income (loss) +23,669 +(2,735 +) +3,354 +(18,354 +) +5,934 +Less: net loss attributable to noncontrolling interests +(55 +) +(6 +) +(5 +) +(214 +) +(280 +) +Net income (loss) attributable to shareholders +$ +23,724 +$ +(2,729 +) +$ +3,359 +$ +(18,140 +) +$ +6,214 +Amounts attributable to Petroleum Development Corporation shareholders: +Income (loss) from continuing operations +$ +22,927 +$ +(416 +) +$ +2,630 +$ +(18,823 +) +$ +6,318 +Income (loss) from discontinued operations, net of tax +797 +(2,313 +) +729 +683 +(104 +) +Net income (loss) attributable to shareholders +$ +23,724 +$ +(2,729 +) +$ +3,359 +$ +(18,140 +) +$ +6,214 +Earnings (loss) per share attributable to shareholders: +Basic +Income (loss) from continuing operations +$ +1.19 +$ +(0.03 +) +$ +0.14 +$ +(0.89 +) +$ +0.33 +Income (loss) from discontinued operations +0.04 +(0.12 +) +0.03 +0.03 +(0.01 +) +Net income (loss) attributable to shareholders +$ +1.23 +$ +(0.15 +) +$ +0.17 +$ +(0.86 +) +$ +0.32 +Diluted +Income (loss) from continuing operations +$ +1.19 +$ +(0.03 +) +$ +0.14 +$ +(0.89 +) +$ +0.32 +Income (loss) from discontinued operations +0.04 +(0.12 +) +0.03 +0.03 +(0.01 +) +Net income (loss) attributable to shareholders +$ +1.23 +$ +(0.15 +) +$ +0.17 +$ +(0.86 +) +$ +0.31 +Weighted average common shares outstanding +Basic +19,191 +19,213 +19,250 +21,026 +19,674 +Diluted +19,287 +19,213 +19,406 +21,026 +19,821 +103 +PETROLEUM DEVELOPMENT CORPORATION +(dba PDC Energy) +FINANCIAL STATEMENT SCHEDULE +Schedule II -VALUATION AND QUALIFYING ACCOUNTS +Description +Beginning +Balance +January 1 +Deconsolidation/Purchase Price Adjustment for PDCM +Charged to +Costs and +Expenses +Deductions (1) +Ending +Balance +December 31 +(in thousands) +2011: +Allowance for doubtful accounts +$ +686 +$ +121 +$ +135 +$ +21 +$ +921 +Valuation allowance for unproved natural gas and crude oil properties +16,996 +260 +2,611 +7,143 +12,204 +2010: +Allowance for doubtful accounts +548 +135 +307 +34 +686 +Valuation allowance for state tax benefits +747 +— +— +747 +— +Valuation allowance for unproved natural gas and crude oil properties +15,001 +19 +6,120 +4,106 +16,996 +2009: +Allowance for doubtful accounts +537 +— +120 +109 +548 +Valuation allowance for state tax benefits +— +— +747 +— +747 +Valuation allowance for unproved natural gas and crude oil properties +12,870 +— +7,279 +5,148 +15,001 +___ ____________ +(1) +For allowance for doubtful accounts, deductions represent the write-off of accounts receivable deemed uncollectible. For valuation allowance for unproved natural gas and crude oil properties, deductions represent accumulated amortization of expired or abandoned unproved natural gas and crude oil properties. For valuation allowance for state tax benefits, deductions represent expired or unutilized state tax benefits. +104 \ No newline at end of file diff --git a/raw/filings/0000077877/2011/0000077877-12-000013/filing_metadata.csv b/raw/filings/0000077877/2011/0000077877-12-000013/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..5d51e3e5b9bd4d55585d06b577a5e89d6d0833e3 --- /dev/null +++ b/raw/filings/0000077877/2011/0000077877-12-000013/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 +0000077877,PDCE,"PDC ENERGY, INC.",10-K,2012-03-01,2011-12-31,2012-03-01T13:07:08.000Z,0000077877-12-000013,petrodev-10kxfy11.htm,PDC ENERGY 2011 FORM 10-K,15184946,1,0,https://www.sec.gov/Archives/edgar/data/77877/000007787712000013/petrodev-10kxfy11.htm,https://www.sec.gov/Archives/edgar/data/77877/000007787712000013/,2011,2011,1 diff --git a/raw/filings/0000077877/2011/0000077877-12-000013/item1.txt b/raw/filings/0000077877/2011/0000077877-12-000013/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2011/0000077877-12-000013/item13.txt b/raw/filings/0000077877/2011/0000077877-12-000013/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..027429f8e3265980bb8c54deb0a423a0e2b946c5 --- /dev/null +++ b/raw/filings/0000077877/2011/0000077877-12-000013/item13.txt @@ -0,0 +1,2 @@ +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2012 Annual Stockholders' meeting and is incorporated by reference in this report. \ No newline at end of file diff --git a/raw/filings/0000077877/2011/0000077877-12-000013/item9a.txt b/raw/filings/0000077877/2011/0000077877-12-000013/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..00ef4dfe64834a6a8ba9092377c3c7a57301291a --- /dev/null +++ b/raw/filings/0000077877/2011/0000077877-12-000013/item9a.txt @@ -0,0 +1,6 @@ +ITEM 9A. CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +As of December 31, 2011 , we carried out an evaluation under the supervision and with the participation of 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 pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e). Based on the results of this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2011 . +Changes in Internal Control over Financial Reporting +During the fourth quarter of 2011 , we made no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) that have materially affected or are reasonably likely to materially affect our internal control over financial reporting. +52 \ No newline at end of file diff --git a/raw/filings/0000077877/2011/0000077877-12-000013/rp_note.txt b/raw/filings/0000077877/2011/0000077877-12-000013/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2011/0000077877-12-000013/rpt_disclosure.txt b/raw/filings/0000077877/2011/0000077877-12-000013/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..4d9b721c929eb9dadfca1aef181531100665b6c2 --- /dev/null +++ b/raw/filings/0000077877/2011/0000077877-12-000013/rpt_disclosure.txt @@ -0,0 +1,15 @@ +TRANSACTIONS WITH RELATED PERSONS +Related Transactions +From January 1, 2012 to the present, there was no transaction or series of transactions, nor is there any currently +proposed transaction, in which the amount involved exceeds $120,000, in which the Company is participant and in which any Director, executive officer, known holder of more than five percent of the Company’s common stock or any member of the +immediate family of any of the foregoing persons had or will have a direct or indirect material interest for which disclosure is required under SEC Rule S-K 404. +Policies and Procedures With Respect to Transactions with Related Persons +The Board has adopted a written policy for the review, approval and ratification of transactions that involve related parties and potential conflicts of interest. The related party transaction policy +applies to each Director and executive officer of the Company, any nominee for election as a Director, any security holder who is known to own more than five percent of the Company’s voting securities, any immediate family member of any of the +foregoing persons and any corporation, firm or association in which one or more of the Company’s Directors are directors or officers, or have a substantial financial interest. +Under our related party transaction policy, a related person transaction is a transaction or arrangement involving a +related person in which the Company is a participant or that would require disclosure in the Company’s filings with the SEC as a transaction with a related person. The related person must disclose to the Audit Committee any potential related +person transactions and must disclose all material facts with respect to such transaction and relationship. All related person transactions will be reviewed by the Audit Committee. In determining whether to approve or ratify a transaction, the Audit +Committee will consider the relevant facts and circumstances of the transaction, which may include factors such as the relationship of the related person with the Company, the materiality or significance of the transaction to the Company and the +business purpose and reasonableness of the transaction, whether the transaction is comparable to a transaction that could be available to the Company on an arms-length basis, and the impact of the transaction on the Company’s business and +operations. \ No newline at end of file diff --git a/raw/filings/0000077877/2013/0000077877-14-000013/filing.txt b/raw/filings/0000077877/2013/0000077877-14-000013/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..7269f5779fc8afed37ba9c6ccc940c0380aeafe5 --- /dev/null +++ b/raw/filings/0000077877/2013/0000077877-14-000013/filing.txt @@ -0,0 +1,7222 @@ +10-K +1 +pdce-10kxfy13.htm +PDC ENERGY 2013 FORM 10-K +PDCE-10K-FY13 +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +FORM 10-K +T 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 +£ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period from __________ to _________ +Commission File Number 000-07246 +PDC ENERGY, INC. +(Exact name of registrant as specified in its charter) +Nevada +95-2636730 +(State of incorporation) +(I.R.S. Employer Identification No.) +1775 Sherman Street, Suite 3000 +Denver, Colorado 80203 +(Address of principal executive offices) (Zip code) +Registrant's telephone number, including area code: (303) 860-5800 +Securities registered pursuant to Section 12(b) of the Act: +Title of each class +Name of each exchange on which registered +Common Stock, par value $0.01 per share +NASDAQ Global Select Market +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 T No £ +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 £ No T +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 T No £ +Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, 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 T No £ +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. £ +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 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 £ +(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 £ No T +The aggregate market value of our common stock held by non-affiliates on June 30, 2013 was $1.5 billion (based on the closing price of $51.48 per share as of the last business day of the fiscal quarter ending June 30, 2013). +As of February 7, 2014 , there were 35,754,597 shares of our common stock outstanding. +DOCUMENTS INCORPORATED BY REFERENCE +We hereby incorporate by reference into this document the information required by Part III of this Form, which will appear in our definitive proxy statement to be filed pursuant to Regulation 14A for our 2014 Annual Meeting of Stockholders. +PDC ENERGY, INC. +2013 ANNUAL REPORT ON FORM 10-K +TABLE OF CONTENTS +PART I +Page +Items 1. and 2. +Business and Properties +2 +Item 1A. +Risk Factors +17 +Item 1B. +Unresolved Staff Comments +29 +Item 3. +Legal Proceedings +29 +Item 4. +Mine Safety Disclosures +29 +PART II +Item 5. +Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities +30 +Item 6. +Selected Financial Data +32 +Item 7. +Management's Discussion and Analysis of Financial Condition and Results of Operations +33 +Item 7A. +Quantitative and Qualitative Disclosures About Market Risk +50 +Item 8. +Financial Statements and Supplementary Data +52 +Item 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +97 +Item 9A. +Controls and Procedures +97 +Item 9B. +Other Information +97 +PART III +Item 10. +Directors, Executive Officers and Corporate Governance +98 +Item 11. +Executive Compensation +98 +Item 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +98 +Item 13. +Certain Relationships and Related Transactions, and Director Independence +98 +Item 14. +Principal Accounting Fees and Services +98 +PART IV +Item15. +Exhibits, Financial Statement Schedule +98 +Signatures +101 +Glossary of Units of Measurements and Industry Terms +102 +PART I +REFERENCES TO THE REGISTRANT +Unless the context otherwise requires, references in this report to "PDC Energy," "PDC," "the Company," "we," "us," "our" or "ours" refer to the registrant, PDC Energy, Inc. and all subsidiaries consolidated for the purposes of its financial statements, including our proportionate share of the financial position, results of operations, cash flows and operating activities of our affiliated partnerships and PDC Mountaineer, LLC ("PDCM"), a joint venture currently owned 50% each by PDC and Lime Rock Partners, LP. Unless the context otherwise requires, references in this report to "Appalachian Basin" refers to our operations in the Utica Shale in Ohio and Marcellus Shale in West Virginia and Pennsylvania, including PDC's proportionate share of our affiliated partnerships' and PDCM's assets, results of operations, cash flows and operating activities. See Note 1, Nature of Operations and Basis of Presentation, to our consolidated financial statements included elsewhere in this report for a description of our consolidated subsidiaries. +GLOSSARY OF UNITS OF MEASUREMENTS AND INDUSTRY TERMS +Units of measurements and industry terms are defined in the Glossary of Units of Measurements and Industry Terms, included at the end of this report. +SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS +This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 ("Securities Act") and Section 21E of the Securities Exchange Act of 1934 ("Exchange Act") regarding our business, financial condition, results of operations and prospects. All statements other than statements of historical facts included in and incorporated by reference into this report are "forward-looking statements" within the meaning of the safe harbor provisions of the United States ("U.S.") Private Securities Litigation Reform Act of 1995. Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements herein. These statements relate to, among other things: estimated crude oil, natural gas and natural gas liquids (“NGLs”) reserves; future production (including the components of such production), sales, expenses, cash flows and liquidity; our evaluation method of our customers' and derivative counterparties' credit risk is appropriate and consistent with those used by other market participants; anticipated capital projects, expenditures and opportunities; future exploration, drilling and development activities; our drilling programs and number of locations; expected timing of additional drilling rigs in the Wattenberg Field and Utica Shale; availability of additional midstream facilities and services, timing of that availability and related benefits to us; availability of sufficient funding for our 2014 capital program and sources of that funding; expected 2014 capital budget allocations; acquisitions of additional Utica Shale acreage; expected use of the remaining net proceeds from our August 2013 equity offering; the impact of high line pressures; compliance with debt covenants; expected funding sources for conversion of our 3.25% convertible senior notes due 2016; compliance with government regulations; potential future transactions; the borrowing base under our credit facility; impact of litigation on our results of operations and financial position; effectiveness of our derivative program in providing a degree of price stability; that we do not expect to pay dividends in the foreseeable future; and our future strategies, plans and objectives. +The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Consequently, forward-looking statements are inherently subject to risks and uncertainties, including known and unknown risks and uncertainties incidental to the exploration for, and the acquisition, development, production and marketing of crude oil, natural gas and NGLs, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements. +Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to: +• +changes in worldwide production volumes and demand, including economic conditions that might impact demand; +• +volatility of commodity prices for crude oil, natural gas and NGLs; +• +the impact of governmental policies and/or regulations, including changes in environmental and other laws, the interpretation and enforcement related to those laws and regulations, liabilities arising thereunder and the costs to comply with those laws and regulations; +• +potential declines in the value of our crude oil, natural gas and NGLs properties resulting in impairments; +• +changes in estimates of proved reserves; +• +inaccuracy of reserve estimates and expected production rates; +• +potential for production decline rates from our wells being greater than expected; +• +timing and extent of our success in discovering, acquiring, developing and producing reserves; +• +our ability to secure leases, drilling rigs, supplies and services at reasonable prices; +• +availability of sufficient pipeline, gathering and other transportation facilities and related infrastructure to process and transport our production, particularly in the Wattenberg Field and the Utica Shale, and the impact of these facilities and regional capacity on the prices we receive for our production; +• +timing and receipt of necessary regulatory permits; +• +risks incidental to the drilling and operation of crude oil and natural gas wells; +• +our future cash flows, liquidity and financial condition; +• +competition within the oil and gas industry; +1 +• +availability and cost of capital; +• +reductions in the borrowing base under our revolving credit facility; +• +our success in marketing crude oil, natural gas and NGLs; +• +effect of natural gas and crude oil derivatives activities; +• +impact of environmental events, governmental and other third-party responses to such events, and our ability to insure adequately against such events; +• +cost of pending or future litigation; +• +effect that acquisitions we may pursue have on our capital expenditures; +• +our ability to retain or attract senior management and key technical employees; and +• +success of strategic plans, expectations and objectives for our future operations. +Further, we urge you to carefully review and consider the cautionary statements and disclosures, specifically those under Item 1A, Risk Factors , made in this report and our other filings with the U.S. Securities and Exchange Commission ("SEC") for further information on risks and uncertainties that could affect our business, financial condition, results of operations and cash flows. We caution you not to place undue reliance on forward-looking statements, which speak only as of the date of this report. We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. All forward-looking statements are qualified in their entirety by this cautionary statement. +ITEMS 1. AND 2. BUSINESS AND PROPERTIES +The Company +We are a domestic independent exploration and production company that produces, develops, acquires and explores for crude oil, natural gas and NGLs with primary operations in the Wattenberg Field in Colorado, the Utica Shale in southeastern Ohio and the Appalachia-Marcellus Shale in northern West Virginia. Our operations in the Wattenberg Field are focused on the liquid-rich horizontal Niobrara and Codell plays. We are currently focusing our Ohio development activity in the liquid-rich portion of the Utica Shale play and are pursuing horizontal development in the Marcellus Shale in West Virginia through our 50% joint venture interest in PDCM. We own an interest in approximately 3,100 gross producing wells, of which 249 are horizontal. Production of 7.4 MMboe from continuing operations for the year ended December 31, 2013 represents an increase of 35% compared to the year ended December 31, 2012 . For the month ended December 31, 2013 , we maintained an average production rate of 27 MBoe per day. As of December 31, 2013 , we had approximately 266 MMBoe of proved reserves with a pre-tax present value of future net revenues (“PV-10”) of $2.7 billion , representing an increase of 73 MMBoe and $1.0 billion , respectively, relative to the totals as of December 31, 2012 . The percentage of our proved reserves represented by crude oil and NGLs rose to 54% as of December 31, 2013 , up from 48% as of December 31, 2012 . PV-10 is not a financial measure under Accounting Principles Generally Accepted in the United States of America (“U.S. GAAP”). See Part I, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Reconciliation of Non-U.S. GAAP Financial Measures, for a definition of PV-10 and a reconciliation of our PV-10 value to our standardized measure. +The increase in our estimated proved reserves and production is primarily attributable to our successful horizontal Niobrara and Codell drilling program in the Wattenberg Field. Future development of the Wattenberg Field provides the opportunity to add further proved, probable and possible ("3P") reserves to our portfolio through continued delineation and downspacing of the horizontal Niobrara and Codell formations. Recently, we completed and are producing from our first 16 horizontal wells per section downspacing project in the Wattenberg Field. In 2013, we spudded 70 horizontal wells in the Wattenberg Field, 54 of which were completed, and participated in 49 gross, 10.4 net, horizontal non-operated drilling projects. Our year-end 2013 proved reserves include reserves associated with our Utica Shale properties, where we have acquired approximately 48,000 net acres. We spudded 11 horizontal Utica wells in 2013, nine of which were completed and connected to a gathering line. PDCM spudded 14 horizontal Marcellus wells in 2013, 10 of which were completed as of year-end. +The following table presents our proved reserve estimates as of December 31, 2013 based on a reserve report prepared by Ryder Scott Company, L.P. (“Ryder Scott”), our independent petroleum engineering consulting firm: +Proved Reserves at December 31, 2013 +Proved Reserves (MMBoe) +% of Total Proved Reserves +% Proved Developed +% Liquids +Proved Reserves to Production Ratio (in years) +Production (MBoe) +Wattenberg Field +212 +79.7 +% +29.7 +% +64.0 +% +35.7 +5,938 +Utica Shale +14 +5.4 +% +23.8 +% +48.6 +% +63.8 +225 +Appalachia-Marcellus Shale +40 +14.9 +% +23.3 +% +— +% +31.2 +1,266 +Total proved reserves +266 +100.0 +% +28.4 +% +53.6 +% +35.8 +7,430 +2 +Our Strengths +• +Multi-year project inventory in premier crude oil, natural gas and NGLs plays. We have a significant operational presence in three key U.S. onshore basins and have identified a substantial inventory of approximately 3,600 gross horizontal drilling projects, as well as a substantial number of refracture and recompletion opportunities. This inventory of horizontal drilling projects includes approximately 2,800 projects in the Wattenberg Field, 200 projects in the Utica Shale and 600 projects in the Marcellus Shale. +• +Track record of reserve and production growth. Our proved reserves have grown from 55 MMBoe at December 31, 2008 to approximately 266 MMBoe at December 31, 2013 , representing a compound annual growth rate (“CAGR”) of 37%. During the same time period, our proved crude oil and NGL reserves grew at a CAGR of 57%. Our annual production from continuing operations grew from 3.2 MMBoe in 2008 to 7.4 MMBoe in 2013, representing a CAGR of 18%. +• +Horizontal drilling and completion experience. We have a proven track record of applying technical expertise toward developing unconventional resources through horizontal drilling and completion operations, having drilled or participated in 249 horizontal wells, including 144 horizontal wells during the year ending December 31, 2013 . We have transitioned to multi-well pad drilling to further optimize costs and enhance horizontal drilling efficiencies. Pad drilling enables us to streamline the transition to increased well density in all our horizontal plays. +• +Access to liquidity. As of December 31, 2013 , we had a total liquidity position of $647.0 million , comprised of $193.2 million of cash and cash equivalents and $453.8 million available for borrowing under revolving credit facilities. In August 2013, we completed a public offering of 5,175,000 shares of our common stock, at a price to us of $53.37 per share, for net proceeds of approximately $276 million , after deducting offering expenses and underwriting discounts. We expect to use the remaining net proceeds from the offering to fund a portion of our 2014 capital program and for general corporate purposes. We have no near-term debt maturities and have had no draws on our revolving credit facility since June 2013. +• +Cash flow management through commodity derivative instruments. We actively hedge our future exposure to commodity price fluctuations by entering into oil and natural gas swaps, collars and basis protection swaps to the extent possible. As of December 31, 2013 , we have hedged approximately 4,112 MBbls of our crude oil production for 2014 at a weighted-average minimum price of $89.06 per Bbl and a weighted-average maximum price of $94.01 per Bbl. As of December 31, 2013 , we have hedged approximately 20 Bcf of our natural gas production in 2014 at a weighted-average minimum price of $ 4.03 per Mcf. +• +Significant operational control in our core areas. As a result of successfully executing our strategy over time of acquiring largely concentrated acreage positions with a high working interest, we operate and manage approximately 91% of the wells in which we have an interest. Our high percentage of operated properties enables us to exercise a significant level of control with respect to drilling, production, operating and administrative costs, in addition to leveraging our base of technical expertise in our core operating areas. +• +Management experience and operational expertise. We have a management team with a proven track record of drilling performance and a technical and operational staff with significant expertise in the basins in which we operate, particularly in horizontal drilling, completion and production activities. +Business Strategy +Our long-term business strategy focuses on generating shareholder value through the acquisition, exploration and development of crude oil and natural gas properties; we are currently focused on the organic growth of our reserves, production and cash flows in our high-value, horizontal drilling programs after having completed multiple transactions to restructure and simplify our property portfolio over the last several years. Additionally, we pursue various midstream, marketing and cost reduction initiatives designed to increase our per unit operating margins and we maintain a conservative and disciplined financial strategy focused on providing sufficient liquidity and balance sheet strength to execute our business strategy. +Development drilling +Our leasehold interests consist of developed and undeveloped crude oil, natural gas and NGLs resources. Based upon our current acreage holdings, we have identified a substantial inventory of approximately 3,600 gross capital projects for horizontal development, primarily in high-return, liquid-rich plays. We have established a capital budget of $631 million for 2014 for drilling in the Wattenberg Field and the Utica Shale and for other miscellaneous projects. Additionally, PDCM has established a capital budget for the Marcellus Shale, of which $16 million is our proportionate share. +Wattenberg Field . Our primary focus in the Wattenberg Field is drilling in the horizontal Niobrara and Codell plays. We have transitioned to multi-well pad drilling to further optimize costs and enhance horizontal drilling efficiencies in the field. Depending upon commodity prices and the number of drilling rigs operating, we believe that our inventory of approximately 2,800 gross 3P horizontal projects in the field, together with refracturing and vertical Codell well opportunities, provides us with over 20 years of drilling activity. Approximately $467 million of our 2014 capital budget is expected to be spent on development activities in the field, the majority of which is expected to be invested in an expanded horizontal Niobrara and Codell drilling program. We plan to run a four-rig program through the first quarter of 2014 and add a fifth drilling rig during the second quarter. Approximately $100 million of the total Wattenberg Field capital budget is allocated for non-operated horizontal drilling projects. We expect to drill and operate approximately 115 horizontal Niobrara or Codell wells and expect to participate in approximately +3 +75 to 100 non-operated horizontal opportunities in 2014. +Utica Shale . We continue to delineate and develop our leasehold position in the Utica Shale. We currently estimate that we have approximately 200 gross projects for horizontal drilling in the Utica Shale and have spudded 13 horizontal wells through December 31, 2013 . We are currently running a one-rig program in the Utica Shale and plan on adding a second drilling rig during the second half of 2014. In 2014, we expect to devote approximately $162 million of our 2014 capital program toward drilling and completion activity and acquisition of additional acreage in the Utica Shale. We plan to drill 18 horizontal wells targeting the wet gas and condensate windows of the play in 2014. +Appalachia-Marcellus Shale. In 2013, PDCM drilled 14 gross (7 net) and completed 10 gross (5 net) horizontal wells in the Marcellus Shale and constructed various midstream assets to gather and compress its Marcellus gas. We currently estimate that we have approximately 600 gross projects for horizontal drilling in the Marcellus Shale. PDCM has elected to temporarily suspend drilling activities in the Marcellus Shale. In 2014, PDCM currently expects to focus on completion operations on the remaining four horizontal wells that were in-process as of December 31, 2013 and on the continued development of midstream infrastructure. +Strategic acquisitions +We typically pursue the acquisition of assets that have a balance of value in producing wells, behind-pipe reserves and high-quality undeveloped drilling locations. We seek liquid-rich properties with large undeveloped drilling upside where we believe we can utilize our operational abilities to add shareholder value. We have an experienced team of management, engineering, geosciences and commercial professionals who identify and evaluate acquisition opportunities. +Wattenberg Field. In June 2012, we acquired certain assets from affiliates of Merit Energy (the "Merit Acquisition") for an aggregate purchase price of $304.6 million . The acquired assets comprise approximately 30,000 net acres located almost entirely in the core Wattenberg Field and in close proximity to our then-existing acreage position. Following the closing of the Merit Acquisition, our total position in the core Wattenberg Field is now approximately 97,000 net acres. +Utica Shale. Since 2011, we have acquired approximately 48,000 net acres of Utica leaseholds, targeting the crude oil and wet natural gas windows of the Utica Shale play throughout southeastern Ohio. As an early entrant into the development of the Utica Shale, we believe we have gained valuable experience and expertise in proactively addressing title and other issues associated with the development of the play. +Appalachia-Marcellus Shale. In October 2011, PDCM acquired 100% of the membership interests of Seneca-Upshur Petroleum, LLC ("Seneca-Upshur”) for $139.2 million , of which our proportionate share was $69.6 million . The acquisition included approximately 1,340 gross wells producing natural gas from the shallow Upper Devonian Shale formation and all rights and depths to an estimated 100,000 net acres in West Virginia, of which 90,000 acres are prospective for the Marcellus Shale. +Strategic divestitures +We continue to seek ways to optimize our asset portfolio as part of our business strategy. This may include divesting lower return assets and reinvesting in our stronger economic inventory. As a result, we have divested several assets over the past few years. +Colorado Dry Gas Assets. In June 2013, we completed the sale of our non-core Colorado dry gas assets, primarily natural gas producing properties located in the Piceance Basin, northeastern Colorado and other non-core areas, to certain affiliates of Caerus Oil and Gas LLC (“Caerus”) for consideration of $177.6 million , with an additional $17 million paid to our non-affiliated investor partners in our affiliated partnerships. The sale resulted in a pre-tax loss of $2.3 million. The proceeds from the asset disposal were used to pay down our revolving credit facility and to fund a portion of our 2013 capital budget. +Appalachian Shallow Upper Devonian Gas Assets. In October 2013, we executed a purchase and sale agreement for the sale of substantially all our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin crude oil and natural gas properties owned directly by us, as well as through our proportionate share of PDCM. The properties consisted of approximately 3,500 gross shallow producing wells, related facilities and associated leasehold acreage, limited to the Upper Devonian and shallower formations. Substantially all of the divestiture closed in December 2013 for aggregate consideration of approximately $20.6 million , of which our share of the proceeds was approximately $5.1 million , subject to certain post-closing adjustments. Concurrent with the closing of the transaction, our $6.7 million irrevocable standby letter of credit and an agreement for firm transportation services were released and novated to the buyer. We retained all zones, formations and intervals below the Upper Devonian formation, including the Marcellus Shale, Utica Shale and Huron Shale, as well as all Marcellus-related midstream assets. +Permian Basin. During the fourth quarter of 2011, we completed the sale of certain non-core Permian assets for a total of $13.2 million . In December 2011, we executed a purchase and sale agreement with a subsidiary of Concho Resources Inc. (“COG”), for the sale of our remaining Permian Basin assets and closed the transaction in February 2012. Total proceeds received were $189.2 million . +Operational and financial risk management +We focus on horizontal development drilling programs in resource plays that offer repeatable results capable of driving growth in reserves, production and cash flows. We periodically review acquisition opportunities in our core areas of operation as we believe we can extract additional value from such assets through production optimization, refracturing, recompletions and development drilling. In addition, core +4 +acquisitions can potentially provide synergies that result in economies of scale from a combined position. While we believe development drilling will remain the foundation of our capital programs, we expect to continue our disciplined approach to acquisitions and exploratory drilling. +We proactively employ strategies to help reduce the financial risks associated with our industry. One such strategy is to maintain a balanced production mix of liquids and natural gas. During 2013, we produced crude oil, natural gas and NGLs with a production mix of approximately 53% liquids and 47% natural gas. This strategy of a diversified commodity mix helps mitigate the financial impact from a decline in the market price of any one of our commodities. In addition, we utilize commodity-based derivative instruments to manage a substantial portion of our exposure to price volatility with regard to our crude oil and natural gas sales and natural gas marketing. As of December 31, 2013 , we had natural gas and crude oil derivative positions in place for 2014 covering approximately 4,112 MBbls of our crude oil production and approximately 20 Bcf of our natural gas production. Currently, we do not hedge our NGL production. See Part II, Item 7A , Quantitative and Qualitative Disclosures About Market Risk, for a detailed summary of our open derivative positions. +Selective exploration +Historically, we have pursued a disciplined exploration program intended to replenish our portfolio and to position us for production and reserve growth in future years. Our efforts have focused on liquid-rich plays to take advantage of the attractive economics associated with crude oil and NGL-weighted projects. We have attempted to identify potential plays in their early stages in order to accumulate significant leasehold positions prior to competitive forces driving up the cost of entry and to invest in leasehold positions that were in the proximity of existing or emerging midstream infrastructure. The Utica Shale was our primary exploration focus during the past few years. Our operations in the Utica Shale have now shifted to developmental drilling and delineation. We do not expect significant exploration activity in 2014, as our main focus is expected to be on organic growth through developmental drilling. +Business Segments +We divide our operating activities into two segments: (1) Oil and Gas Exploration and Production and (2) Gas Marketing. +Oil and Gas Exploration and Production +Our Oil and Gas Exploration and Production segment primarily reflects revenues and expenses from the production and sale of crude oil, natural gas and NGLs. The prices we receive for our crude oil, natural gas and NGLs vary based on the terms of applicable purchase contracts. +• +Crude oil . We do not refine any of our crude oil production. In the Wattenberg Field, crude oil is sold at each individual well site and transported by the purchasers via truck, pipeline or rail to local and non-local markets under various purchase contracts with monthly pricing provisions based on a differential to the average monthly NYMEX price. In the Utica Shale, crude oil and condensate is sold to local purchasers at each individual well site based on a differential to the average monthly NYMEX price and is typically transported by the purchasers via truck to local refineries, rail facilities or barge loading terminals on the Ohio River. We currently have no long-term firm transportation agreements related to our crude oil production. +• +Natural gas . We primarily sell our natural gas to midstream service providers, marketers, utilities, industrial end-users and other wholesale purchasers. We generally sell the natural gas that we produce under contracts with indexed or NYMEX monthly pricing provisions, with the remaining production sold under contracts with daily pricing provisions. Virtually all of our contracts include provisions whereby prices change monthly with changes in the market, with certain adjustments that may be made based on whether a well delivers to a gathering or transmission line and the quality of the natural gas. Therefore, the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. In certain instances, we enter into firm transportation, processing and sales agreements to provide for pipeline capacity to flow and sell a portion of our natural gas volumes. In some cases, in order to meet pipeline specifications, our natural gas must be processed before we can transport it. We also have interruptible transportation agreements in place in certain areas where adequate transportation capacity is believed to be available. We may also enter into firm sales agreements to ensure that we are selling to a purchaser who has contracted for pipeline capacity. See Note 11, Commitments and Contingencies - Firm Transportation, Processing and Sales Agreements , to our consolidated financial statements included elsewhere in this report for a discussion of our long-term firm sales, processing and transportation agreements for pipeline capacity. In the Wattenberg Field, the majority of our leasehold is dedicated to our primary midstream provider, DCP Midstream, which gathers and processes wet natural gas produced in the basin and sells our residue gas to various markets. In the Utica Shale, wet natural gas produced in our northern acreage is gathered and processed pursuant to a firm transportation agreement with Markwest Utica EMG while wet natural gas produced in our southern acreage is gathered and processed by Blue Racer Midstream LLC. We market our Utica residue gas to various purchasers based on pipeline basis or NYMEX pricing. In the Appalachia-Marcellus Shale, our dry natural gas is gathered and transported to a market hub pursuant to a firm transportation agreement with Equitrans LP and an interruptible agreement with Momentum. We sell the dry natural gas to various marketers at a price primarily based on spot gas delivered to the Texas Eastern Transmission pipeline M-2 point, less transportation costs. +• +NGLs . We produce NGLs in the Wattenberg Field and Utica Shale. In the Wattenberg Field, the majority of our NGLs are sold at the tailgate of DCP Midstream processing plants based on prices of NGL deliveries to the Conway hub in Kansas. In the Utica Shale, the majority of our NGLs are fractionated and marketed by Markwest Utica EMG and Blue Racer Midstream LLC and +5 +sold based on month-to-month pricing in various markets. Our NGL production is sold under both short- and long-term purchase contracts. +We enter into financial derivatives in order to reduce the impact of possible price volatility regarding the physical sales market. See Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations: Results of Operations - Commodity Price Risk Management, Net, Natural Gas and Crude Oil Derivative Activities , Item 7A, Quantitative and Qualitative Disclosures about Market Risk, and Note 4, Derivative Financial Instruments , to our consolidated financial statements included elsewhere in this report. +Our Oil and Gas Exploration and Production segment also reflects revenues and expenses related to well operations and pipeline services. We are paid a monthly operating fee for the portion of each well we operate that is owned by others, including our affiliated partnerships. We believe the fee is competitive with rates charged by other operators in the area. As we acquire the working interest of our non-affiliated investor partners in our affiliated partnerships, revenues related to well operations and pipeline services will decrease. +We construct, own and operate gathering systems in our Appalachia-Marcellus Shale operations. Pipelines and related facilities can represent a significant portion of the capital costs of developing wells, particularly in new areas located at a distance from existing pipelines. We consider these costs in the evaluation of our leasing, development and acquisition opportunities. +Our natural gas is transported through our own and third-party gathering systems and pipelines and we incur gathering, processing and transportation expenses to move our natural gas from the wellhead to a purchaser-specified delivery point. These expenses vary based upon the volume and distance shipped, as well as the fee charged by the third-party processor or transporter. Like most producers, we rely on our third-party midstream service providers to construct compression, gathering and processing facilities to keep pace with our production growth. As a result, the timing and availability of additional facilities going forward is beyond our control. Capacity on these gathering systems and pipelines is occasionally reduced due to operational issues, repairs or improvements. A portion of our natural gas is transported under interruptible contracts and the remainder under firm transportation agreements, either directly with our subsidiary Riley Natural Gas ("RNG"), or through third-party processors or marketers. Therefore, interruptions in natural gas sales could result if pipeline space is constrained. Our Wattenberg Field production was adversely impacted by high line pressures on the gathering system operated by DCP Midstream during the spring and summer months of 2012 and 2013. We, and other operators in the field, are working closely with DCP Midstream in the Wattenberg Field, which is implementing a multi-year facility expansion program. The program is increasing midstream system capacity and helping to mitigate the impact of increased production volumes on system pressures. Although we expect system pressures to fluctuate and constrain production from time to time, we believe that this expansion will provide the additional gathering and processing capacity in the system necessary to increase our confidence that we can continue to produce and market our production. +See Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations, Summary Operating Results, for production, sales, pricing and lifting cost data. +Gas Marketing +Our Gas Marketing segment is comprised solely of the operating activities of RNG. RNG specializes in the purchase, aggregation and sale of natural gas production in the Utica Shale and Appalachia-Marcellus Shale. RNG purchases for resale natural gas produced by third-party producers, as well as natural gas produced by us and PDCM. The natural gas is marketed to third-party marketers, natural gas utilities and industrial and commercial customers, either directly through our gathering system or through transportation services provided by regulated interstate/intrastate pipeline companies. +For additional information regarding our business segments, see Note 17, Business Segments , to our consolidated financial statements included elsewhere in this report. +6 +Areas of Operations +The following map presents the general locations of our development and production activities as of December 31, 2013 . +• +Wattenberg Field area, DJ Basin, Colorado. Currently, horizontal wells drilled in this area target the reservoirs in the Codell and Niobrara formations where we have acquired approximately 97,000 net acres. These horizontal wells have a vertical depth ranging from approximately 6,500 to 7,500 feet, with lateral lengths of approximately 4,000 to 5,000 feet. Pad drilling enables us to streamline the transition to increased well density in the horizontal Niobrara and Codell plays and optimize costs. We currently estimate that we have 2,800 gross horizontal capital projects in the Wattenberg Field in inventory, as well as other refracture and vertical Codell well opportunities. +• +Utica Shale area, southeastern Ohio. Wells drilled in this area primarily target the Point Pleasant member of the Utica Shale formation. We have acquired approximately 48,000 net acres targeting the condensate and wet natural gas windows of the Utica Shale play throughout southeastern Ohio and we currently estimate that we have approximately 200 gross projects for horizontal drilling in the Utica Shale. The horizontal wells have a vertical depth ranging from approximately 7,000 to 8,000 feet, with lateral lengths of approximately 4,000 to 7,500 feet. +• +Appalachia-Marcellus Shale area, West Virginia. Wells drilled in this area are primarily horizontal wells targeting the Marcellus Shale. PDCM has approximately 66,000 net acres prospective for the Marcellus Shale. PDCM is primarily focused on horizontal drilling and has approximately 600 gross Marcellus Shale drilling locations on the West Virginia acreage. These horizontal wells have a vertical depth ranging from approximately 7,000 to 8,000 feet, with lateral lengths of approximately 4,000 to 6,500 feet. +In December 2013, PDCM closed on a transaction pursuant to which substantially all of the wells producing from the shallow Upper Devonian Shale formation (non-Marcellus Shale) were sold. +Properties +Productive Wells +The following table presents our productive wells: +Productive Wells +As of December 31, 2013 +Crude Oil +Natural Gas +Total +Operating Region/Area +Gross +Net +Gross +Net +Gross +Net +Wattenberg Field +207 +138.1 +2,497 +2,156.7 +2,704 +2,294.8 +Utica Shale +10 +7.7 +3 +3.0 +13 +10.7 +Appalachia-Marcellus Shale +— +— +374 +140.5 +374 +140.5 +Total productive wells +217 +145.8 +2,874 +2,300.2 +3,091 +2,446.0 +7 +Proved Reserves +Our proved reserves are sensitive to future crude oil, natural gas and NGLs sales prices and the related effect on the economic productive life of producing properties. Increases in commodity prices may result in a longer economic productive life of a property or result in recognition of more economically viable proved undeveloped reserves. Decreases in commodity prices may result in negative impacts of this nature. +All of our proved reserves are located onshore in the U.S. Our proved reserve estimates are prepared using the definitions for proved reserves set forth in SEC Regulation S-X, Rule 4-10(a) and applicable SEC staff regulations, interpretations and guidance. As of December 31, 2013 , all of our proved reserves, including the reserves of all subsidiaries consolidated for the purposes of our financial statements, have been estimated by Ryder Scott. +We have a comprehensive process that governs the determination and reporting of our proved reserves. As part of our internal control process, our reserves are reviewed annually by an internal team composed of reservoir engineers, geologists and accounting personnel for adherence to SEC guidelines through a detailed review of land records, available geological and reservoir data, as well as production performance data. The process includes a review of applicable working and net revenue interests and cost and performance data. The internal team compiles the reviewed data and forwards the data to the independent engineering firm engaged to estimate our reserves. +Our proved reserve estimates as of December 31, 2013 were based on a reserve report prepared by Ryder Scott. When preparing our reserve estimates, Ryder Scott did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, production volumes, well test data, historical costs of operations and development, product prices or any agreements relating to current and future operations of properties and sales of production. +Ryder Scott prepares an estimate of our reserves in conjunction with an ongoing review by our engineers. A final comparison of data is performed to ensure that the reserve estimates are complete, determined pursuant to acceptable industry methods and with a level of detail we deem appropriate. The final estimated reserve report is reviewed by our engineering staff and management prior to issuance by Ryder Scott. +The professional qualifications of the internal lead engineer primarily responsible for overseeing the preparation of our reserve estimates qualify the engineer as a Reserves Estimator, as defined in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information as promulgated by the Society of Petroleum Engineers. This position is currently being held by an employee who holds a Bachelor of Science degree in Petroleum and Chemical Refining Engineering with a minor in Petroleum Engineering, has over 36 years of experience in reservoir engineering, is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers and is a registered Professional Engineer in the State of Colorado. +The SEC's reserve rule has expanded the technologies that a registrant may use to establish reserves. The SEC now allows use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. +All of our proved undeveloped reserves conform to the SEC five-year rule requirement as all proved undeveloped locations are scheduled, according to an adopted development plan, to be drilled within five years of each location’s initial booking date. +We used a combination of production and pressure performance, wireline wellbore measurements, offset analogies, seismic data and interpretation, wireline formation tests, geophysical logs and core data to calculate our reserve estimates, including the material additions to the 2013 reserve estimates. +Reserve estimates involve judgments and cannot be measured exactly. The estimates must be reviewed periodically and adjusted to reflect additional information gained from reservoir performance, new geological and geophysical data and economic changes. Neither the estimated future net cash flows nor the standardized measure of discounted future net cash flows ("standardized measure") is intended to represent the current market value of our proved reserves. For additional information regarding both of these measures, as well as other information regarding our proved reserves, see the unaudited Supplemental Information - Crude Oil and Natural Gas Information provided with our consolidated financial statements included elsewhere in this report. The following tables provide information regarding our estimated proved reserves: +8 +As of December 31, +2013 +2012 (3)(4) +2011 (3)(4)(5) +Proved reserves +Crude oil and condensate (MMBbls) +94 +59 +38 +Natural gas (Bcf) +740 +604 +672 +NGLs (MMBbls) +49 +33 +20 +Total proved reserves (MMBoe) +266 +193 +169 +Proved developed reserves (MMBoe) +76 +82 +79 +Estimated future net cash flows (in millions) (1) +$ +4,323 +$ +2,756 +$ +2,290 +PV-10 ( in millions) (2) +$ +2,704 +$ +1,709 +$ +1,350 +Standardized measure (in millions) +$ +1,782 +$ +1,168 +$ +941 +___________ +(1) +Amount represents undiscounted pre-tax future net cash flows estimated by Ryder Scott of approximately $6.4 billion , $4.0 billion and $3.2 billion as of December 31, 2013 , 2012 and 2011 , respectively, less an internally estimated future income tax expense of approximately $2.1 billion , $1.2 billion and $0.9 billion , respectively. +(2) +PV-10 is a non-U.S. GAAP financial measure. This non-U.S. GAAP measures is not a measure of financial or operating performance under U.S. GAAP and it is not intended to represent the current market value of our estimated reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure reported in accordance with U.S. GAAP, but rather should be considered in addition to the standardized measure. See Part I, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Reconciliation of Non-U.S. GAAP Financial Measures, for a definition of PV-10 and a reconciliation of our PV-10 value to the standardized measure. +(3) +Includes estimated reserve data related to our Piceance and NECO assets which were divested in June 2013. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of our Piceance and NECO assets. +The following table sets forth information regarding estimated proved reserves for our Piceance and NECO assets: +As of December 31, +2012 +2011 +Proved reserves +Crude oil and condensate (MMBbls) +0.1 +0.4 +Natural gas (Bcf) +84 +354 +Total proved reserves (MMBoe) +14 +59 +Proved developed reserves (MMBoe) +14 +24 +Estimated future net cash flows (in millions) +$ +43 +$ +32 +(4) +Includes estimated reserve data related to our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin crude oil and natural gas properties, which were divested in December 2013. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to these assets. +The following table sets forth information regarding estimated proved reserves for our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin crude oil and natural gas properties: +As of December 31, +2012 +2011 +Proved reserves +Natural gas (Bcf) +11 +20 +Total proved reserves (MMBoe) +2 +3 +Proved developed reserves (MMBoe) +2 +3 +Estimated future net cash flows (in millions) +$ +3 +$ +15 +9 +(5) +Includes estimated reserve data related to our Permian assets, which were classified as held for sale as of December 31, 2011 and divested in February 2012. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of our Permian assets. +The following table sets forth information regarding estimated proved reserves for our Permian assets: +December 31, 2011 +Proved reserves +Crude oil and condensate (MMBbls) +8 +Natural gas (Bcf) +6 +NGLs (MMBbls) +2 +Total proved reserves (MMBoe) +11 +Proved developed reserves (MMBoe) +3 +Estimated future net cash flows (in millions) +$ +348 +The following table presents our estimated proved developed and undeveloped reserves as of December 31, 2013 : +As of December 31, 2013 +Operating Region/Area +Crude Oil and Condensate (MBbls) +Natural Gas +(MMcf) +NGLs +(MBbls) +Crude Oil +Equivalent +(MBoe) +Percent +Proved developed +Wattenberg Field +22,611 +155,797 +14,360 +62,937 +83 +% +Utica Shale +1,385 +9,412 +465 +3,419 +5 +% +Appalachia-Marcellus Shale +1 +55,178 +— +9,197 +12 +% +Total proved developed +23,997 +220,387 +14,825 +75,553 +100 +% +Proved undeveloped +Wattenberg Field +66,481 +302,272 +32,073 +148,933 +78 +% +Utica Shale +3,352 +34,936 +1,773 +10,947 +6 +% +Appalachia-Marcellus Shale +— +182,045 +— +30,341 +16 +% +Total proved undeveloped +69,833 +519,253 +33,846 +190,221 +100 +% +Proved reserves +Wattenberg Field +89,092 +458,069 +46,433 +211,870 +80 +% +Utica Shale +4,737 +44,348 +2,238 +14,366 +5 +% +Appalachia-Marcellus Shale +1 +237,223 +— +39,538 +15 +% +Total proved reserves +93,830 +739,640 +48,671 +265,774 +100 +% +Developed and Undeveloped Acreage +The following table presents our developed and undeveloped lease acreage: +As of December 31, 2013 +Developed +Undeveloped (1) +Total +Operating Region/Area +Gross +Net +Gross +Net +Gross +Net +Wattenberg Field +99,000 +88,700 +9,300 +7,900 +108,300 +96,600 +Utica Shale +2,400 +2,000 +50,300 +45,900 +52,700 +47,900 +Appalachia-Marcellus Shale +147,250 +60,250 +12,800 +5,250 +160,050 +65,500 +Total acreage +248,650 +150,950 +72,400 +59,050 +321,050 +210,000 +__________ +(1) +With the exception of our properties prospective for the Utica Shale, substantially all of our undeveloped acreage is related to leaseholds that are held by production. Approximately 3% , 5.6% and 16.5% of our undeveloped leaseholds expire during 2014, 2015 and 2016, respectively. +10 +Drilling Activity +The following table presents information regarding the number of wells drilled or participated in and the number of wells for which refractures and/or recompletions were performed: +Drilling Activity +Year Ended December 31, +2013 +2012 +2011 +Operating Region +Gross +Net +Gross +Net +Gross +Net +Wattenberg Field +119 +69.2 +57 +39.0 +145 +99.6 +Utica Shale +11 +9.2 +3 +2.5 +1 +0.8 +Appalachia-Marcellus Shale +14 +7.0 +3 +1.5 +6 +2.9 +Other (1)(2) +— +— +— +— +43 +41.5 +Total wells drilled +144 +85.4 +63 +43.0 +195 +144.8 +Refractures and recompletions (3) +5 +4.1 +85 +79.9 +192 +177.6 +__________ +(1) +Includes drilling activity in Piceance and NECO operating regions, which were divested in June 2013. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of our Piceance and NECO assets. +(2) +Includes drilling activity in the Permian Basin operating region, which were divested in February 2012. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of our Permian assets. +(3) +Substantially all of the refractures and recompletions occurred in the Wattenberg Field. +The following tables set forth our developmental and exploratory well drilling activity. There is no correlation between the number of productive wells completed during any period and the aggregate reserves attributable to those wells. Productive wells consist of wells spudded, turned-in-line and producing during the period. In-process wells represent wells that are in the process of being drilled or have been drilled and are waiting to be fractured and/or for gas pipeline connection as of the date shown. +Net Development Well Drilling Activity +Year Ended December 31, +2013 +2012 +2011 +Operating Region/Area +Productive +In-Process (3) +Dry +Productive +In-Process +Dry +Productive +In-Process +Dry +Wattenberg Field +53.5 +15.6 +0.1 +31.3 +7.7 +— +86.5 +13.1 +— +Utica Shale +3.0 +2.0 +— +— +— +— +— +— +— +Appalachia-Marcellus Shale +3.5 +2.0 +— +1.5 +— +— +0.9 +2.0 +— +Other (1)(2) +— +— +— +— +— +— +28.5 +8.5 +2.0 +Total net development wells +60.0 +19.6 +0.1 +32.8 +7.7 +— +115.9 +23.6 +2.0 +__________ +(1) +Our Piceance and NECO assets were divested in June 2013. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of our Piceance and NECO assets. +(2) +As of December 31, 2011, our Permian assets were held for sale and subsequently divested in February 2012. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of our Permian assets. +(3) +On a gross basis, wells in-process as of December 31, 2013 consisted of 32 wells in the Wattenberg Field, 2 wells in the Utica Shale and 4 wells in the Appalachia-Marcellus Shale. +Net Exploratory Well Drilling Activity +Year Ended December 31, +2013 +2012 +2011 +Operating Region/Area +Productive +In-Process +Dry +Productive +In-Process +Dry +Productive +In-Process +Dry +Utica Shale +4.2 +— +— +— +1.5 +1.7 +— +2.3 +— +Appalachia-Marcellus Shale +1.5 +— +— +— +— +— +— +— +— +Other +— +— +— +— +— +— +— +1.0 +— +Total net exploratory wells +5.7 +— +— +— +1.5 +1.7 +— +3.3 +— +11 +Title to Properties +We believe that we hold good and defensible leasehold title to substantially all of our crude oil and natural gas properties in accordance with standards generally accepted in the industry. As is customary in the industry, a preliminary title examination is typically conducted at the time the undeveloped properties are acquired. Prior to the commencement of drilling operations, a title examination is conducted and remedial curative work is performed with respect to discovered defects which we deem to be significant. Title examinations have been performed with respect to substantially all of our producing properties. +The properties we own are subject to royalty, overriding royalty and other outstanding interests customary in the industry. The properties may also be subject to additional burdens, liens or encumbrances customary in the industry, including items such as operating agreements, current taxes, development obligations under crude oil and natural gas leases, farm-out agreements and other restrictions. We do not believe that any of these burdens will materially interfere with our use of the properties. +Substantially all of our crude oil and natural gas properties, excluding properties held by PDCM and our share of the limited partnerships that we sponsor, have been mortgaged or pledged as security for our revolving credit facility. Substantially all of our Appalachia-Marcellus Shale properties have been pledged as security for PDCM's credit facility. See Note 8, Long-Term Debt , to our consolidated financial statements included elsewhere in this report. +Facilities +We lease 45,015 square feet of office space in Denver, Colorado, which serves as our corporate offices, through December 2015. We own a 32,000 square feet administrative office building located in Bridgeport, West Virginia, where we also lease approximately 18,600 square feet of office space in a second building through October 2014. +We own or lease field operating facilities in Evans, Colorado, Bridgeport, West Virginia and Marietta, Ohio. +Governmental Regulation +While the prices of crude oil and natural gas are market driven, other aspects of our business and the industry in general are heavily regulated. The availability of a ready market for crude oil and natural gas production depends on several factors that are beyond our control. These factors include, but are not limited to, regulation of production, federal and state regulations governing environmental quality and pollution control, the amount of crude oil and natural gas available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. In general, state and federal regulations are intended to protect consumers from unfair treatment and oppressive control, reduce environmental and health risks from the development and transportation of crude oil and natural gas, prevent misuse of crude oil and natural gas and protect rights among owners in a common reservoir. Pipelines are subject to the jurisdiction of various federal, state and local agencies. We believe that we are in compliance with such statutes, rules, regulations and governmental orders in all material respects, although there can be no assurance that this is or will remain the case. The following summary discussion on the regulation of the U.S. oil and gas industry is not intended to constitute a complete discussion of the various statutes, rules, regulations and environmental directives to which our operations may be subject. +Regulation of Crude Oil and Natural Gas Exploration and Production . Our exploration and production business is subject to various federal, state and local laws and regulations on the taxation of crude oil and natural gas, the development, production and marketing of crude oil and natural gas and environmental and safety matters. State and local laws and regulations require drilling permits and govern the spacing and density of wells, rates of production, water discharge, prevention of waste and other matters. Prior to commencing drilling activities for a well, we must procure permits and/or approvals for the various stages of the drilling process from the applicable state and local agencies where the well being drilled is located. Additionally, other regulated matters include: +• +bond requirements in order to drill or operate wells; +• +well locations; +• +drilling and casing methods; +• +surface use and restoration of well properties; +• +well plugging and abandoning; +• +fluid disposal; and +• +air emissions. +In addition, our drilling activities involve hydraulic fracturing, which may be subject to additional federal and state disclosure and regulatory requirements discussed in "Environmental Matters" below and in Item 1A, Risk Factors . +Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the density of wells which may be drilled and the unitization or pooling of lands and leases. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely primarily or exclusively on voluntary pooling of lands and leases. In areas where pooling is primarily or exclusively voluntary, it may be more difficult to form units, and therefore, more difficult to drill and develop our leases where we own less than 100% of the leases located within the proposed unit. State laws may establish +12 +maximum rates of production from crude oil and natural gas wells, prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. Leases covering state or federal lands often include additional regulations and conditions. The effect of these conservation laws and regulations may limit the amount of crude oil and natural gas we can produce from our wells and may limit the number of wells or the locations at which we can drill. Such laws and regulations may increase the costs of planning, designing, drilling, installing, operating and abandoning our crude oil and natural gas wells and other facilities. These laws and regulations, and any others that are passed by the jurisdictions where we have production, can limit the total number of wells drilled or the allowable production from successful wells, which can limit our reserves. As a result, we are unable to predict the future cost or effect of complying with such regulations. +Regulation of Transportation of Natural Gas . We move natural gas through pipelines owned by other companies and sell natural gas to other companies that also utilize common carrier pipeline facilities. Natural gas pipeline interstate transmission and storage activities are subject to regulation by the Federal Energy Regulatory Commission ("FERC") under the Natural Gas Act of 1938 ("NGA") and under the Natural Gas Policy Act of 1978, and, as such, rates and charges for the transportation of natural gas in interstate commerce, accounting, and the extension, enlargement or abandonment of jurisdictional facilities, among other things, are subject to regulation. Each natural gas pipeline company holds certificates of public convenience and necessity issued by FERC authorizing ownership and operation of all pipelines, facilities and properties for which certificates are required under the NGA. Each natural gas pipeline company is also subject to the Natural Gas Pipeline Safety Act of 1968, as amended, which regulates safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities. FERC regulations govern how interstate pipelines communicate and do business with their affiliates. Interstate pipelines may not operate their pipeline systems to preferentially benefit their marketing affiliates. +Each interstate natural gas pipeline company establishes its rates primarily through FERC's rate-making process. Key determinants in the ratemaking process are: +• +costs of providing service, including depreciation expense; +• +allowed rate of return, including the equity component of the capital structure and related income taxes; and +• +volume throughput assumptions. +The availability, terms and cost of transportation affect our natural gas sales. Competition among suppliers has greatly increased. Furthermore, gathering is exempt from regulation under the Natural Gas Act, thus allowing gatherers to charge unregulated rates. Historically, producers were able to flow supplies into interstate pipelines on an interruptible basis; however, recently we have seen the increased need to acquire firm transportation on pipelines in order to avoid curtailments or shut-in gas, which could adversely affect cash flows from the affected area. +Additional proposals and proceedings that might affect the industry occur frequently in Congress, FERC, state commissions, state legislatures and the courts. The industry historically has been very heavily regulated; therefore, there is no assurance that the current regulatory approach recently taken by FERC and Congress will continue. We cannot determine to what extent our future operations and earnings will be affected by new legislation, new regulations, or changes in existing regulation, at federal, state or local levels. +Environmental Matters +Our operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Public demand for the protection of the environment has increased dramatically in recent years. The trend of more expansive and restrictive environmental legislation and regulations is expected to continue. To the extent laws are enacted or other governmental actions are taken which restrict drilling or impose environmental protection requirements resulting in increased costs, our business and prospects may be adversely affected. +We generate wastes that may be subject to the Federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes. The U.S. Environmental Protection Agency ("EPA") and various state agencies have adopted requirements that limit the approved disposal methods for certain hazardous and non-hazardous wastes. Furthermore, certain wastes generated by our operations that are currently exempt from treatment as "hazardous wastes" may in the future be designated as "hazardous wastes," and therefore may subject us to more rigorous and costly operating and disposal requirements. +Hydraulic fracturing is commonly used to stimulate production of crude oil and/or natural gas from dense subsurface rock formations. We routinely apply fracturing in our crude oil and natural gas production programs. The process involves the injection of water, sand and additives under pressure into a targeted subsurface formation. The water and pressure create fractures in the rock formations, which are held open by the grains of sand, enabling the crude oil or natural gas to flow to the wellbore. The process is generally subject to regulation by state oil and gas commissions. However, the EPA has asserted federal regulatory authority over certain fracturing activities involving diesel fuel under the federal Safe Drinking Water Act ("SDWA") and issued draft guidance related to this asserted regulatory authority in February 2014. The guidance explains the EPA’s interpretation of the term “diesel fuel” for permitting purposes, describes existing Underground Injection Control Class II program requirements for permitting underground injection of diesel fuels in hydraulic fracturing and also provides recommendations for EPA permit writers in implementing these requirements. From time to time, Congress has considered legislation that would provide for federal regulation of hydraulic fracturing and disclosure of the chemicals used in the hydraulic fracturing process. +The White House Council on Environmental Quality continues to coordinate an administration-wide review of hydraulic fracturing. The EPA continues its study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with final results +13 +expected by December 2014. In addition, the U.S. 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. These ongoing studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms. The U.S. Department of the Interior, through the Bureau of Land Management (the “BLM”), is also conducting a rulemaking to require disclosure of chemicals used, mandate well integrity measures and impose other requirements relating to hydraulic fracturing on federal lands. +Certain states in which we operate, including Colorado, Pennsylvania and Ohio, have adopted, and are considering additional regulations that could impose more stringent permitting, transparency and well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether. For example, Colorado requires that all chemicals used in the hydraulic fracturing of a well be reported in a publicly searchable registry website developed and maintained by the Ground Water Protection Council and Interstate Oil and Gas Compact Commission ("Frac Focus"). The Colorado rules also require operators seeking new location approvals to provide certain information to surface owners and adjacent property owners within 500 feet of a new well. Similarly, Colorado has implemented a baseline groundwater sampling rule and a rule governing setback distances of oil and gas wells located near population centers. In December 2013, the Colorado Oil and Gas Conservation Commission issued new, more restrictive rules regarding spill reporting and remediation. See further discussion in Item 1A, Risk Factors . +In December 2011, West Virginia enacted the Natural Gas Horizontal Well Control Act and amendments to existing laws that together establish a comprehensive, detailed system for permitting and regulation of horizontal natural gas wells. The law applies to most proposed new natural gas wells. The law imposes far more detailed permitting and regulatory requirements than prior law and requires further study and authorizes potential rulemaking by the West Virginia Department of Environmental Protection ("DEP"). Among the new regulatory requirements are: detailed surface owner compensation requirements; performance standards applicable to disposal of drilling cuttings and associated drilling mud; protection of quantity and quality of surface and groundwater systems; advance designation of water withdrawal locations to the DEP and recordkeeping and reporting for all flowback and produced water; and restrictions on well locations. +In November 2013, the Ohio Department of Natural Resources ("ODNR") proposed draft regulations pertaining to well pad construction requirements and increased bonding for construction. The rules are expected to be finalized in 2014. +In Colorado, local governing bodies have begun to issue drilling moratoriums, develop jurisdictional siting, permitting and operating requirements and conduct air quality studies to identify potential public health impacts. For instance, in 2013, the City of Fort Collins, Colorado, adopted a ban on drilling and fracturing of new wells within city limits. In the November 2013 election, voters in the cities of Boulder, Lafayette, Fort Collins and Brighton passed hydraulic fracturing bans. We do not currently have operations in any of these areas. In addition, as discussed in more detail in Item 1A. Risk Factors , a ballot initiative has been proposed in Colorado which, if approved and upheld, could greatly expand the right of local governments to limit or prohibit oil and natural gas production and development in their jurisdictions. If new laws or regulations that significantly restrict hydraulic fracturing or well locations continue to be adopted at local levels or are adopted at the state level, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from dense subsurface rock formations and, in the event of local prohibitions against commercial production of natural gas, may preclude our ability to drill wells. If hydraulic fracturing becomes regulated as a result of federal legislation or regulatory initiatives by the EPA or other federal agencies, our fracturing activities could become subject to additional permitting requirements and permitting delays, as well as potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of crude oil and natural gas that we are ultimately able to produce from our reserves. We continue to be active in stakeholder and interest groups and to engage with regulatory agencies in an open, proactive dialogue. +We currently own or lease numerous properties that for many years have been used for the exploration and production of crude oil and natural gas. Although we believe that we have utilized good operating and waste disposal practices, and when necessary, appropriate remediation techniques, prior owners and operators of these properties may not have utilized similar practices and techniques and hydrocarbons or other wastes may have been disposed of or released on or under the properties that we own or lease or on or under locations where such wastes have been taken for disposal. These properties and the wastes disposed thereon may be subject to the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), RCRA and analogous state laws, as well as state laws governing the management of crude oil and natural gas wastes. Under such laws, we may be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or remediate property contamination (including surface and groundwater contamination) or to perform remedial plugging operations to prevent future contamination. +CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed of or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for release of hazardous substances under CERCLA may be subject to full liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and 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. As an owner and operator of crude oil and natural gas wells, we may be liable pursuant to CERCLA and similar state laws. +Our operations are subject to the federal Clean Air Act ("CAA") and comparable state and local requirements. The CAA contains provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. The EPA and states continue the development of regulations to implement these requirements. We may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and +14 +approvals addressing other air emission-related issues. Greenhouse gas record keeping and reporting requirements of the CAA became effective in 2011 and will continue into the future with increased costs for administration and implementation of controls. Federal New Source Performance Standards regarding oil and gas operations ("NSPS OOOO") became effective in 2012 and 2013, with additional NSPS provisions expected in 2014, all of which will add administrative and operational costs. Colorado continues to draft and adopt new regulations to meet the requirements of NSPS OOOO and will promulgate significant rules relating specifically to crude oil and natural gas operations that are more stringent than NSPS OOOO and are expected to be finalized by March 2014. +The federal Clean Water Act ("CWA") and analogous state laws impose strict controls against the discharge of pollutants and fill material, including spills and leaks of crude oil and other substances. The CWA also requires approval and/or permits prior to construction, where construction will disturb wetlands or other waters of the U.S. The CWA also regulates storm water run-off from crude oil and natural gas facilities and requires storm water discharge permits for certain activities. Spill Prevention, Control, and Countermeasure ("SPCC") requirements of the CWA require appropriate secondary containment loadout controls, piping controls, berms and other measures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon spill, rupture or leak. The EPA and U.S. Army Corps of Engineers released a Connectivity Report in September 2013, which determined that all tributary streams, wetlands, open water in floodplains and riparian areas are connected. This report supported the drafting of new rules regarding what will be considered waters of the U.S. The new rules were submitted for inter-agency review in October 2013 and are expected to be available for public review by May 2014. +Crude oil production is subject to many of the same operating hazards and environmental concerns as natural gas production, but is also subject to the risk of crude oil spills. Federal regulations require certain owners or operators of facilities that store or otherwise handle crude oil, including us, to procure and implement additional SPCC measures relating to the possible discharge of crude oil into surface waters. The Oil Pollution Act of 1990 ("OPA") subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from crude oil spills. Noncompliance with OPA may result in varying civil and criminal penalties and liabilities. Historically, we have not experienced any significant crude oil discharge or crude oil spill problems. Our shift in production since mid-2010 to a greater percentage of crude oil increases our risks related to soil and water contamination. +Our costs relating to protecting the environment have risen over the past few years and are expected to continue to rise in 2014 and beyond. Environmental regulations have increased our costs and planning time, but have had no materially adverse effect on our ability to operate to date. However, no assurance can be given that environmental regulations or interpretations of such regulations will not, in the future, result in a curtailment of production or otherwise have a materially adverse effect on our business, financial condition or results of operations. See Note 11, Commitments and Contingencies , to our consolidated financial statements included elsewhere in this report. +Operating Hazards and Insurance +Our exploration and production operations include a variety of operating risks, including, but not limited to, the risk of fire, explosions, blowouts, cratering, pipe failure, casing collapse, abnormally pressured formations and environmental hazards such as gas leaks, ruptures and discharges of crude oil and natural gas. The occurrence of any of these events could result in substantial losses to us due to injury and loss of life, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. Our pipeline, gathering and distribution operations are subject to the many hazards inherent in the industry. These hazards include damage to wells, pipelines and other related equipment, damage to property caused by hurricanes, floods, fires and other acts of God, inadvertent damage from construction equipment, leakage of natural gas and other hydrocarbons, fires and explosions and other hazards that could also result in personal injury and loss of life, pollution and suspension of operations. In September 2013, we experienced widespread flooding in our Wattenberg Field operations in Weld County, Colorado, which resulted in a shut-in of approximately 200 vertical wells, approximately 40 of which remained shut-in at December 31, 2013. We have incurred significant costs to replace damaged well equipment and to bring vertical wells back on-line. Assessment of the full economic impact of the flooding is on going. +Any significant problems related to our facilities could adversely affect our ability to conduct our operations. In accordance with customary industry practice, we maintain insurance against some, but not all, potential risks; however, there can be no assurance that such insurance will be adequate to cover any losses or exposure for liability. The occurrence of a significant event not fully insured against could materially adversely affect our operations and financial condition. We cannot predict whether insurance will continue to be available at premium levels that justify our purchase or will be available at all. Furthermore, we are not insured against our economic losses resulting from damage or destruction to third-party property, such as transportation pipelines, crude oil refineries or natural gas processing facilities. Such an event could result in significantly lower regional prices or our inability to deliver our production. +15 +Competition and Technological Changes +We believe that our exploration, drilling and production capabilities and the experience of our management and professional staff generally enable us to compete effectively. We encounter competition from numerous other crude oil and natural gas companies, drilling and income programs and partnerships in all areas of operations, including drilling and marketing crude oil and natural gas and obtaining desirable crude oil and natural gas leases on producing properties. Many of these competitors possess larger staffs and greater financial resources than we do, which may enable them to identify and acquire desirable producing properties and drilling prospects more economically. Our ability to explore for crude oil and natural gas prospects and to acquire additional properties in the future depends upon our ability to conduct our operations, evaluate and select suitable properties and consummate transactions in this highly competitive environment. We also face intense competition in the marketing of natural gas from competitors including other producers and marketing companies. Also, international developments and the possible improved economics of domestic natural gas exploration may influence other companies to increase their domestic crude oil and natural gas exploration. Furthermore, competition among companies for favorable prospects can be expected to continue and it is anticipated that the cost of acquiring properties will increase in the future. +Recently, certain regions experienced strong demand for drilling services and supplies, which resulted in increasing costs. The Wattenberg Field, Utica Shale and Appalachia-Marcellus Shale have experienced intense competition for drilling and pumping services. Factors affecting competition in the industry include price, location of drilling, availability of drilling prospects and drilling rigs, fracturing services, pipeline capacity, quality of production and volumes produced. We believe that we can compete effectively in the industry in each of the areas where we have operations. Nevertheless, our business, financial condition and results of operations could be materially adversely affected by competition. We also compete with other crude oil and natural gas companies, as well as companies in other industries, for the capital we need to conduct our operations. Should economic conditions deteriorate and financing become more expensive and difficult to obtain, we may not have adequate capital to execute our business plan and we may be forced to curtail our drilling and acquisition activities. +The oil and gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition, results of operations and cash flows could be materially adversely affected. +Employees +As of December 31, 2013 , we had 412 employees. Our employees are not covered by collective bargaining agreements. We consider relations with our employees to be good. +WHERE YOU CAN FIND ADDITIONAL INFORMATION +We file annual, quarterly and current reports, proxy statements and other information with the SEC. Our SEC filings are available free of charge from the SEC’s website at www.sec.gov or from our website at www.pdce.com. You may also read or copy any document we file at the SEC’s public reference room in Washington, D.C., located at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Please call the SEC at (800) SEC-0330 for further information on the public reference room. We also make available free of charge any of our SEC filings by mail. For a mailed copy of a report, please contact PDC Energy Inc., Investor Relations, 1775 Sherman Street, Suite 3000, Denver, CO 80203, or call (800) 624-3821. +We recommend that you view our website for additional information, as we routinely post information that we believe is important for investors. Our website can be used to access such information as our recent news releases, committee charters, code of business conduct and ethics, shareholder communication policy, director nomination procedures and our whistle blower hotline. While we recommend that you view our website, the information available on our website is not part of this report and is not incorporated by reference. +16 +ITEM 1A. RISK FACTORS +You should carefully consider the following risk factors in addition to the other information included in this report. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common stock or other securities. +Crude oil, natural gas and NGL prices fluctuate and a decline in these prices can significantly affect the value of our assets and our financial results and impede our growth. +Our revenue, profitability, cash flows and liquidity depend in large part upon the price we receive for our crude oil, natural gas and NGLs. In addition, changes in commodity prices have a significant effect on the value and quantity of our reserves, which can in turn affect the borrowing base under our revolving credit facility and our access to other sources of capital, and on the nature and scale of our operations. The markets for crude oil, natural gas and NGLs are often volatile, and prices may fluctuate in response to relatively minor changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including national and international economic and political factors and federal and state legislation. For example, geopolitical events in the Middle East or elsewhere could affect global crude oil prices, and continued weakness in the overall economic environment could adversely affect all commodity prices. +In addition to factors affecting the price of crude oil, natural gas and NGLs generally, the prices we receive for our production are affected by factors specific to us and to the local markets where the production occurs. The prices that we receive for our production are generally lower than the relevant benchmark prices that are used for calculating commodity derivative positions. These differences, or differentials, are difficult to predict and may widen in the future. Differentials can be influenced by, among other things, local or regional supply and demand factors and the terms of our sales contracts. Differentials on oil produced in the Wattenberg Field have widened in recent months, in part as a result of the midstream capacity issues discussed below. Over the longer term, differentials will be significantly affected by factors such as investment decisions made by providers of midstream facilities and services, refineries and other industry participants, and the overall regulatory and economic climate. For example, increases in U.S. domestic oil production generally may result in widening differentials, particularly for production from some basins. We may be materially and adversely impacted by widening differentials on our production. +The marketability of our production is dependent upon transportation and processing facilities the capacity and operation of which we do not control. Market conditions or operational impediments, including high line pressures, particularly in the Wattenberg Field, and other impediments affecting midstream facilities and services, could hinder our access to crude oil, natural gas and NGL markets, increase our costs or delay production and thereby adversely affect our profitability. +Our ability to market our production depends in substantial part on the availability, proximity and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. If adequate midstream facilities and services are not available to us on a timely basis and at acceptable costs, our production and results of operations will be adversely affected. These risks are greater for us than for some of our competitors because our operations are focused on areas where there is currently a substantial amount of development activity, which increases the likelihood that there will be periods of time in which there is insufficient midstream capacity to accommodate the resulting increases in production. For example, due to increased drilling activities by us and third parties, and hot temperatures during the summer months, the principal third-party provider we use in the Wattenberg area for midstream facilities and services has recently experienced high gathering system line pressure. The resulting capacity constraints impacted the productivity of some of our older wells and limited the incremental production impact of our newer horizontal wells. This constrained our production and reduced our revenue from the affected wells. Capacity constraints affecting natural gas production also impact our ability to produce the associated NGLs. We are also dependent on the availability and capacity of purchasers for our production. For example, recent reductions in purchases by a local crude oil refinery have increased the amount of oil that we have to transport out of the Wattenberg area for sale. This has increased our transportation costs and reduced the price we receive for the affected production. We expect this situation to continue for the foreseeable future. In addition, the use of alternative forms of transportation such as trucks or rail involve risks as well. For example, recent and well-publicized accidents involving trains delivering crude oil could result in increased levels of regulation and transportation costs. We face similar risks in other areas, including our Utica operating area, as gathering/processing infrastructure is currently in the development phase and development activity conducted by us and others is increasing. We are also dependent on third party pipeline infrastructure to deliver our natural gas production to market in the Appalachia-Marcellus area. In addition to causing production curtailments, capacity constraints can also reduce the price we receive for the crude oil, natural gas and NGLs we produce. +Federal, state and local legislation and regulations relating to hydraulic fracturing could result in increased costs, additional drilling and operating restrictions or delays in the production of crude oil, natural gas and NGLs, and could prohibit hydraulic fracturing activities. +Most of our drilling uses hydraulic fracturing. Hydraulic fracturing is an important and commonly used process in the completion of unconventional wells in shale, coalbed, and tight sand formations. Proposals have been introduced in the U.S. Congress to regulate hydraulic fracturing operations and related injection of fracturing fluids and propping agents used by the crude oil and natural gas industry in fracturing fluids under the Safe Drinking Water Act (“SDWA”), and to require the disclosure of chemicals used in the hydraulic fracturing process under the SDWA, the Emergency Planning and Community Right-to-Know Act (“EPCRA”), or other laws. Sponsors of these bills, which have been subject to various proceedings in the legislative process, including in the House Energy and Commerce Committee and the Senate Environmental and Public Works Committee, have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies and otherwise cause adverse environmental impacts. In March 2011, the EPA announced its intention to conduct a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on water quality and public health. EPA issued an initial report about the study in December 2012. The initial report described the focus of the continuing study but did not include any data concerning EPA’s efforts +17 +to date, nor did it draw any conclusions about the safety of hydraulic fracturing. A draft report including data and conclusions is expected in 2014. +EPA has begun a Toxic Substances Control Act (“TSCA”) rulemaking which will collect expansive information on the chemicals used in hydraulic fracturing fluid, as well as other health-related data, from chemical manufacturers and processors. EPA has not indicated when it intends to issue a proposed rule. Concurrently, the White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. +EPA also finalized major new CAA standards (New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants) applicable to hydraulically fractured natural gas wells and certain storage vessels in August 2012. The standards will require, among other things, use of reduced emission completions, or green completions, to reduce volatile organic compound emissions during well completions as well as new controls applicable to a wide variety of storage tanks and other equipment, including compressors, controllers, and dehydrators. While most key provisions in the new CAA standards are not effective until 2015 and EPA currently is re-considering parts of the rule, the rules associated with such standards are substantial and will increase future costs of our operations and will require us to make modifications to our operations and install new equipment. +EPA has also issued permitting guidance under the SDWA for the underground injection of liquids from hydraulically fractured (and other) wells where diesel is used. This recently-issued guidance may create duplicative requirements, further slow down the permitting process in certain areas, increase the costs of operations, and result in expanded regulation of hydraulic fracturing activities by EPA depending on how it is implemented. Certain other federal agencies are analyzing, or have been requested to review, environmental issues associated with hydraulic fracturing. Most notably, the U.S. Department of the Interior, through the BLM, is currently conducting a rulemaking that will require, among other things, disclosure of chemicals and more stringent well integrity measures associated with hydraulic fracturing operations on public land. BLM has not indicated when it will issue a final rule. +In addition, the governments of certain states, including Colorado, Pennsylvania, Ohio, and West Virginia, have adopted or are considering adopting laws and regulations that impose or could impose, among other requirements, stringent permitting or air emission control requirements, disclosure, wastewater disposal, baseline sampling, well construction and well location requirements on hydraulic fracturing operations or otherwise seek to ban underground injection of fracturing wastewater or fracturing activities altogether. For example, in January 2012, the ODNR issued a temporary moratorium on the development of hydraulic fracturing disposal wells in northeast Ohio in order to study the relationship between these wells and minor earthquakes reported in the area. As a result, ODNR promulgated new and more stringent regulations for certain underground injection wells, including requirements for a complete suite of geophysical logs, analytical interpretation of the logs, and enhanced monitoring and recording. +At the local level, some municipalities and local governments have adopted or are considering bans on hydraulic fracturing. Voters in the cities of Fort Collins, Boulder, and Lafayette, Colorado recently approved bans of varying length on hydraulic fracturing within their respective city limits. +In addition, lawsuits have been filed against unrelated third parties in Pennsylvania, New York, Arkansas, Colorado, Ohio, West Virginia, and several other states alleging contamination of drinking water by hydraulic fracturing. Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to crude oil, natural gas and NGL production activities using hydraulic fracturing techniques. Additional legislation, regulation, litigation, or moratoria could also lead to operational delays or lead us to incur increased operating costs in the production of crude oil, natural gas and NGLs, including from the development of shale plays, or could make it more difficult to perform hydraulic fracturing or other drilling activities. If these legislative, regulatory, litigation, and other initiatives cause a material decrease in the drilling of new wells or an increase in drilling costs, our profitability could be materially impacted. +A ballot initiative has been proposed in Colorado which, if approved, could vastly expand the right of local governments to limit or prohibit oil and natural gas production and development in their jurisdictions. Should this or any similar initiative or legislation be successful and survive legal challenge, additional limitations or prohibitions could be placed on crude oil and natural gas production and development within certain areas of Colorado or the state as a whole. This could adversely affect the cost, manner, and feasibility of development activities in Colorado, particularly those involving hydraulic fracturing, and significantly affect the value of our assets and our financial results and impede our growth. +Certain interest groups in Colorado opposed to oil and natural gas development generally, and hydraulic fracturing in particular, have advanced various options for ballot initiatives aimed at significantly limiting or preventing oil and natural gas development. To date, one initiative has been formally proposed. Colorado Community Rights Network has submitted to the Colorado Legislative Council a proposed amendment to the Colorado Constitution that would add a new section to the Bill of Rights regarding the right of local governments to self-govern. This constitutional amendment, should it be successfully implemented and survive legal challenge, would grant local governments in Colorado the right, without limitation, to prohibit crude oil and natural gas development within their respective jurisdictions and would clarify that such prohibitions would not be preempted by conflicting international, federal, or state laws. Other ballot initiatives and legislation focused on allowing localities greater latitude to regulate oil and natural gas development in Colorado are under discussion. Additional ballot initiatives and legislation directly impacting oil and natural gas development, including through further regulation of hydraulic fracturing, are also possible. Should any of these initiatives be successful and survive legal challenge, they could have a materially adverse impact on our ability to drill and/or produce crude oil and natural gas in certain areas in Colorado, or the state generally, and could materially impact our results of operations, production and reserves. +18 +Environmental and overall public scrutiny focused on the oil and gas industry is increasing. The current trend is to increase regulation of our operations and the industry. We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business. +Our exploration, development, production, and marketing operations are regulated extensively at the federal, state, and local levels. Environmental and other governmental laws and regulations have increased the costs of planning, designing, drilling, installing, operating, and abandoning crude oil and natural gas wells and associated facilities. Under these laws and regulations, we could also be liable for personal injuries, property damage, and natural resource or other damages. Similar to our competitors, we incur substantial operating and capital costs to comply with such laws and regulations. These compliance costs may put us at a competitive disadvantage compared to larger companies in the industry which can more easily capture economies of scale with respect to compliance. Failure to comply with these laws and regulations may result in the suspension or termination of our operations or other operational impediments and subject us to administrative, civil, and criminal penalties. Moreover, public interest in environmental protection has increased in recent years-particularly with respect to hydraulic fracturing-and environmental organizations have opposed, with some success, certain drilling projects. +In addition, our activities are subject to regulations governing conservation practices, protection of wildlife and habitat, and protection of correlative rights by state governments. These regulations affect our operations, increase our costs of exploration and production, and limit the quantity of crude oil, natural gas and NGLs that we can produce and market. A major risk inherent in our drilling plans is the possibility that we will be unable to obtain needed drilling permits from relevant governmental authorities in a timely manner. Delays in obtaining regulatory approvals or drilling permits, 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 or develop our properties. +Additionally, the crude oil and natural gas regulatory environment could change in ways that substantially increase our financial and managerial compliance costs, increase our exposure to potential damages or limit our activities. At the state level, for instance, the Colorado Oil and Gas Conservation Commission (“COGCC”) issued a rule in 2013 governing mandatory minimum spacing, or setbacks, between oil and gas wells and occupied buildings and other areas. Similarly, the COGCC has discussed measures to focus on wellbore integrity. Also in 2013, the COGCC issued rules that require baseline sampling of certain ground and surface water in most areas of Colorado and impose stringent spill reporting and remediation requirements. These new sampling requirements could increase the costs of developing wells in certain locations. In addition to increasing costs of operation, these rules could prevent us from drilling wells on certain locations we plan to develop, thereby reducing our reserves as well as our future revenues. +In addition, in November 2013, the Colorado Department of Public Health and Environment’s Air Quality Control Commission (“AQCC”) approved proposed regulations that would impose stringent new requirements relating to air emissions from oil and gas facilities in Colorado. These new rules, which are expected to be finalized in spring 2014, will require new controls, and impose additional monitoring, recordkeeping, and reporting requirements for most operators in Colorado. As part of the proposed rule package, the AQCC approved the direct regulation of hydrocarbon (i.e., methane) emissions from the Colorado oil and gas sector. If finalized as proposed, such direct state-only regulation of methane (a greenhouse gas) from a single industry sector in the absence of comparable federal regulation is a significant new authority being asserted at the state level and has the potential to adversely affect operations in Colorado as well as in other parts of the country. Along the same lines, local governments are undertaking air quality studies to assess potential public health impacts from oil and gas operations. These studies, in combination with other air quality-related studies that are national in scope, may result in the imposition of additional regulatory requirements on oil and gas operations. +Other potential laws and regulations affecting us include new or increased severance taxes proposed in several states, including Pennsylvania and Ohio. This could adversely affect our existing operations in these states and the economic viability of future drilling. Additional laws, regulations, or other changes could significantly reduce our future growth, increase our costs of operations, and reduce our cash flows, in addition to undermining the demand for the crude oil, natural gas and NGLs we produce. +Our ability to produce crude oil and natural gas could be impaired if we are unable to acquire adequate supplies of water for our drilling and completion operations or are unable to dispose of the water we use at a reasonable cost and within applicable environmental rules. +Our operations could be adversely impacted if we are unable to locate sufficient amounts of water, or dispose of or recycle water used in our exploration and production operations. Currently, the quantity of water required in certain completion operations, such as hydraulic fracturing, and changing regulations governing usage may lead to water constraints and supply concerns (particularly in some parts of the country). In addition, notwithstanding recent flooding in Colorado discussed below, Colorado and other western states have recently experienced drought conditions. As a result, future availability of water from certain sources used in the past may become limited. +The imposition of new environmental initiatives relating to wastewater could restrict our ability to conduct certain operations such as hydraulic fracturing. This includes potential restrictions on waste disposal, including, but not limited to, produced water, drilling fluids, and other wastes associated with the exploration, development, or production of crude oil and natural gas. For example, in 2010 a petition was filed by the Natural Resources Defense Council with EPA requesting that the agency reassess its prior and long-standing determination that certain oil and natural gas exploration and production wastes would not be regulated as hazardous waste under Subtitle C of the RCRA. EPA has not yet acted on the petition and it remains pending. Were EPA to begin treating some or all of these wastes as “hazardous” under Subtitle C in response to the petition, the consequences for our operations would be serious, and would include a significant increase in costs associated with waste treatment and disposal and a potential inability to conduct operations in some instances. +The CWA and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas waste, into navigable waters or other regulated federal and state waters. Permits or other approvals must be obtained to discharge fill and pollutants into regulated waters and to conduct construction activities in such waters and wetlands. Uncertainty +19 +regarding regulatory jurisdiction over wetlands and other regulated waters of the United States has complicated, and will continue to complicate and increase the cost of, obtaining such permits or other approvals. Most recently, EPA and the U.S. Army Corps of Engineers submitted to the White House Office of Management and Budget for review a proposed rule on defining jurisdictional waters of the United States. An expansive definition of such jurisdictional waters could affect our ability to operate in certain areas, increase costs of operations, and cause significant scrutiny and delays in permitting. While generally exempt under federal programs, many state agencies have also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. These permits, in turn, impose far-ranging monitoring, flow control, and other obligations that have generated, and will continue to generate, increased costs for our operations. +In October 2011, EPA announced its intention to develop federal pretreatment standards for wastewater discharges associated with hydraulic fracturing activities. If adopted, the pretreatment rules will require shale gas operations to pretreat wastewater before transfer to treatment facilities. Proposed rules are expected in 2014. Some states, including Pennsylvania, have banned the treatment of fracturing wastewater at publicly owned treatment facilities. There has been recent nationwide concern, particularly in Ohio, over earthquakes associated with Class II underground injection control wells, a predominant storage method for crude oil and gas wastewater. As seen in Ohio, it is likely that new rules and regulations will be developed to address these concerns, possibly eliminating access to Class II wells in certain locations, and increasing the cost of disposal in others. +Finally, the EPA study noted above has focused and will continue to focus on various stages of water use in hydraulic fracturing operations. It is possible that, following the conclusion of EPA’s study, the agency will move to more strictly regulate the use of water in hydraulic fracturing operations. While we cannot predict the impact that these changes may have on our business at this time, they may be material to our business, financial condition, and operations. In addition, an inability to meet our water supply needs to conduct our completion operations may adversely impact our business. These potential water-related concerns may be heightened by recent flooding events in Colorado. For example, we experienced damage to some of our facilities as well as other operational impediments caused by the flooding event. Future legal and regulatory changes related to this event could negatively affect our financial condition and operations. +A substantial part of our crude oil, natural gas and NGLs production is located in the Wattenberg Field, making us vulnerable to risks associated with operating primarily in a single geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing formations. +Our operations are focused primarily on the Wattenberg Field, which means our current producing properties and new drilling opportunities are geographically concentrated in that area. Because our operations are not as diversified geographically as many of our competitors, the success of our operations and our profitability may be disproportionately exposed to the effect of any regional events, including fluctuations in prices of crude oil, natural gas and NGLs produced from the wells in the area, natural disasters such as the flooding that occurred in the area in September 2013, restrictive governmental regulations, transportation capacity constraints, curtailment of production or interruption of transportation, and any resulting delays or interruptions of production from existing or planned new wells. For example, the recent increase in activity in the Wattenberg Field has contributed to bottlenecks in processing and transportation that have negatively affected our results of operations, and these adverse effects may be disproportionately severe to us compared to our more geographically diverse competitors. Similarly, the concentration of our assets within a small number of producing formations exposes us to risks, such as changes in field-wide rules, that could adversely affect development activities or production relating to those formations. Such an event could have a material adverse effect on our results of operations and financial condition. +Our estimated crude oil and natural gas reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves. +Calculating reserves for crude oil, natural gas and NGLs requires subjective estimates of remaining volumes of underground accumulations of hydrocarbons. Assumptions are also made concerning commodity prices, production levels, and operating and development costs over the economic life of the properties. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be inaccurate. Independent petroleum engineers prepare our estimates of crude oil, natural gas and NGLs reserves using pricing, production, cost, tax and other information that we provide. The reserve estimates are based on certain assumptions regarding commodity prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions to actual results could greatly affect: +• +the economically recoverable quantities of crude oil, natural gas and NGLs attributable to any particular group of properties; +• +future depreciation, depletion and amortization (“DD&A”) rates and amounts; +• +impairments in the value of our assets; +• +the classifications of reserves based on risk of recovery; +• +estimates of future net cash flows; +• +timing of our capital expenditures; and +• +the amount of funds available for us to utilize under our revolving credit facility. +Some of our reserve estimates must be made with limited production histories, which renders these reserve estimates less reliable than estimates based on longer production histories. Horizontal drilling in the Wattenberg Field is a relatively recent development, whereas vertical drilling has been used by producers in this field for over 40 years. As a result, the amount of production data from horizontal wells available to reserve engineers is relatively small, and future reserve estimates will be affected by additional production data as it becomes available. Horizontal drilling in the Utica Shale has an even more limited history, particularly in the southern part of the play where most of our acreage is located. Further, reserve estimates are based on the volumes of crude oil, natural gas and NGLs that are anticipated to be +20 +economically recoverable from a given date forward based on economic conditions that exist at that date. The actual quantities of crude oil, natural gas and NGLs recovered will be different than the reserve estimates since they will not be produced under the same economic conditions as used for the reserve calculations. In addition, quantities of probable and possible reserves by definition are inherently more risky than proved reserves and are less likely to be recovered. +At December 31, 2013 , approximately 72% of our estimated proved reserves (by volume) were undeveloped. These reserve estimates reflected our plans to make significant capital expenditures to convert our PUDs into proved developed reserves, including approximately $2.5 billion during the five years ending December 31, 2018. You should be aware that the estimated development costs may not be accurate, development may not occur as scheduled and results may not be as estimated. If we choose not to develop PUDs, or if we are not otherwise able to successfully develop them, we will be required to remove the associated volumes from our reported proved reserves. In addition, under the SEC’s reserve reporting rules, because PUDs generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking, we may be required to downgrade any PUDs that are not developed within this five-year time frame to probable or possible. +The present value of the estimated future net cash flows from our proved reserves is not necessarily the same as the current market value of those reserves. Pursuant to SEC rules, the estimated discounted future net cash flows from our proved reserves, and the estimated quantity of those reserves, were based on the prior 12-month average crude oil and natural gas index prices. However, factors such as actual prices we receive for crude oil and natural gas and hedging instruments, the amount and timing of actual production, amount and timing of future development costs, supply of and demand for crude oil, natural gas and NGLs and changes in governmental regulations or taxation, also affect our actual future net cash flows from our properties. If we had used current forward strip commodity prices instead of the 12-month average prices mandated by SEC rules, the estimated quantities of our proved reserves and cash flows from those reserves as of December 31, 2013 would have been lower. +The timing of both our production and incurrence of expenses in connection with the development and production of crude oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor (the rate required by the SEC) we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates currently in effect and risks associated with our properties or the industry in general. +Unless reserves are replaced as they are produced, our reserves and production will decline, which would adversely affect our future business, financial condition and results of operations. We may not be able to develop our identified drilling locations as planned. +Producing crude oil, natural gas and NGL reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The rate of decline may change over time and may exceed our estimates. Our future reserves and production and, therefore, our cash flows and income, are highly dependent on our ability to efficiently develop and exploit our current reserves and to economically find or acquire additional recoverable reserves. We may not be able to develop, discover or acquire additional reserves to replace our current and future production at acceptable costs. Our failure to do so would adversely affect our future operations, financial condition and results of operations. +We have identified a number of well locations as an estimation of our future multi-year drilling activities on our existing acreage. These well locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including crude oil, natural gas and NGL prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, midstream constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. Because of these factors, we do not know if the numerous potential well locations we have identified will ever be drilled or if we will be able to produce crude oil, natural gas or NGLs from these or any other potential well locations. In addition, the number of drilling locations available to us will depend in part on the spacing of wells in our operating areas. An increase in well density in an area could result in additional locations in that area, but a reduced production performance from the area on a per-well basis. Further, certain of the horizontal wells we intend to drill in the future may require pooling of our lease interests with the interests of third parties. If these third parties are unwilling to pool their interests with ours, and we are unable to require such pooling on a timely basis or at all, this may limit the total locations we can drill. As such, our actual drilling activities may materially differ from those presently identified. Further, our inventory of drilling projects includes locations in addition to those that we currently classify as 3P. The development of and results from these additional projects are more uncertain than those relating to 3P locations, and significantly more uncertain than those relating to proved locations. +The wells we drill may not yield crude oil, natural gas or NGLs in commercially viable quantities, and productive wells may be less successful than we expect. +A prospect is a property on which our geologists have identified what they believe, based on available information, to be indications of hydrocarbon-bearing rocks. However, our geologists cannot know conclusively prior to drilling and testing whether crude oil, natural gas or NGLs will be present in sufficient quantities to repay drilling or completion costs and generate a profit given the available data and technology. If a well is determined to be dry or uneconomic, which can occur even though it contains some crude oil, natural gas or NGLs, it is classified as a dry hole and must be plugged and abandoned in accordance with applicable regulations. This generally results in the loss of the entire cost of drilling and completion to that point, the cost of plugging, and lease costs associated with the prospect. Even wells that are completed and placed into production may not produce sufficient crude oil, natural gas and NGLs to be profitable, or they may be less productive and/or profitable than we expected. If we drill a dry hole or unprofitable well on a current or future prospect, the profitability of our operations will decline and the value of our properties will likely be reduced. These risks are greater in developing areas such as the Utica +21 +Shale, where we are currently investing substantial capital. Exploratory drilling is typically subject to substantially greater risk than development drilling. In addition, initial results from a well are not necessarily indicative of its performance over a longer period. +Drilling for and producing crude oil, natural gas and NGLs are high risk activities with many uncertainties that could adversely affect our business, financial condition and results of operations. +Drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for crude oil and natural gas can be unprofitable, not only due to dry holes, but also due to curtailments, delays or cancellations as a result of other factors, including: +• +unusual or unexpected geological formations; +• +pressures; +• +fires; +• +floods; +• +loss of well control; +• +loss of drilling fluid circulation; +• +title problems; +• +facility or equipment malfunctions; +• +unexpected operational events; +• +shortages or delays in the delivery of equipment and services; +• +unanticipated environmental liabilities; +• +compliance with environmental and other governmental requirements; and +• +adverse weather conditions. +Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and regulatory penalties. For example, a loss of containment of hydrocarbons during drilling activities could potentially subject us to civil and/or criminal liability and the possibility of substantial costs, including for environmental remediation, depending upon the circumstances of the loss of containment, the nature and scope of the loss and the applicable laws and regulations. We maintain insurance against various losses and liabilities arising from operations; however, insurance against certain operational risks may not be available or may be prohibitively expensive relative to the perceived risks presented. For example, we may not have coverage with respect to a pollution event if we are unaware of the event while it is occurring and are therefore unable to report the occurrence of the event to our insurance company within the time frame required under our insurance policy. Thus, losses could occur for uninsurable or uninsured risks or for amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance and/or governmental or third party responses to an event could have a material adverse effect on our business activities, financial condition and results of operations. We are currently involved in various remedial and investigatory activities at some of our wells and related sites. +Our business strategy focuses on production in our liquid-rich and high impact shale plays. In this regard, we plan to allocate our capital to an active horizontal drilling program. Historically, most of the wells we drilled were vertical wells. Since 2012, however, we have devoted the majority of our capital budget to drilling horizontal wells. Drilling horizontal wells is technologically more difficult than drilling vertical wells - including as a result of risks relating to our ability to fracture stimulate the planned number of stages and to successfully run casing the length of the well bore - and the risk of failure is therefore greater than the risk involved in drilling vertical wells. Additionally, drilling a horizontal well is typically far costlier than drilling a vertical well. This means that the risks of our drilling program will be spread over a smaller number of wells, and that, in order to be economic, each horizontal well will need to produce at a higher level in order to cover the higher drilling costs. In addition, we have transitioned to the use of multi-well pads instead of single-well sites. The use of multi-well pad drilling increases some operational risks because problems affecting the pad or a single well could adversely affect production from all of the wells on the pad. Pad drilling can also make our overall production, and therefore our revenue and cash flows, more volatile, because production from multiple wells on a pad will typically commence simultaneously. While we believe that we will be better served by drilling horizontal wells using multi-well pads, the risk component involved in such drilling will be increased in some respects, with the result that we might find it more difficult to achieve economic success in our drilling program. +Under the “successful efforts” accounting method that we use, unsuccessful exploratory wells must be expensed in the period when they are determined to be non-productive, which reduces our net income in such periods and could have a negative effect on our profitability. +We conduct exploratory drilling in order to identify additional opportunities for future development. Under the “successful efforts” method of accounting that we use, the cost of unsuccessful exploratory wells must be charged to expense in the period in which the wells are determined to be unsuccessful. In addition, lease costs for acreage condemned by the unsuccessful well must also be expensed. In contrast, unsuccessful development wells are capitalized as a part of the investment in the field where they are located. Because exploratory wells generally are more likely to be unsuccessful than development wells, we anticipate that some or all of our exploratory wells may not be productive. The costs of such unsuccessful exploratory wells could result in a significant reduction in our profitability in periods when the costs are required to be expensed and could have a negative effect on our ability to comply with our debt covenants. +Increasing finding and development costs may impair our profitability. +In order to continue to grow and maintain our profitability, we must add new reserves that exceed our production over time at a finding and development cost that yields an acceptable operating margin and DD&A rate. Without cost effective exploration, development or acquisition activities, our production, reserves and profitability will decline over time. Given the relative maturity of most crude oil and natural +22 +gas basins in North America and the high level of activity in the industry, the cost of finding new reserves through exploration and development operations has been increasing in some basins. The acquisition market for properties has become extremely competitive among producers for additional production and expanded drilling opportunities in North America. Acquisition values for crude oil properties have climbed in recent years and may continue to increase in the future. This increase in finding and development costs results in higher DD&A rates. If the upward trend in crude oil finding and development costs continues, we will be exposed to an increased likelihood of a write-down in the carrying value of our crude oil properties in response to any future decrease in commodity prices and/or reduction in the profitability of our operations. +Depressed natural gas prices could result in significant impairment charges and significant downward revisions of proved natural gas reserves. +The domestic natural gas market remains weak. Low natural gas prices could result in, among other adverse effects, significant impairment charges in the future. The cash flow model we use to assess properties for impairment includes numerous assumptions, such as management’s estimates of future oil and gas production and commodity prices, market outlook on forward commodity prices and operating and development costs. All inputs to the cash flow model must be evaluated at each date that the estimate of future cash flows for each producing basin is calculated. However, a significant decrease in long-term forward natural gas prices alone could result in a significant impairment for our properties that are sensitive to declines in natural gas prices. In December 2012, we recognized an impairment charge of $161.2 million associated with our Piceance Basin proved crude oil and natural gas properties. In 2013, we recognized additional charges of $48.8 million associated with our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin producing properties. Similar charges could occur in the future. In addition, low natural gas prices could result in significant downward revisions to our proved natural gas reserves. Future declines in crude oil prices could have similar effects. +Our development and exploration operations require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our production and reserves, and ultimately our profitability. +Our industry is capital intensive. We expect to continue to make substantial capital expenditures in our business and operations for the exploration, development, production and acquisition of crude oil, natural gas and NGL reserves. To date, we have financed capital expenditures primarily with bank borrowings under our revolving credit facility, cash generated by operations and proceeds from capital markets transactions and the sale of properties. We intend to finance our future capital expenditures utilizing similar financing sources. Our cash flows from operations and access to capital are subject to a number of variables, including: +• +our proved reserves; +• +the amount of crude oil, natural gas and NGLs we are able to produce from existing wells; +• +the prices at which crude oil, natural gas and NGLs are sold; +• +the costs to produce crude oil, natural gas and NGLs; and +• +our ability to acquire, locate and produce new reserves. +If our revenues or the borrowing base under our revolving credit facility decrease as a result of lower commodity prices, operating difficulties or for any other reason, our need for capital from other sources would increase, and there can be no assurance that such other sources of capital would be available at that time on reasonable terms or at all. If we raise funds by issuing additional equity securities, this would have a dilutive effect on existing shareholders. If we raise funds through the incurrence of debt, the risks we face with respect to our indebtedness would increase and we would incur additional interest expense. Our inability to obtain sufficient financing on acceptable terms would adversely affect our financial condition and profitability. +We have a substantial amount of debt and the cost of servicing, and risks related to refinancing, that debt could adversely affect our business. Those risks could increase if we incur more debt. +We have a substantial amount of indebtedness. As a result, a significant portion of our cash flows will be required to pay interest and principal on our indebtedness, and we may not generate sufficient cash flows from operations, or have future borrowing capacity available, to enable us to repay our indebtedness or to fund other liquidity needs. +Servicing our indebtedness and satisfying our other obligations will require a significant amount of cash. Our cash flows from operating activities and other sources may not be sufficient to fund our liquidity needs. Our ability to pay interest and principal on our indebtedness and to satisfy our other obligations will depend on our future operating performance and financial condition and the availability of refinancing indebtedness, which will be affected by prevailing economic conditions and financial, business and other factors, many of which are beyond our control. +A substantial decrease in our operating cash flows or an increase in our expenses could make it difficult for us to meet our debt service requirements and could require us to modify our operations, including by curtailing our exploration and drilling programs, selling assets, refinancing all or a portion of our existing debt or obtaining additional financing. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. Our ability to restructure or refinance our debt will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. In addition, the terms of future debt agreements may, and our existing debt agreements do, restrict us from implementing some of these alternatives. In the absence of adequate cash from operations and other available capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. We may not be able to consummate these dispositions for fair market value, in a timely manner or at all. Furthermore, any proceeds that we could realize from any dispositions may not be adequate to meet our debt service or other obligations then due. Because the cash required to service our indebtedness is not available to finance our operations +23 +and other business activities, our indebtedness limits our flexibility in planning for or reacting to changes in our business and the industry in which we operate and increases our vulnerability to economic downturns and sustained declines in commodity prices. +Covenants in our debt agreements currently impose, and future financing agreements may impose, significant operating and financial restrictions. +The indenture governing our senior notes and our revolving credit facility contain restrictions, and future financing agreements may contain additional restrictions, on our activities, including covenants that restrict our and certain of our subsidiaries’ ability to: +• +incur additional debt; +• +pay dividends on, redeem or repurchase stock; +• +create liens; +• +make specified types of investments; +• +apply net proceeds from certain asset sales; +• +engage in transactions with our affiliates; +• +engage in sale and leaseback transactions; +• +merge or consolidate; +• +restrict dividends or other payments from restricted subsidiaries; +• +sell equity interests of restricted subsidiaries; and +• +sell, assign, transfer, lease, convey or dispose of assets. +Our revolving credit facility is secured by all of our crude oil and natural gas properties as well as a pledge of all ownership interests in our operating subsidiaries. The restrictions contained in our debt agreements may prevent us from taking actions that we believe would be in the best interest of our business, and may make it difficult for us to successfully execute our business strategy or effectively compete with companies that are not similarly restricted. We may also incur future debt obligations that might subject us to additional restrictive covenants that could affect our financial and operational flexibility. Similar issues may arise with respect to PDCM’s debt agreements, which, among other things, limit PDCM’s ability to pay dividends to us. +Our revolving credit facility has substantial restrictions and financial covenants and our ability to comply with those restrictions and covenants is uncertain. Our lenders can unilaterally reduce our borrowing availability based on anticipated commodity prices. +We depend in large part on our revolving credit facility for future capital needs. The terms of the credit agreement require us to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flows from operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants under the revolving credit facility or other debt agreements could result in a default under those agreements, which could cause all of our existing indebtedness to be immediately due and payable. +The revolving credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion based upon projected revenues from the properties securing their loan. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the revolving credit facility. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other crude oil and natural gas properties as additional collateral. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under the revolving credit facility. Our inability to borrow additional funds under our revolving credit facility could adversely affect our operations and our financial results. PDCM is subject to each of the foregoing risks with respect to its revolving credit facility and its term loan agreement. +If we are unable to comply with the restrictions and covenants in the agreements governing our indebtedness, there would be a default under the terms of these agreements, which could result in an acceleration of payment of funds that we have borrowed and would impact our ability to make principal and interest payments on our indebtedness and satisfy our other obligations. +Any default under the agreements governing our indebtedness, including a default under our revolving credit facility that is not waived by the required lenders, and the remedies sought by the holders of any such indebtedness, could make us unable to pay principal and interest on our indebtedness and satisfy our other obligations. If we are unable to generate sufficient cash flows and are otherwise unable to obtain funds necessary to meet required payments of principal and interest on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants, in the instruments governing our indebtedness, we could be in default under the terms of the agreements governing such indebtedness. In the event of such default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest, the lenders under our revolving credit facility could elect to terminate their commitments, cease making further loans and institute foreclosure proceedings against our assets, and we could be forced into bankruptcy or liquidation. If our operating performance declines, we may in the future need to seek to obtain waivers from the required lenders under our revolving credit facility to avoid being in default. If we breach our covenants under our revolving credit facility and seek a waiver, we may not be able to obtain a waiver from the required lenders. If this occurs, we would be in default under our revolving credit facility, the lenders could exercise their rights as described above, and we could be forced into bankruptcy or liquidation. We cannot assure you that we will be granted waivers or amendments to our debt agreements if for any reason we are unable to comply with these agreements, or that we will be able to refinance our debt on terms acceptable to us, or at all. PDCM is subject to each of the foregoing risks with respect to its debt agreements. As of June 30 and September 30, 2013, PDCM was not in compliance with certain financial covenants in its debt agreements. It was able to obtain a waiver for these defaults from its lenders in July and October 2013, respectively. However, there can be no assurance that similar waivers will be available if needed in the future. +24 +Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly. +Borrowings under our revolving credit facility bear interest at variable rates and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase although the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness and for other purposes would decrease. +Notwithstanding our current indebtedness levels and restrictive covenants, we may still be able to incur substantial additional debt, which could exacerbate the risks described above. +We may be able to incur additional debt in the future. Although our debt agreements contain restrictions on our ability to incur indebtedness, those restrictions are subject to a number of exceptions. In particular, we may borrow under the revolving credit facility. We may also consider investments in joint ventures or acquisitions that may increase our indebtedness. Adding new debt to current debt levels could intensify the related risks that we and our subsidiaries now face. +Seasonal weather conditions and lease stipulations can adversely affect our operations. +Seasonal weather conditions and lease stipulations designed to protect wildlife affect operations in some areas. In certain areas drilling and other activities may be restricted or prohibited by lease stipulations, or prevented by weather conditions, for significant periods of time. This limits our operations in those areas and can intensify competition during the active months for drilling rigs, oil field equipment, services, supplies and qualified personnel, which may lead to additional or increased costs or periodic shortages. These constraints and the resulting high costs or shortages could delay our operations and materially increase operating and capital costs and therefore adversely affect our profitability. Similarly, hot weather during some recent periods adversely impacted the operation of certain midstream facilities, and therefore our production. Similar events could occur in the future and could negatively impact our results of operations and cash flows. +We have limited control over activities on properties in which we own an interest but we do not operate, which could reduce our production and revenues. +We operate approximately 91% of the wells in which we own an interest. If we do not operate the properties in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of the underlying properties. The success and timing of drilling and development activities on properties operated by others therefore depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise (including safety and environmental compliance) and financial resources, inclusion of other participants in drilling wells, and use of technology. The failure by an operator to adequately perform operations, or an operator’s breach of the applicable agreements, could reduce production and revenues and adversely affect our profitability. These risks have been increasing for us in recent years as our capital expenditures for non-operated projects have risen significantly, and are expected to rise further in 2014. +Our derivative activities could result in financial losses or reduced income from failure to perform by our counterparties or could limit our potential gains from increases in prices. +We use derivatives for a portion of the production from our own wells, our partnerships and for natural gas purchases and sales by our marketing subsidiary to achieve more predictable cash flows, to reduce exposure to adverse fluctuations in commodity prices, and to allow our natural gas marketing company to offer pricing options to natural gas sellers and purchasers. These arrangements expose us to the risk of financial loss in some circumstances, including when purchases or sales are different than expected or the counterparty to the derivative contract defaults on its contractual obligations. In addition, many of our derivative contracts are based on WTI or another oil or natural gas index price. The risk that the differential between the index price and the price we receive for the relevant production may change unexpectedly makes it more difficult to hedge effectively and increases the risk of a hedging-related loss. +Also, derivative arrangements may limit the benefit we would otherwise receive from increases in the prices for the relevant commodity, and they may require the use of our resources to meet cash margin requirements. Since we do not designate our derivatives as hedges, we do not currently qualify for use of hedge accounting; therefore, changes in the fair value of derivatives are recorded in our income statements, and our net income is subject to greater volatility than it would be if our derivative instruments qualified for hedge accounting. For instance, if commodity prices rise significantly, this could result in significant non-cash charges during the relevant period, which could have a material negative effect on our net income. +The inability of one or more of our customers or other counterparties to meet their obligations may adversely affect our financial results. +Substantially all of our accounts receivable result from our crude oil, natural gas and NGLs sales or joint interest billings to a small number of third parties in the energy industry. This concentration of customers and joint interest owners may affect our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, our derivatives as well as the derivatives used by our marketing subsidiary expose us to credit risk in the event of nonperformance by counterparties. Nonperformance by our customers or derivative counterparties may adversely affect our financial condition and profitability. We face similar risks with respect to our other counterparties, including the lenders under our revolving credit facility and the providers of our insurance coverage. +25 +Our business could be negatively impacted by security threats, including cybersecurity threats, and other disruptions. +As a crude oil and natural gas producer, we face various security threats, including attempts by third parties 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 infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. There can be no assurance that the procedures and controls we use to monitor these threats and mitigate our exposure to them will be sufficient in preventing them 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 condition, results of operations, or cash flows. +Our insurance coverage may not be sufficient to cover some liabilities or losses that we may incur. +The occurrence of a significant accident or other event not fully covered by insurance or in excess of our insurance coverage could have a material adverse effect on our operations and financial condition. Insurance does not protect us against all operational risks. We do not carry business interruption insurance at levels that would provide enough funds for us to continue operating without access to other funds. We also do not carry contingent business interruption insurance related to the purchasers of our production. In addition, pollution and environmental risks are generally not fully insurable. +We may not be able to keep pace with technological developments in our industry. +Our industry is characterized by rapid and significant technological advancements. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement those or other new technologies at substantial cost. In addition, our 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. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we were unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected. +Competition in our industry is intense, which may adversely affect our ability to succeed. +Our industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce crude oil, natural gas and NGLs, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, larger companies may have a greater ability to continue exploration activities during periods of low commodity prices. Larger competitors may also be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which could adversely affect our competitive position. These factors could adversely affect the success of our operations and our profitability. +Acquisitions of properties are subject to the uncertainties of evaluating recoverable reserves and potential liabilities, including environmental uncertainties. +Acquisitions of producing properties and undeveloped properties have been an important part of our historical and recent growth. We expect acquisitions will also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, many of which are beyond our control. These factors include recoverable reserves, development potential, future commodity prices, operating costs, title issues and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform engineering, environmental, geological and geophysical reviews of the acquired properties, which we believe are generally consistent with industry practices. However, such reviews are not likely to permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well prior to an acquisition and our ability to evaluate undeveloped acreage is inherently imprecise. Even when we inspect a well, we may not always discover structural, subsurface and environmental problems that may exist or arise. In some cases, our review prior to signing a definitive purchase agreement may be even more limited. In addition, we often acquire acreage without any warranty of title except as to claims made by, through or under the transferor. +When we acquire properties, we will generally have potential exposure to liabilities and costs for environmental and other problems existing on the acquired properties, and these liabilities may exceed our estimates. Often we are not entitled to contractual indemnification associated with acquired properties. We often acquire interests in properties on an “as is” basis with no or limited remedies for breaches of representations and warranties. Therefore, we could incur significant unknown liabilities, including environmental liabilities, or losses due to title defects, in connection with acquisitions for which we have limited or no contractual remedies or insurance coverage. In addition, the acquisition of undeveloped acreage is subject to many inherent risks and we may not be able to realize efficiently, or at all, the assumed or expected economic benefits of acreage that we acquire. +Additionally, significant acquisitions can change the nature of our operations depending upon the character of the acquired properties, which may have substantially different operating and geological characteristics or may be in different geographic locations than our existing properties. These factors can increase the risks associated with an acquisition. Acquisitions also present risks associated with the additional indebtedness that may be required to finance the purchase price, and any related increase in interest expense or other related charges. +26 +A failure to complete successful acquisitions would limit our growth. +Because our crude oil and natural gas properties are depleting assets, our future reserves, production volumes and cash flows depend on our success in developing and exploiting our current reserves efficiently and finding or acquiring additional recoverable reserves economically. Acquiring additional crude oil and natural gas properties, or businesses that own or operate such properties, when attractive opportunities arise is a significant component of our strategy. We may not be able to identify attractive acquisition opportunities. If we do identify an appropriate acquisition candidate, we may be unable to negotiate mutually acceptable terms with the seller, finance the acquisition or obtain the necessary regulatory approvals. If we are unable to complete suitable acquisitions, it will be more difficult to replace our reserves, and an inability to replace our reserves would have a material adverse effect on our financial condition and results of operations. +Certain federal income tax deductions currently available with respect to crude oil and natural gas and exploration and development may be eliminated as a result of future legislation. +The administration of U.S. President Barack Obama has proposed to eliminate certain key U.S. federal income tax preferences currently available with respect to crude oil and natural gas exploration and production. The proposals include, but are not limited to (i) the repeal of the percentage depletion allowance for crude oil and natural gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is not possible at this time to predict how legislation or new regulations that may be adopted to address these proposals would impact our business, but any such future laws and regulations could result in higher federal income taxes, which could negatively affect our financial condition and results of operations. In addition, proposals are made from time to time in states where we operate to implement or increase severance or other taxes at the state level, and any such additional taxes would have similarly adverse effects on us. +Derivatives legislation and regulation could adversely affect our ability to hedge crude oil and natural gas prices and increase our costs and adversely affect our profitability. +In July 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”). The Dodd-Frank Act regulates derivative transactions, including our commodity hedging swaps, and could have a number of adverse effects on us, including the following: +• +The Dodd-Frank Act may limit our ability to enter into hedging transactions, thus exposing us to additional risks related to commodity price volatility; commodity price decreases would then have an increased adverse effect on our profitability and revenues. Reduced hedging may also impair our ability to have certainty with respect to a portion of our cash flows, which could lead to decreases in capital spending and, therefore, decreases in future production and reserves. +• +If, as a result of the Dodd-Frank Act or its implementing regulations, we are required to post cash collateral in connection with our derivative positions, this would likely make it impracticable to implement our current hedging strategy. +• +Our derivatives counterparties will be subject to significant new capital, margin and business conduct requirements imposed as a result of the Dodd-Frank Act. We expect that these requirements will increase the cost to hedge because there will be fewer counterparties in the market and increased counterparty costs will be passed on to us. +The above factors could also affect the pricing of derivatives and make it more difficult for us to enter into hedging transactions on favorable terms. +Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the crude oil, natural gas and NGLs that we produce while physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects. +In December 2009, EPA published its findings 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 EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings provide the basis for EPA to adopt and implement regulations that would restrict emissions of greenhouse gases under existing provisions of the CAA. In June 2010, EPA published its final rule to address the permitting of greenhouse gas emissions from stationary sources under the CAA’s Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. This rule “tailors” these permitting programs to apply to certain stationary sources of greenhouse gas emissions in a multi-step process, with the largest sources first subject to permitting. It is widely expected that facilities required to obtain PSD permits for their greenhouse gas emissions will be required to also reduce those emissions according to “best available control technology” (“BACT”) standards. In its permitting guidance for greenhouse gases, issued in November 2010, EPA recommended options for BACT from the largest sources, which include improved energy efficiency, among others. EPA has recently issued a final rule retaining the current “tailored” permitting thresholds, opting not to extend greenhouse gas permitting requirements to smaller stationary sources at this time. EPA, however, intends to revisit these thresholds again by 2016. Should it do so, it is possible the onshore crude oil and natural gas sector will be included. +In June 2012, the United States Court of Appeals for the District of Columbia Circuit issued an opinion and order in Coalition for Responsible Regulation v. Environmental Protection Agency , upholding EPA’s greenhouse gas-related rules, including the “Tailoring Rule,” against challenges from various state and industry group petitioners. In October 2013, the United States Supreme Court in Utility Air Regulatory Group v. EPA , accepted a petition for certiorari to decide whether EPA correctly determined that its regulation of greenhouse gases from mobile sources triggered permitting requirements under the CAA for stationary sources that emit greenhouse gases. The Court’s decision is expected in the spring or summer of 2014 and will have significant implications for the regulation of greenhouse gases from stationary sources, including those in the oil and gas sector. Any regulatory or permitting obligation that limits emissions of greenhouse gases could require us to incur +27 +costs to reduce and monitor emissions of greenhouse gases associated with our operations and also adversely affect demand for the crude oil and natural gas that we produce. +In the past, Congress has considered various pieces of legislation to reduce emissions of greenhouse gases. Congress has not adopted any significant legislation in this respect to date, but could do so in the future. For example, if Congress undertakes comprehensive tax reform in the coming year, it is possible that such measures could include a carbon tax, which could result in additional direct costs to our operations. In the absence of such national legislation, many states and regions have 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. For example, Colorado has proposed to directly regulate methane emissions from the oil and gas sector in its recently proposed oil and gas air emissions rules. +President Obama has indicated that climate change and greenhouse gas regulation is a significant priority for his second term. The President issued a Climate Action Plan in June 2013 that, among other things, calls for a reduction in methane emissions from the oil and gas sector. In November 2013, the President released an Executive Order charging various federal agencies, including EPA, with devising and pursuing strategies to improve the country’s preparedness and resilience to climate change. In part through these executive actions, the direct regulation of methane emissions from the oil and gas sector continues to be a focus of regulation. In addition to the proposed Colorado rules discussed above, a lawsuit has been filed by several northeastern states that would require EPA to more stringently regulate methane emissions from the oil and gas sector. The passage of legislation, or executive and other initiatives that limit emissions of greenhouse gases from our equipment and operations, could require us to incur costs to reduce the greenhouse gas emissions, and it could also adversely affect demand for the crude oil and natural gas that we produce. +Some have suggested that one consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods. Recent flooding in Colorado is an example of an extreme weather event that negatively impacted our operations. If such events were to continue to occur, or become more frequent, our operations could be adversely affected in various ways, including through damage to our facilities from increased costs for insurance. +Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we produce. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is difficult to predict how the market for our fuels could be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business. +The cost of defending any suits brought against us with respect to our royalty payment practices, and any judgments resulting from such suits, could have an adverse effect on our results of operations and financial condition. +In recent years, litigation has commenced against us and other companies in our industry regarding royalty practices and payments in jurisdictions where we conduct business. We intend to defend ourselves vigorously in these cases. The costs of defending these suits can be significant, even when we ultimately succeed in having them dismissed. These costs would be reflected in terms of dollar outlay, as well as the amount of time, attention and other resources that our management would have to appropriate to the defense. A judgment in favor of a plaintiff in a suit of this type could have a material adverse effect on our financial condition and profitability. +PDCM is dependent upon our equity partner and poses exit-related risks for us. +The board of managers of PDCM consists of three representatives appointed by us and three representatives appointed by our equity partner Lime Rock Partners, LP, each with equal voting power. The joint venture agreement generally requires the affirmative vote of a majority of the members of the board to approve an action, and we and Lime Rock may not always agree on the best course of action for the joint venture. If such a disagreement were to occur, we would not be able to cause the joint venture to take action that we believed to be in its best interests. Consequently, our best interests may not be advanced and our investment in the joint venture could be adversely affected. If there is a disagreement about a development plan and budget for the joint venture, Lime Rock is entitled to unilaterally suspend substantially all of the operations of the joint venture, which could have a material adverse impact on the results of operations of the joint venture and our investment. Such a suspension could last for up to two years, at which point either party could elect to dissolve the joint venture or to sell its ownership interests to a third party. Lime Rock is entitled in some cases to a preference with respect to liquidating distributions and proceeds from significant sales of ownership interests up to the amount of its contributed capital, which would diminish our returns if the value of the joint venture had declined at the time of the liquidation or sale. +Lime Rock is entitled to seek to sell its interest in the joint venture to a third party, subject to rights of first offer and refusal in favor of us. If we do not exercise those rights in a sale involving all of Lime Rock’s ownership interests, Lime Rock can exercise “drag-along” rights and compel us to sell all of our interests in the proposed transaction. Accordingly, if we possessed insufficient funds and were unable to obtain financing necessary to purchase Lime Rock’s interest under the rights of first offer and refusal, Lime Rock might sell its interests in the joint venture to a third party with whom we might have a difficult time dealing and in managing the joint venture or we may be required to sell our interest in the joint venture at a time when we may not wish to do so. Under these circumstances, our investment in the joint venture could be adversely affected. +Our articles of incorporation, bylaws, stockholders rights plan and Nevada law contain provisions that may have an anti-takeover effect and may delay, defer or prevent a tender offer or takeover attempt, which may adversely affect the market price of our common stock. +28 +Our articles of incorporation authorize our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. We have adopted a stockholders rights plan that will dilute the stock ownership of certain acquirers of our common stock upon the occurrence of certain events. In addition, some provisions of our articles of incorporation, bylaws and Nevada law could make it more difficult for a third party to acquire control of us, including: +• +the organization of our board of directors as a classified board, which allows no more than one-third of our directors to be elected each year; +• +limitations on the ability of our shareholders to call special meetings; and +• +certain Nevada anti-takeover statutes. +Because we have no plans to pay dividends on our common stock, investors must look solely to stock appreciation for a return on their investment in us. +We have never declared or paid cash dividends on our common stock. We currently intend to retain all future earnings and other cash resources, if any, for the operation and development of our business and do not anticipate paying cash dividends in the foreseeable future. Payment of any future dividends will be at the discretion of our board of directors after taking into account many factors, including our financial condition, operating results, current and anticipated cash needs and plans for expansion. In addition, our revolving credit facility and the indenture governing our senior notes limit our ability to pay cash dividends on our common stock. Any future dividends may also be restricted by any debt agreements which we may enter into from time to time. +Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities. +Unless production is established within the spacing units covering the undeveloped acres on which some of our drilling locations are identified, our leases for such acreage will expire. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. As such, our actual drilling activities may differ materially from our current expectations, which could adversely affect our business. +We may incur losses as a result of title defects in the properties in which we invest. +It is our practice in acquiring oil and gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest at the time of acquisition. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. Leases in the Appalachia-Marcellus and Utica areas are particularly vulnerable to title deficiencies due the long history of land ownership in the area, resulting in extensive and complex chains of title. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property. +ITEM 1B. UNRESOLVED STAFF COMMENTS +None. +ITEM 3. LEGAL PROCEEDINGS +Information regarding our legal proceedings can be found in Note 11, Commitments and Contingencies – Litigation , to our consolidated financial statements included elsewhere in this report. +ITEM 4. MINE SAFETY DISCLOSURES +Not applicable. +29 +PART II +ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDERS MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES +Our common stock, par value $0.01 per share, is traded on the NASDAQ Global Select Market under the symbol PDCE. The following table sets forth the range of high and low sales prices for our common stock for each of the periods presented: +Price Range +High +Low +January 1 - March 31, 2012 +$ +40.26 +$ +28.61 +April 1 - June 30, 2012 +37.63 +19.33 +July 1 - September 30, 2012 +34.25 +23.27 +October 1 - December 31, 2012 +36.55 +25.76 +January 1 - March 31, 2013 +53.80 +33.39 +April 1 - June 30, 2013 +55.56 +38.02 +July 1 - September 30, 2013 +66.03 +51.46 +October 1 - December 31, 2013 +73.93 +51.32 +As of February 7, 2014 , we had approximately 707 shareholders of record. Since inception, no cash dividends have been declared on our common stock. Cash dividends are restricted under the terms of our revolving credit facility and the indenture governing our 7.75% senior notes due 2022 and we presently intend to continue a policy of using retained earnings for expansion of our business. See Note 8, Long-term Debt , to our consolidated financial statements included elsewhere in this report. +The following table presents information about our purchases of our common stock during the three months ended December 31, 2013 : +Period +Total Number of Shares Purchased (1) +Average Price Paid per Share +October 1 - 31, 2013 +1,086 +$ +60.83 +November 1 - 30, 2013 +7,762 +59.94 +December 1 - 31, 2013 +— +— +Total fourth quarter purchases +8,848 +60.05 +__________ +(1) +Purchases primarily represent shares purchased from employees for the payment of their tax liabilities related to the vesting of securities issued pursuant to our stock-based compensation plans. +30 +SHAREHOLDER PERFORMANCE GRAPH +The performance graph below compares the cumulative total return of our common stock over the five-year period ended December 31, 2013 , with the cumulative total returns for the same period for the Standard and Poor's ("S&P") 500 Index and the Standard Industrial Code ("SIC") Index. The SIC Index is a weighted composite of 267 crude petroleum and natural gas companies. The cumulative total shareholder return assumes that $100 was invested, including reinvestment of dividends, if any, in our common stock on December 31, 2008 and in the S&P 500 Index and the SIC Index on the same date. The results shown in the graph below are not necessarily indicative of future performance. +31 +ITEM 6. SELECTED FINANCIAL DATA +Year Ended/As of December 31, +2013 +2012 +2011 +2010 +2009 +(in millions, except per share data and as noted) +Statement of Operations (from continuing operations): +Crude oil, natural gas and NGLs sales +$ +359.4 +$ +238.4 +$ +223.3 +$ +146.0 +$ +115.8 +Commodity price risk management gain (loss), net +(23.9 +) +$ +32.3 +46.1 +59.9 +(10.1 +) +Total revenues +411.3 +320.6 +337.3 +276.6 +169.6 +Income (loss) from continuing operations +(26.5 +) +(21.7 +) +22.6 +18.1 +(62.8 +) +Earnings per share from continuing operations: +Basic +$ +(0.82 +) +$ +(0.78 +) +$ +0.96 +$ +0.94 +$ +(3.71 +) +Diluted +(0.82 +) +(0.78 +) +0.95 +0.92 +(3.71 +) +Statement of Cash Flows: +Net cash from: +Operating activities +$ +159.2 +$ +174.7 +$ +166.8 +$ +151.8 +$ +143.9 +Investing activities +(217.1 +) +(451.9 +) +(456.4 +) +(300.9 +) +(142.3 +) +Financing activities +248.7 +271.4 +243.4 +171.5 +(20.6 +) +Capital expenditures +394.9 +347.7 +334.5 +162.7 +143.0 +Acquisitions of crude oil and natural gas properties +9.7 +312.2 +145.9 +158.1 +— +Balance Sheet: +Total assets +$ +2,025.2 +$ +1,826.8 +$ +1,698.0 +$ +1,389.0 +$ +1,250.3 +Working capital +112.4 +(31.4 +) +(22.0 +) +16.2 +32.9 +Long-term debt +657.0 +676.6 +532.2 +295.7 +280.7 +Total equity +967.6 +703.2 +664.1 +642.2 +538.6 +Pricing and Lifting Costs Relating to Continuing Operations (per Boe): +Average sales price (excluding net settlements on derivatives) +$ +48.37 +$ +43.42 +$ +48.37 +$ +44.13 +$ +34.12 +Average lifting cost (1) +5.01 +5.00 +4.98 +4.12 +4.28 +Production (MBoe): +Production from continuing operations +7,429.5 +5,489.9 +4,616.2 +3,383.3 +3,393.4 +Production from discontinued operations +1,127.8 +2,835.3 +3,304.5 +3,056.1 +3,820.7 +Total production +8,557.3 +8,325.2 +7,920.7 +6,439.4 +7,214.1 +Total proved reserves (MMBoe) (2)(3)(4) +265.8 +192.8 +169.3 +143.4 +119.6 +______________ +(1) +Lifting costs represent lease operating expenses, excluding production taxes, on a per unit basis. +(2) +Includes total proved reserves related to our Piceance Basin and NECO assets of 14.1 MMBoe, 59.5 MMBoe, 76.4 MMBoe and 68.3 MMBoe as of December 31, 2012, 2011, 2010 and 2009, respectively. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of our Piceance Basin and NECO assets. +(3) +Includes total proved reserves related to our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin assets of 2 MMBoe, 3 MMBoe, 4 MMBoe and 8 MMBoe as of December 31, 2012, 2011, 2010 and 2009, respectively. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin assets. +(4) +Includes total proved reserves related to our Permian Basin assets of 10.8 MMBoe and 5.4 MMBoe as of December 31, 2011 and 2010, respectively. Our Permian assets were held for sale as of December 31, 2011 and divested in February 2012. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of our Permian assets. +32 +ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +The following discussion and analysis, as well as other sections in this report, should be read in conjunction with our consolidated financial statements and related notes to consolidated financial statements included elsewhere in this report. Further, we encourage you to revisit the Special Note Regarding Forward-Looking Statements in Part I of this report. +EXECUTIVE SUMMARY +2013 Financial Overview +Crude oil, natural gas and NGLs sales from continuing operations increased in 2013 by $121.0 million , or 50.8% , compared to 2012. The growth in crude oil, natural gas and NGLs sales was the result of increased production and higher prices. For the month ended December 31, 2013 , we maintained an average production rate of 27 MBoe per day. Production of 7.4 MMboe from continuing operations for the year ended December 31, 2013 represents an increase of 35% as compared to the year ended December 31, 2012 , primarily attributable to our successful horizontal Niobrara and Codell drilling program in the Wattenberg Field. Crude oil production from continuing operations increased 46% in 2013, while NGLs production from continuing operations increased 25% . Our liquids percentage of total production from continuing operations was 53% in 2013 compared to 51% during 2012. Natural gas production from continuing operations increased 30% in 2013 compared to 2012. +Available liquidity as of December 31, 2013 was $647.0 million , including $16.1 million related to PDCM, compared to $398.6 million, including $14.1 million related to PDCM, as of December 31, 2012. Available liquidity is comprised of $193.2 million of cash and cash equivalents and $453.8 million available for borrowing under our revolving credit facilities. In August 2013, we completed a public offering of 5,175,000 shares of our common stock, par value $0.01 per share, at a price to us of $53.37 per share, for net proceeds of approximately $276 million , after deducting offering expenses and underwriting discounts. We expect to use the remaining net proceeds from the offering to fund a portion of our 2014 capital program and for general corporate purposes. We believe we have sufficient liquidity to allow us to execute our expanded drilling program through 2014. On October 31, 2013, we completed the semi-annual redetermination of our revolving credit facility's borrowing base. Our available borrowing base was reaffirmed at $450 million. +Operational Overview +Drilling Activities. During 2013, we continued to execute our strategic plan of increasing production while increasing our production mix of crude oil and NGLs by focusing our drilling operations primarily in the liquid-rich Wattenberg Field in Colorado and the emerging Utica Shale play in southeastern Ohio. +In the Wattenberg Field, we are currently running four drilling rigs and recently completed and are producing from our first 16 horizontal wells per section downspacing project. In 2013, we spudded 70 horizontal wells in the Wattenberg Field, 54 of which were completed, and participated in 49 gross, 10.4 net, horizontal non-operated drilling projects. In the Utica Shale, we spudded 11 horizontal wells in 2013, nine of which were completed and connected to a gathering line and two of which were in various stages of completion as of December 31, 2013 . In the Appalachia-Marcellus Shale, PDCM spudded 14 horizontal wells in 2013, 10 of which were completed and turned-in-line as of December 31, 2013 . +Divestiture of Crude Oil and Natural Gas Properties. In February 2013, we entered into a purchase and sale agreement with certain affiliates of Caerus pursuant to which we agreed to sell to Caerus our Piceance Basin, NECO and certain other non-core Colorado oil and gas properties, leasehold mineral interests and related assets. This divestiture was completed in June 2013 with total consideration of approximately $177.6 million , with an additional $17.0 million paid to our non-affiliated investor partners in our affiliated partnerships. The sale resulted in a pre-tax loss of $2.3 million . The proceeds from the asset divestiture were used to pay down our revolving credit facility and to fund a portion of our 2013 capital budget. Following the sale to Caerus, we do not have significant continuing involvement in the operations of, or cash flows from, the Piceance Basin and NECO oil and gas properties. Accordingly, the results of operations related to these assets have been separately reported as discontinued operations for all periods presented in our consolidated financial statements included elsewhere in this report. +In October 2013, we executed a purchase and sale agreement for the sale of our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin crude oil and natural gas properties owned directly by us, as well as through our proportionate share of PDCM. The properties consisted of approximately 3,500 gross shallow producing wells, related facilities and associated leasehold acreage, limited to the Upper Devonian and shallower formations. Substantially all of the divestiture closed in December 2013 for aggregate consideration of approximately $20.6 million , of which our share of the proceeds was approximately $5.1 million , subject to certain post-closing adjustments. Concurrent with the closing of the transaction, our $6.7 million irrevocable standby letter of credit and an agreement for firm transportation services was released and novated to the buyer. We retained all zones, formations and intervals below the Upper Devonian formation, including the Marcellus Shale, Utica Shale and Huron Shale, as well as the Marcellus-related midstream assets. +Colorado Flooding. In September 2013, we experienced widespread flooding in our Wattenberg Field operations in Weld County, Colorado, which resulted in a shut-in of approximately 200 vertical wells, approximately 40 of which remained shut-in as of December 31, 2013. Through December 31, 2013 , we have expensed approximately $0.9 million and have capitalized approximately $1.1 million as a result of performing remediation operations. Assessment of the full economic impact of the flooding is ongoing and we expect to incur approximately $1 million to $2 million in additional costs during the first quarter of 2014 to replace damaged well equipment and to bring vertical wells back on-line. +33 +2014 Operational Outlook +We expect our production for 2014 to range between 9.5 MMBoe to 10 MMBoe. Our 2014 $647 million capital budget, of which $16 million represents our share of PDCM's capital budget, is expected to be used primarily for development drilling and selective acquisition of additional acreage. This budget includes $576 million of development capital and $71 million for leasehold acquisitions, exploration and other expenditures. We may revise our capital budget during the year as a result of, among other things, acquisitions or dispositions of assets, drilling results, commodity prices, changes in our borrowing capacity and/or significant changes in cash flows. +Wattenberg Field. We expect to invest approximately $467 million in the Wattenberg Field in 2014, continuing with a four-rig drilling program with plans to add a fifth operated horizontal drilling rig in the second quarter of 2014. We plan to spud 115 gross operated horizontal wells, comprised of 59 horizontal Codell wells and 56 horizontal Niobrara wells. Approximately $100 million of the total Wattenberg Field capital budget is expected to be allocated to non-operated projects, including participation in a 26-well pad in the Niobrara formation in the northeastern portion of the core Wattenberg Field. We also plan to reinitiate a modest vertical well refracturing program. +Utica Shale. We expect to invest approximately $162 million in the Utica Shale to spud 18 horizontal wells, including eight wells in our northern acreage and 10 wells in our southern acreage. A second drilling rig is expected to be deployed in the second half of 2014. The Utica capital budget includes approximately $30 million to acquire additional contiguous leasehold. +Marcellus Shale. PDCM's 2014 capital budget is $32 million, of which $16 million represents our share, and is expected to be utilized to finalize drilling and completion operations on horizontal wells that were in-process at December 31, 2013 and for midstream infrastructure. PDCM's capital budget is expected to be funded by PDCM's operating activities, borrowing under its credit facility or other financing transactions. PDCM has elected to temporarily suspend drilling activities in the Marcellus Shale. +Non-U.S. GAAP Financial Measures +We use "adjusted cash flows from operations," "adjusted net income (loss)," "adjusted EBITDA" and "PV-10," non-U.S. GAAP financial measures, for internal management reporting, when evaluating period-to-period changes and, in some cases, providing public guidance on possible future results. These measures are not measures of financial performance under U.S. GAAP and should be considered in addition to, not as a substitute for, net income (loss) or cash flows from operations, investing or financing activities, or standardized measure, as applicable, and should not be viewed as liquidity measures or indicators of cash flows reported in accordance with U.S. GAAP. The non-U.S. GAAP financial measures that we use may not be comparable to similarly titled measures reported by other companies. Also, in the future, we may disclose different non-U.S. GAAP financial measures in order to help our investors more meaningfully evaluate and compare our future results of operations to our previously reported results of operations. We strongly encourage investors to review our financial statements and publicly filed reports in their entirety and to not rely on any single financial measure. See Reconciliation of Non-U.S. GAAP Financial Measures for a detailed description of these measures, as well as a reconciliation of each to the most comparable U.S. GAAP measure. +34 +Results of Operations +Summary Operating Results +The following table presents selected information regarding our operating results from continuing operations: +Year Ended December 31, +Percent Change +2013 +2012 +2011 +2013-2012 +2012-2011 +(dollars in millions, except per unit data) +Production (1) +Crude oil (MBbls) +2,909.7 +1,987.8 +1,675.7 +46.4 +% +18.6 +% +Natural gas (MMcf) +20,859.6 +15,988.6 +13,370.1 +30.5 +% +19.6 +% +NGLs (MBbls) +1,043.2 +837.3 +712.1 +24.6 +% +17.6 +% +Crude oil equivalent (MBoe) (2) +7,429.5 +5,489.9 +4,616.2 +35.3 +% +18.9 +% +Average MBoe per day +20.4 +15.0 +12.6 +36.0 +% +19.0 +% +Crude Oil, Natural Gas and NGLs Sales +Crude oil +$ +261.6 +$ +173.5 +$ +147.2 +50.8 +% +20.4 +% +Natural gas +68.6 +42.0 +49.3 +63.3 +% +(14.8 +)% +NGLs +29.2 +22.9 +26.8 +27.5 +% +(14.6 +)% +Total crude oil, natural gas and NGLs sales +$ +359.4 +$ +238.4 +$ +223.3 +50.8 +% +6.8 +% +Net Settlements on Derivatives (3) +Natural gas +$ +16.0 +$ +49.9 +$ +29.1 +(67.9 +)% +71.5 +% +Crude oil +(3.1 +) +(0.5 +) +(11.9 +) +* +(95.8 +)% +Total net settlements on derivatives +$ +12.9 +$ +49.4 +$ +17.2 +(73.9 +)% +187.2 +% +Average Sales Price (excluding net settlements on derivatives) +Crude oil (per Bbl) +$ +89.92 +$ +87.27 +$ +87.44 +3.0 +% +(0.2 +)% +Natural gas (per Mcf) +3.29 +2.63 +3.74 +25.1 +% +(29.7 +)% +NGLs (per Bbl) +27.97 +27.33 +37.62 +2.3 +% +(27.4 +)% +Crude oil equivalent (per Boe) +48.37 +43.42 +48.37 +11.4 +% +(10.2 +)% +Average Lifting Cost (per Boe) (4) +Wattenberg Field +$ +4.72 +$ +4.23 +$ +4.40 +11.6 +% +(3.9 +)% +Utica Shale +1.53 +7.37 +— +(79.2 +)% +* +Appalachia-Marcellus Shale +7.00 +8.29 +7.99 +(15.6 +)% +3.8 +% +Weighted-average +5.01 +5.00 +4.98 +0.2 +% +0.4 +% +Natural Gas Marketing Contribution Margin (5) +$ +(0.3 +) +$ +0.4 +$ +0.7 +* +(42.9 +)% +Other Costs and Expenses +Exploration expense +$ +7.0 +$ +20.9 +$ +5.7 +(66.3 +)% +264.4 +% +Impairment of crude oil and natural gas properties +53.4 +5.9 +2.3 +* +156.2 +% +General and administrative expense +64.0 +58.8 +61.5 +8.8 +% +(4.3 +)% +Depreciation, depletion, and amortization +127.3 +98.8 +87.6 +28.8 +% +12.7 +% +Loss on extinguishment of debt +$ +— +$ +23.3 +$ +— +(100.0 +)% +* +Interest Expense +$ +51.9 +$ +48.3 +$ +37.0 +7.5 +% +30.6 +% +* +Percentage change is not meaningful or equal to or greater than 300%. +Amounts may not recalculate due to rounding. +______________ +(1) +Production is net and determined by multiplying the gross production volume of properties in which we have an interest by our ownership percentage. For total production volume, including discontinued operations, see Part I, Item 6, Selected Financial Data. +(2) +One Bbl of crude oil or NGL equals six Mcf of natural gas. +(3) +Represents net settlements on derivatives related to crude oil and natural gas sales, which do not include net settlements on derivatives related to natural gas marketing. +(4) +Represents lease operating expenses, exclusive of production taxes, on a per unit basis. +(5) +Represents sales from natural gas marketing, net of costs of natural gas marketing, including net settlements and net change in fair value of unsettled derivatives related to natural gas marketing activities. +35 +Crude Oil, Natural Gas and NGLs Sales +The following tables present crude oil, natural gas and NGLs production and weighted-average sales price for continuing operations: +Year Ended December 31, +Change +Production by Operating Region +2013 +2012 +2011 +2013-2012 +2012-2011 +Crude oil (MBbls) +Wattenberg Field +2,783.1 +1,979.1 +1,670.9 +40.6 +% +18.4 +% +Utica Shale +122.8 +3.0 +— +* +* +Appalachia-Marcellus Shale +3.8 +5.7 +4.8 +(33.3 +)% +18.8 +% +Total +2,909.7 +1,987.8 +1,675.7 +46.4 +% +18.6 +% +Natural gas (MMcf) +Wattenberg Field +12,724.3 +9,844.7 +8,980.2 +29.3 +% +9.6 +% +Utica Shale +561.1 +2.1 +— +* +* +Appalachia-Marcellus Shale +7,574.2 +6,141.8 +4,389.9 +23.3 +% +39.9 +% +Total +20,859.6 +15,988.6 +13,370.1 +30.5 +% +19.6 +% +NGLs (MBbls) +Wattenberg Field +1,034.4 +837.3 +712.1 +23.5 +% +17.6 +% +Utica Shale +8.8 +— +— +* +* +Total +1,043.2 +837.3 +712.1 +24.6 +% +17.6 +% +Crude oil equivalent (MBoe) +Wattenberg Field +5,938.2 +4,457.2 +3,879.7 +33.2 +% +14.9 +% +Utica Shale +225.1 +3.4 +— +* +* +Appalachia-Marcellus Shale +1,266.2 +1,029.3 +736.5 +23.0 +% +39.8 +% +Total +7,429.5 +5,489.9 +4,616.2 +35.3 +% +18.9 +% +Amounts may not recalculate due to rounding. +Year Ended December 31, +Average Sales Price by Operating Region +Change +(excluding net settlements on derivatives) +2013 +2012 +2011 +2013-2012 +2012-2011 +Crude oil (per Bbl) +Wattenberg Field +$ +89.83 +$ +87.27 +$ +87.42 +2.9 +% +(0.2 +)% +Utica Shale +91.90 +76.58 +— +20.0 +% +* +Appalachia-Marcellus Shale +92.89 +92.73 +95.86 +0.2 +% +(3.3 +)% +Weighted-average price +89.92 +87.27 +87.44 +3.0 +% +(0.2 +)% +Natural gas (per Mcf) +Wattenberg Field +3.25 +2.61 +3.55 +24.5 +% +(26.5 +)% +Utica Shale +2.74 +1.66 +— +65.1 +% +* +Appalachia-Marcellus Shale +3.39 +2.66 +4.15 +27.4 +% +(35.9 +)% +Weighted-average price +3.29 +2.63 +3.74 +25.1 +% +(29.7 +)% +NGLs (per Bbl) +Wattenberg Field +27.83 +27.33 +37.62 +1.8 +% +(27.4 +)% +Utica Shale +43.70 +— +— +* +* +Weighted-average price +27.97 +27.33 +37.62 +2.3 +% +(27.4 +)% +Crude oil equivalent (per Bbl) +Wattenberg Field +53.91 +49.64 +52.74 +8.6 +% +(5.9 +)% +Utica Shale +58.68 +69.56 +— +(15.6 +)% +* +Appalachia-Marcellus Shale +20.57 +16.39 +25.37 +25.5 +% +(35.4 +)% +Weighted-average price +48.37 +43.42 +48.37 +11.4 +% +(10.2 +)% +Amounts may not recalculate due to rounding. +36 +The year-over-year change in crude oil, natural gas and NGLs sales revenue were primarily due to the following: +Year Ended December 31, +2013 +2012 +(in millions) +Increase in production +$ +98.8 +$ +41.8 +Increase (decrease) in average crude oil price +7.7 +(0.3 +) +Increase (decrease) in average NGLs price +0.7 +(8.5 +) +Increase (decrease) in average natural gas price +13.8 +(17.9 +) +Total increase in crude oil, natural gas and NGLs sales revenue +$ +121.0 +$ +15.1 +Crude oil, natural gas and NGLs sales in 2013 increased 51% compared to 2012. The increase was primarily attributable to significantly higher volumes sold, in particular liquids, which resulted in a liquids percentage of total production of approximately 53% in 2013. Our average daily sales volumes increased to 20 MBoe per day in 2013 compared to 15 MBoe per day in 2012, primarily due to the success of the horizontal Niobrara and Codell drilling program in the Wattenberg Field. For December 2013, our average production from continuing operations was 27 MBoe per day, compared to 14 MBoe per day in December 2012. Contributing to the increase in crude oil, natural gas and NGLs sales was the 25% and 3% increase in the average price of natural gas and crude oil, respectively, during 2013. +Crude oil, natural gas and NGLs sales in 2012 increased 7% compared to 2011. The increase was primarily attributable to an increase in volumes sold, in particular liquids, which resulted in a liquids percentage of total production of approximately 51% in 2012. The increase was offset in part by the 30% and 27% declines in the average price of natural gas and NGLs, respectively, during 2012. Our average daily sales volumes increased to 15 MBoe per day in 2012 compared to 13 MBoe per day in 2011. +Crude Oil, Natural Gas and NGLs Pricing. Our results of operations depend upon many factors, particularly the price of crude oil, natural gas and NGLs and our ability to market our production effectively. Crude oil, natural gas and NGLs prices are among the most volatile of all commodity prices. These price variations can have a material impact on our financial results and capital expenditures. +Crude oil pricing is predominately driven by the physical market, supply and demand, financial markets and national and international politics. In the Wattenberg Field, crude oil is sold under various purchase contracts with monthly pricing provisions based on NYMEX pricing, adjusted for differentials. In the Utica Shale, crude oil and condensate is sold to local purchasers at each individual well site based on NYMEX pricing, adjusted for differentials. Natural gas prices vary by region and locality, depending upon the distance to markets, availability of pipeline capacity and supply and demand relationships in that region or locality. The price we receive for our natural gas produced in the Wattenberg Field is based on CIG prices, adjusted for differentials, while natural gas produced in the Utica Shale and Appalachia-Marcellus Shale is based on NYMEX pricing, adjusted for differentials. Our price for NGLs produced in the Wattenberg Field is mainly based on prices from the Conway hub in Kansas where this production is marketed. The NGLs produced in the Utica Shale are sold based on month-to-month pricing in various markets. +We currently use the "net-back" method of accounting for these arrangements related to our commodity sales pursuant to which the purchaser also provides the transportation and gathering services. We sell our commodities at the wellhead and collect a price and recognize revenues based on the wellhead sales price as transportation costs downstream of the wellhead are incurred by the purchaser and reflected in the wellhead price. The net-back method results in the recognition of a sales price that is below the indices for which the production is based. The majority of our Wattenberg production, as well as all our crude oil production, is subject to the net-back method of accounting. +Production Costs +Production costs include lease operating expenses, production taxes and certain production and engineering staff-related overhead costs, as well as other costs to operate wells and pipelines as follows: +Year Ended December 31, +2013 +2012 +2011 +(in millions, except per unit data) +Lease operating expenses +$ +37.3 +$ +27.4 +$ +23.0 +Production taxes +24.5 +15.2 +14.9 +Overhead and other production expenses +11.6 +12.1 +6.9 +Total production costs +$ +73.4 +$ +54.7 +$ +44.8 +Total production costs per Boe +$ +9.88 +$ +9.96 +$ +9.71 +37 +Lease operating expenses. Lifting costs per Boe were $5.01 , $5.00 and $4.98 for 2013, 2012 and 2011, respectively. The $9.9 million increase in lease operating expenses in 2013 as compared to 2012 was due to an increase of $3.5 million for workover, compliance and maintenance related projects, an increase of $2.1 million for the rental of additional compressors used to accommodate high line pressures in the Wattenberg Field, an increase of $1.2 million in additional wages and employee benefits, $1.2 million for transportation expense primarily related to Marcellus Shale production and $0.9 million of expenses for wells impacted by the September 2013 Colorado flood. The increase in lease operating expenses in 2012 compared to 2011 was primarily related to the increase in production-related expenses of approximately $7.4 million mostly related to the Merit Acquisition and the Seneca-Upshur acquisition, offset by a decrease in environmental compliance costs of $2.6 million due to the completion of many environmental projects during 2011. +Production taxes. Production taxes are directly related to crude oil, natural gas and NGLs sales. The $9.3 million , or 61% , increase in production taxes for 2013 compared to 2012 is primarily related to the 51% increase in crude oil, natural gas and NGLs sales. +Overhead and other production expenses. The increase of $5.2 million in 2012 over 2011 was mainly the result of two significant one-time charges. We recognized $3.2 million of expense related to the sale of crude oil inventory that had been acquired at fair market value in the Merit Acquisition and an additional $2.0 million in prepaid well costs charged to expense. These 2012 amounts were offset by the 2013 increase of $2.1 million in inventory value and inventory processing expenses, $1.9 million for the unutilized portion of a transportation agreement in the Appalachian Basin and $0.8 million in labor and benefits increases. +Commodity Price Risk Management, Net +Commodity price risk management, net, includes cash settlements upon maturity of our derivative instruments and the change in fair value of unsettled derivatives related to our crude oil and natural gas production. Commodity price risk management, net, does not include derivative transactions related to our natural gas marketing, which are included in sales from and cost of natural gas marketing. See Note 3, Fair Value of Financial Instruments , and Note 4, Derivative Financial Instruments , to our consolidated financial statements included elsewhere in this report for additional details of our derivative financial instruments. +The following table presents net settlements and net change in fair value of unsettled derivatives included in commodity price risk management, net: +Year Ended December 31, +2013 +2012 +2011 +(in millions) +Commodity price risk management gain (loss), net: +Net settlements +$ +12.9 +$ +49.4 +$ +17.2 +Net change in fair value of unsettled derivatives +(36.8 +) +(17.1 +) +28.9 +Total commodity price risk management gain (loss), net +$ +(23.9 +) +$ +32.3 +$ +46.1 +Net settlements in 2013 are primarily the result of lower natural gas index prices at maturity of our derivative instruments compared to the respective strike prices. Positive settlements on natural gas, exclusive of basis swaps, were $25.8 million. This reflects a weighted-average strike price of $4.89 compared to a weighted-average settlement price of $3.66. Positive settlements were offset in part by negative settlements of $9.8 million on our basis swap positions, as the negative basis differential between NYMEX and CIG was a weighted-average of $0.20 compared to a weighted-average strike price of $0.75, and by negative settlements of $3.1 million on our crude oil positions, reflective of a weighted-average strike price of $96.88 compared to a weighted-average settlement price of $98.62. The net change in fair value of unsettled derivatives in 2013 includes a $30.9 million net asset reduction in the beginning-of-period fair value of derivative instruments that settled during the period. The corresponding impact of settlement of these instruments is included in net settlements for the period as discussed above. The net change in fair value of unsettled derivatives in 2013 also includes a $5.9 million decrease in the fair value of unsettled derivatives during the period, primarily related to the upward shift in the crude oil and natural gas forward curves. +Net settlements in 2012 were mainly the result of lower natural gas index prices at maturity of our derivative instruments compared to the respective strike prices, resulting in $66.5 million of positive settlements, offset in part by negative settlements of $16.6 million on our basis swap positions and $0.5 million on our crude oil positions. The net change in fair value of unsettled derivatives in 2012 includes a $28.8 million net asset reduction in the beginning-of-period fair value of derivative instruments that settled during the period. This reduction was offset in part by an $11.7 million increase in the fair value of unsettled derivatives during the period, primarily related to the downward shift in the crude oil and natural gas forward curves. +Net settlements in 2011 were mainly the result of lower natural gas index prices at maturity of our derivative instruments compared to the respective strike prices, resulting in $44 million of positive settlements, offset in part by negative settlements of $14.9 million on our basis swap positions and $11.9 million on our crude oil positions. The net change in fair value of unsettled derivatives in 2011 includes a $10.3 million net asset reduction in the beginning-of-period fair value of derivative instruments that settled during the period. This reduction was offset in part by a $39.2 million increase in the fair value of unsettled derivatives during the period, primarily related to the downward shift in the natural gas forward curve. +38 +We use various derivative instruments to manage fluctuations in natural gas and crude oil prices. We have in place a variety of collars, fixed-price swaps and basis swaps on a portion of our estimated natural gas and crude oil production. Because we sell all of our physical natural gas and crude oil at prices similar to the indexes inherent in our derivative instruments, adjusted for certain fees and surcharges stipulated in the applicable sales agreements, we ultimately realize a price, before contract fees, related to our collars of no less than the floor and no more than the ceiling and, for our commodity swaps, we ultimately realize the fixed price related to our swaps. See Note 4, Derivative Financial Instruments , to our consolidated financial statements included elsewhere in this report and Item 7A, Quantitative and Qualitative Disclosures About Market Risk , for a discussion of how each derivative type impacts our cash flows and a detailed presentation of our derivative positions as of December 31, 2013 . +Natural Gas Marketing +Fluctuations in our natural gas marketing's income contribution are primarily due to fluctuations in commodity prices, cash settlements upon maturity of derivative instruments and the change in fair value of unsettled derivatives, and, to a lesser extent, volumes sold and purchased. +The following table presents the components of sales from and costs of natural gas marketing: +Year Ended December 31, +2013 +2012 +2011 +(in millions) +Natural gas sales revenue +$ +68.9 +$ +44.9 +$ +60.7 +Net settlements from derivatives +0.5 +2.2 +3.0 +Net change in fair value of unsettled derivatives +0.4 +(1.7 +) +(0.2 +) +Total sales from natural gas marketing +69.8 +45.4 +63.5 +Costs of natural gas purchases +68.1 +43.3 +59.0 +Net settlements from derivatives +0.3 +2.0 +2.6 +Net change in fair value of unsettled derivatives +0.4 +(1.6 +) +0.1 +Other +1.3 +1.3 +1.1 +Total costs of natural gas marketing +70.1 +45.0 +62.8 +Natural gas marketing contribution margin +$ +(0.3 +) +$ +0.4 +$ +0.7 +The increase in natural gas sales revenue and costs of natural gas purchases in 2013 compared to 2012 is primarily attributable to a 30% increase in the average natural gas price and a 14% increase in volumes. The decrease in natural gas sales revenue and costs of natural gas purchases in 2012 compared to 2011 is primarily attributable to a 34% decrease in the average natural gas price, offset in part by an 11% increase in volumes. +Derivative instruments related to natural gas marketing include both physical and cash-settled derivatives. We offer fixed-price derivative contracts for the purchase or sale of physical natural gas and enter into cash-settled derivative positions with counterparties in order to offset those same physical positions. See Note 4, Derivative Financial Instruments , to our consolidated financial statements included elsewhere in this report and Item 7A, Quantitative and Qualitative Disclosures About Market Risk , for a discussion of how each derivative type impacts our cash flows and detailed presentation of our derivative positions as of December 31, 2013 . +Exploration Expense +The following table presents the major components of exploration expense: +Year Ended December 31, +2013 +2012 +2011 +(in millions) +Exploratory dry hole costs +$ +— +$ +14.5 +$ +0.1 +Geological and geophysical costs +0.8 +1.9 +1.8 +Operating, personnel and other +6.2 +4.5 +3.8 +Total exploration expense +$ +7.0 +$ +20.9 +$ +5.7 +Exploratory dry hole costs. There were no exploratory dry holes identified in 2013. In 2012, two vertical stratigraphic test wells in southeastern Ohio were expensed at a cost of $12.2 million. The remaining 2012 expense relates to the unsuccessful testing of an exploratory +39 +zone in two existing wells in the Wattenberg Field and three Rose Run test wells in Ohio that were determined to have found noncommercial quantities of hydrocarbons. +Geological and geophysical costs. The $1.1 million decrease in 2013 compared to 2012 is primarily related to costs associated with PDCM's geological and seismic testing of the Marcellus Shale in the Appalachian Basin and PDC's reservoir studies in the Utica Shale in 2012. +Operating, personnel and other . The $1.7 million increase in 2013 compared to 2012 is mainly attributable to payroll and employee benefits in the exploration division as a result of increased employee headcount for the Utica Shale operations. The $0.7 million increase in 2012 compared to 2011 is mainly attributable to a $2 million increase in payroll and employee benefits in the exploration division as a result of increased employee headcount in the Utica Shale, offset in part by a $0.7 million decrease in PDCM's lease prospecting costs. +Impairment of Crude Oil and Natural Gas Properties +The following table sets forth the major components of our impairments of crude oil and natural gas properties expense: +Year Ended December 31, +2013 +2012 +2011 +(in millions) +Impairment of proved properties +$ +48.8 +$ +— +$ +— +Impairment of individually significant unproved properties +1.1 +1.6 +1.1 +Amortization of individually insignificant unproved properties +3.6 +4.3 +1.2 +Total impairment of crude oil and natural gas properties +$ +53.5 +$ +5.9 +$ +2.3 +Impairment of proved properties . In the first quarter of 2013, we recognized an impairment charge of approximately $45 million related to all of our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin producing properties located in West Virginia and Pennsylvania owned directly by us, as well as through our proportionate share of PDCM. The impairment charge represented the excess of the carrying value of the assets over the estimated fair value, less cost to sell. The fair value of the assets was determined based upon estimated future cash flows from unrelated third-party bids, a Level 3 input. Pursuant to a purchase and sale agreement entered into in October 2013, we determined that the carrying value of the above-mentioned properties exceeded the transaction sales price, a Level 3 input, less costs to sell. As a result, we recognized an additional impairment charge of approximately $3.8 million in the third quarter of 2013 to reduce the carrying value of the net assets to reflect the current net sales price. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations , to our consolidated financial statements included elsewhere in this report for additional details related to the sale of these properties. +Impairment of individually significant unproved properties . The $0.5 million decrease in 2013 compared to 2012 is primarily related to two significant leases that were written off in 2012 in the Wattenberg Field for $1.0 million compared to a single lease in non-Utica Ohio acreage written off in 2013 for $0.5 million. +Amortization of individually insignificant unproved properties . The $0.7 million decrease in 2013 compared to 2012 is primarily related to a decrease in leases not held by production, primarily in the Utica Shale. The increase in amortization of individually insignificant unproved properties in 2012 compared to 2011 was mostly attributable to $2.4 million in lease amortization expense related to increased insignificant leases acquired in the Merit Acquisition and $1.6 million in insignificant leases written off in Ohio related to non-Utica leases in 2012. +General and Administrative Expense +General and administrative expense increased $5.2 million , or 8.8% , in 2013 compared to 2012. The increase was primarily due to increased stock-based compensation of $3.5 million due to expanding employee participation in our equity incentive program, a $1.2 million increase in payroll and employee benefits and a $2.3 million increase in other general and administrative expenses. These increases were offset in part by a decrease in professional and consulting fees of $1.8 million. +General and administrative expense for 2012 decreased by $2.6 million , or 4.3% , compared to 2011. The decrease is mainly attributable to a $6.7 million charge recognized in 2011 related to the separation agreement with our former chief executive officer, a $1.6 million charge to legal fees recorded in 2011 related to the settlement agreement reached with regard to our West Virginia royalty lawsuit and a $1.6 million decrease in professional and consulting fees during 2012. These decreases were offset in part by an increase in payroll and employee benefits of $7.5 million in 2012. +Depreciation, Depletion and Amortization +Crude oil and natural gas properties. DD&A expense related to crude oil and natural gas properties is directly related to proved reserves and production volumes. DD&A expense related to crude oil and natural gas properties was $122.2 million in 2013 compared to $94.1 million in 2012. The increase in 2013 compared to 2012 was comprised of $31.6 million due to higher production, offset in part by $3.5 million due to a lower weighted-average DD&A expense rate. +40 +The following table presents our DD&A expense rates for crude oil and natural gas properties: +Year Ended December 31, +Operating Region/Area +2013 +2012 +2011 +(per Boe) +Wattenberg Field +$ +17.68 +$ +18.20 +$ +19.26 +Utica Shale +24.87 +— +— +Appalachia-Marcellus Shale +9.12 +11.41 +12.00 +Total weighted-average +16.44 +16.92 +18.10 +Non-crude oil and natural gas properties. Depreciation expense for non-crude oil and natural gas properties was $5.1 million for 2013 compared to $4.7 million for 2012 and $4.0 million for 2011. +Accretion of Asset Retirement Obligations +Accretion of asset retirement obligations ("ARO") for 2013 increased by $0.9 million , or 24.4% , compared to 2012 . The increase in 2013 is primarily attributable to the properties acquired in the Merit Acquisition in 2012. Accretion of ARO for 2012 increased by $2.3 million , or 163.7% , compared to 2011. The increase in 2012 is primarily attributable to the properties acquired in the Merit Acquisition in 2012 and the Seneca-Upshur acquisition in 2011. +Gain (Loss) on Sale of Properties and Equipment +The loss on sale of properties and equipment of $1.4 million in 2013 primarily relates to the sale of our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin producing properties. The gain on sale of properties and equipment of $4.4 million in 2012 mainly related to our proportionate share of the gain realized from PDCM's sale of certain leases in the Appalachia-Marcellus Shale. The gain on sale of properties and equipment in 2011 was not material. +Interest Expense +Interest expense increased by approximately $3.6 million in 2013 compared to 2012 . The increase is primarily related to $39.6 million of interest expense resulting from the issuance of $500 million of 7.75% senior notes due 2022 in October 2012. Partially offsetting this increase were decreases of $31.1 million related to the November 2012 redemption of previously-outstanding 12% senior notes due 2018 and $4.4 million as a result of lower average borrowings on our revolving credit facility during 2013 as compared to 2012. +Interest expense increased by approximately $11.3 million in 2012 compared to 2011. Approximately $6 million of the increase is related to the issuance of the 7.75% senior notes due 2022 in October 2012 and the result of incurring interest on both the 7.75% senior notes due 2022 and the previously-outstanding 12% senior notes due 2018 during the month of October 2012. Additionally, approximately $3.6 million of the increase was the result of higher average borrowings on our revolving credit facility during 2012 as compared to 2011 and $1.1 million due to higher debt issuance amortization expense. +Interest costs capitalized in 2013, 2012 and 2011 were $1.9 million , $1.2 million and $1.7 million , respectively. +Loss on Extinguishment of Debt +The $23.3 million loss on extinguishment of debt in 2012 related to the redemption of the previously-outstanding 12% senior notes due 2018 in October 2012. The pre-tax loss consisted of an $18.9 million make-whole premium and the write-off of both unamortized debt discount of $1.5 million and unamortized debt issuance costs of $2.9 million . +Provision for Income Taxes +The effective tax rate (the "rate") benefit on loss from continuing operations in 2013 was 35.9% , which reflects a reduction for nondeductible executive compensation, partially offset by a benefit for the percentage depletion deduction. The 2012 benefit on loss from continuing operations of 36.9% reflects a reduced state tax benefit due to our divestitures and their discontinued operations treatment. The 2012 rate also reflects a benefit for the percentage depletion deduction, partially offset by nondeductible executive compensation. The 2011 provision on income from continuing operations rate of 34.3% was also favorably impacted by our deduction for percentage depletion, as well as a $0.6 million tax benefit related to a reduction of the accrual for uncertain tax positions, partially offset by the adjustment to the estimated state deferred rate. Discrete items did not have a significant impact on the effective tax rate in 2013, 2012 or 2011. See Note 7, Income Taxes , to our consolidated financial statements included elsewhere in this report for our rate reconciliation for each of the years in the three-year period ended December 31, 2013 . +Beginning with our 2010 tax year, we were accepted into and have agreed to participate in the IRS Compliance Assurance Process ("CAP") program. See Note 7, Income Taxes , to the accompanying consolidated financial statements included elsewhere in this report for disclosure regarding the reduction of our uncertain tax liability due to our participation in this program. Our 2010 and 2011 CAP reviewed returns +41 +were fully accepted by the IRS shortly after filing. Our 2012 CAP reviewed return was filed in September 2013 with “partial acceptance” issued by the IRS at the filing date. We anticipate “full acceptance” of the 2012 return by the IRS in early 2014, after completion of their post-filing review. We are currently participating in the IRS CAP program review of our 2013 tax year and have accepted an offer for continued participation in the program for our 2014 tax year. +Discontinued Operations +Piceance Basin and NECO . In February 2013, we entered into a purchase and sale agreement with certain affiliates of Caerus pursuant to which we agreed to sell to Caerus our Piceance Basin, NECO and certain other non-core Colorado oil and gas properties, leasehold mineral interests and related assets. Additionally, certain firm transportation obligations and natural gas hedging positions were assumed by Caerus. In June 2013, this divestiture was completed with total consideration of $177.6 million , with an additional $17 million paid to our non-affiliated investor partners in our affiliated partnerships. The sale resulted in a pre-tax loss of $2.3 million . The proceeds from the asset divestiture were used to pay down our revolving credit facility and to fund a portion of our 2013 capital budget. Following the sale to Caerus, we do not have significant continuing involvement in the operations of, or cash flows from, the Piceance Basin and NECO oil and gas properties. Accordingly, the results of operations related to these assets have been reported as discontinued operations for all periods presented in the accompanying consolidated statements of operations included in this report. The sale of our other non-core Colorado oil and gas properties did not meet the requirements to be accounted for as discontinued operations. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for further discussion of the Piceance Basin and NECO divestiture. +Permian Basin. During the fourth quarter of 2011, we completed the sale of certain non-core Permian Basin assets for a total of $13.2 million . Following the sale of our core Permian assets in February 2012, we do not have significant continuing involvement in the operations of or cash flows from these assets. Accordingly, the results of operations related to the core and non-core Permian Basin assets have been reported as discontinued operations in the 2012 and 2011 consolidated statements of operations included elsewhere in this report. Proceeds from the sale of our core Permian Basin assets were $189.2 million after certain post-closing adjustments and were received in the first quarter of 2012. The sale of our Permian Basin assets resulted in a pre-tax gain of $19.9 million . See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for further discussion of the Permian divestiture. +North Dakota. In February 2011, we executed a purchase and sale agreement for the sale of our North Dakota assets and subsequently closed. Proceeds from the sale were $9.5 million , net of non-affiliated investor partners' share of $3.8 million , resulting in a pre-tax gain on sale of $3.9 million . Following the sale to the unrelated party, we do not have significant continuing involvement in the operations of, or cash flows from, these assets. Accordingly, the results of operations related to the North Dakota assets have been reported as discontinued operations in the 2011 consolidated statements of operations included elsewhere in this report. +For operating results related to our discontinued operations, see Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report. +Net Income (Loss)/Adjusted Net Income (Loss) +The year-over-year changes in net income (loss) are discussed above. These same reasons similarly impacted adjusted net income (loss), a non-U.S. GAAP financial measure, with the exception of the net change in fair value of unsettled derivatives, adjusted for taxes. Adjusted net income (loss) excludes the impact of a tax adjusted net change in fair value of unsettled derivatives of $22.8 million , $10.6 million and $17.7 million in 2013 , 2012 and 2011 , respectively. Adjusted net income, a non-U.S. GAAP financial measure, was $0.5 million in 2013 compared to an adjusted net loss of $120.1 million and $4.3 million in 2012 and 2011 , respectively. See Reconciliation of Non-U.S. GAAP Financial Measures , below, for a more detailed discussion of this non-U.S. GAAP financial measure. +Financial Condition, Liquidity and Capital Resources +Historically, our primary sources of liquidity have been cash flows from operating activities, our revolving credit facility, proceeds raised in debt and equity market transactions and asset sales. In 2013 , our primary sources of liquidity were the proceeds received from the public offering of our common stock of $275.8 million , proceeds received from the sale of properties and equipment, including acquisition adjustments, of approximately $187.5 million and net cash flows from operating activities of $159.2 million . +Our primary source of cash flows from operating activities is the sale of crude oil, natural gas and NGLs. Fluctuations in our operating cash flows are substantially driven by commodity prices and changes in our production volumes. Commodity prices have historically been volatile and we manage this volatility through our use of derivatives. We enter into commodity derivative instruments with maturities of no greater than five years from the date of the instrument. For instruments that mature in three years or less, our debt covenants restricts us from entering into hedges that would exceed 85% of our expected future production from total proved reserves (proved developed producing, proved developed non-producing and proved undeveloped). For instruments that mature later than three years, but no more than our designated maximum maturity, our debt covenants limit our holdings to 85% of our expected future production from proved developed producing properties. Therefore, we may still have significant fluctuations in our cash flows from operating activities due to the remaining non-hedged portion of our future production. +Our working capital fluctuates for various reasons, including, but not limited to, changes in the fair value of our commodity derivative instruments and changes in our cash and cash equivalents due to our practice of utilizing excess cash to reduce the outstanding borrowings under our revolving credit facility. At December 31, 2013 , we had a working capital surplus of $112.4 million compared to a deficit of $31.4 million at December 31, 2012 . The working capital surplus as of December 31, 2013 is primarily due to the common stock offering. +42 +We ended 2013 with cash and cash equivalents of $193.2 million and availability under our revolving credit facility and our proportionate share of PDCM's credit facility of $453.8 million , for a total liquidity position of $647 million , compared to $398.6 million at December 31, 2012 . The increase in liquidity of $248.4 million , or 62.3% , was primarily attributable to $275.8 million received from the public offering of our common stock, $187.5 million received from the sale of properties and equipment, including acquisition adjustments, and cash flows provided by operating activities of $159.2 million , offset in part by capital expenditures of $394.9 million during 2013. With our current liquidity position and expected cash flows from operations, we believe that we have sufficient capital to fund our planned drilling operations in 2014. +In recent periods, we have been able to access borrowings under our revolving credit facility and to obtain proceeds from the issuance of debt and equity securities. We cannot, however, be assured this will continue to be the case in the future. We continue to monitor market conditions and circumstances and their potential impact on each of our revolving credit facility lenders. Our $450 million revolving credit facility borrowing base is subject to a redetermination each May and November, based upon a quantification of our proved reserves at each June 30 and December 31, respectively. Our November semi-annual redetermination was completed in October 2013 and resulted in the reaffirmation of our available borrowing base at $450 million . +In January 2012, we filed an automatic shelf registration statement on Form S-3 with the SEC. Effective upon filing, the shelf provides for the potential sale of an unspecified amount of debt securities, common stock or preferred stock, either separately or represented by depository shares, warrants or purchase contracts, as well as units that may include any of these securities or securities of other entities. The shelf registration statement is intended to allow us to be proactive in our ability to raise capital and to have the flexibility to raise such funds in one or more offerings should we perceive market conditions to be favorable. Pursuant to this shelf registration, we sold 6.5 million shares of our common stock in May 2012 in an underwritten public offering at a price to the public of $26.50 per share and approximately 5.2 million shares of our common stock in August 2013 in an underwritten public offering at a price to us of $53.37 per share. +Our revolving credit facility contains financial maintenance covenants. The covenants require that we maintain: (i) total debt of less than 4.25 times earnings before interest, taxes, depreciation, depletion and amortization, change in fair value of unsettled derivatives, exploration expense, gains (losses) on sales of assets and other non-cash, extraordinary or non-recurring gains (losses) ("EBITDAX") and (ii) an adjusted current ratio of at least 1.0 to 1.0. Our adjusted current ratio is adjusted by eliminating the impact on our current assets and liabilities of recording the fair value of crude oil and natural gas derivative instruments. Additionally, available borrowings under our revolving credit facility are added to the current asset calculation and the current portion of our revolving credit facility debt is eliminated from the current liabilities calculation. At December 31, 2013 , we were in compliance with all debt covenants with a 2.2 times debt to EBITDAX ratio and a 4.1 to 1.0 current ratio. We expect to remain in compliance throughout the next year. +The indenture governing our 7.75% senior notes due 2022 contains customary restrictive covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: (a) incur additional debt, (b) make certain investments or pay dividends or distributions on our capital stock or purchase, redeem or retire capital stock, (c) sell assets, including capital stock of our restricted subsidiaries, (d) restrict the payment of dividends or other payments by restricted subsidiaries to us, (e) create liens that secure debt, (f) enter into transactions with affiliates and (g) merge or consolidate with another company. At December 31, 2013 , we were in compliance with all covenants and expect to remain in compliance throughout the next year. +The conversion rights on our 3.25% convertible senior notes due 2016 could be triggered prior to the maturity date. We have initially elected a net-settlement method to satisfy our conversion obligation, which allows us to settle the principal amount of the Convertible Notes in cash and to settle the excess conversion value in shares, as well as cash in lieu of fractional shares. In the event that a holder elects to convert its note, we expect to fund the cash settlement of any such conversion from working capital and/or borrowings under our revolving credit facility. The conversion right is not expected to have a material impact on our financial position. +See Part II, Item 7A, Quantitative and Qualitative Disclosures about Market Risk , for our discussion of credit risk. +Cash Flows +Operating Activities. Our net cash flows from operating activities are primarily impacted by commodity prices, production volumes, net settlements from our derivative positions, operating costs and general and administrative expenses. Cash flows provided by operating activities decreased in 2013 compared to 2012 . The $15.6 million decrease was mainly attributable to changes in assets and liabilities of $59.4 million related to the timing of cash payments and receipts, the decrease in net settlements on derivatives of $36.5 million and increases in production costs, net of inventory adjustments and prepaid well cost write-offs, of $26.2 million, general and administrative expense of $5.2 million and interest expense of $3.6 million . The decrease was offset in part by the increase in crude oil, natural gas and NGLs sales of $121.0 million . Cash flows provided by operating activities increased in 2012 compared to 2011 . The $7.9 million increase was mainly attributable to an increase in net settlements on derivatives of $31.9 million and an increase in crude oil, natural gas and NGLs sales of $15.1 million, offset by a $37.7 million loss of operating margins related to the divested Permian Basin, Piceance and NECO assets. The key components for the changes in our cash flows provided by operating activities are described in more detail in Results of Operations above. +Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased in 2013 and decreased slightly in 2012 when compared to the respective prior years. These changes were primarily due to the same factors mentioned above for changes in cash flows provided by operating activities, without regard to timing of cash payments and receipts of our assets and liabilities. +43 +Adjusted EBITDA, a non-U.S. GAAP financial measure, increased by $44.1 million in 2013 from 2012 , primarily due to a $121.0 million increase in crude oil, natural gas and NGLs sales, offset in part by a $36.5 million decrease in net settlements on derivatives, a $18.7 million increase in production costs and a $19.9 million pre-tax gain on sale of properties and equipment recognized in 2012 related to the sale of our Permian Basin assets. Adjusted EBITDA increased by $6.7 million in 2012 from 2011, primarily due to a $31.9 million increase in net settlements on derivatives, a $19.9 million pre-tax gain on sale of properties and equipment related to the sale of our Permian Basin assets and a $15.1 million increase in crude oil, natural gas and NGLs sales, offset in part by a $41.8 million decrease in contribution margins related to divested crude oil and natural gas assets and a $15.2 million increase in exploration expense. +See Reconciliation of Non-U.S. GAAP Financial Measures , below, for a more detailed discussion of non-U.S. GAAP financial measures. +Investing Activities. Because crude oil and natural gas production from a well declines rapidly in the first few years of production, we need to continue to commit significant amounts of capital in order to maintain and grow our production and replace our reserves. If capital is not available or is constrained in the future, we will be limited to our cash flows from operations and liquidity under our revolving credit facility as the sources for funding our capital expenditures. We would not be able to maintain our current level of crude oil, natural gas and NGLs production and cash flows from operating activities if capital markets were unavailable, commodity prices were to become depressed and/or the borrowing base under our revolving credit facility was significantly reduced. The occurrence of such an event may result in our election to defer a substantial portion of our planned capital expenditures and could have a material negative impact on our operations in the future. +Cash flows from investing activities primarily consist of the acquisition, exploration and development of crude oil and natural gas properties, net of dispositions of crude oil and natural gas properties. In 2013 , our drilling program consisted of three drilling rigs operating in the oil- and liquid-rich horizontal Niobrara and Codell plays in our Wattenberg Field for a majority of the year and one drilling rig in the Utica Shale and Appalachia-Marcellus Shale, respectively. See Part I, Properties - Drilling Activities , for additional details on our drilling activities. Net cash used in investing activities of $217.1 million during 2013 was primarily related to cash utilized for our drilling operations of $394.9 million , offset in part by the $187.5 million received from the sale of properties and equipment, including acquisition adjustments. We also invested approximately $9.7 million to purchase substantially all of the Colorado crude oil and natural gas wells owned by certain affiliated partnerships; the assets were purchased through a court-approved auction after such partnerships filed for bankruptcy in September 2013. In 2012, net cash used in investing activities was primarily related to the $304.6 million expended in June 2012 for the Merit Acquisition and drilling activity of $347.7 million, offset in part by $189.2 million received from the divestiture of our Permian assets in February 2012 and $28.9 million received related to title defects discovered from PDCM's Seneca-Upshur acquisition in October 2011, of which $14.5 million represented our share. In 2011, net cash used in investing activities primarily related to cash utilized for our drilling operations of $334.5 million and our acquisition of crude oil and natural gas properties for $145.9 million , offset in part by the $23.1 million received from the sale of our North Dakota assets and our non-core Permian Basin assets. +Financing Activities. Net cash from financing activities in 2013 was primarily related to the $275.8 million received from the issuance of our common stock in August 2013, partially offset by net payments of approximately $23.3 million to pay down amounts borrowed under revolving credit facilities. Net cash from financing activities in 2012 includes gross proceeds of $500 million from our October 2012 issuance of the 7.75% senior notes due 2022 and $164.5 million from our May 2012 sale of common stock. The net proceeds from the issuance of the 7.75% senior notes due 2022 were used to fund the redemption of our previously-outstanding 12% senior notes due 2018 for a total redemption price of approximately $222 million and to repay a portion of amounts outstanding under our revolving credit facility. The proceeds from the sale of common stock in May 2012 were used to finance a portion of the Merit Acquisition. Cash flows provided by financing activities in 2011 were primarily comprised of net borrowings under our revolving credit facility of $233.5 million to execute our capital budget. Additionally, 2011 financing cash flows includes $12.5 million, representing our proportionate share of capital contributed to PDCM by our investing partner. +44 +Contractual Obligations and Contingent Commitments +The table below presents our contractual obligations and contingent commitments as of December 31, 2013 . +Payments due by period +Less than +1-3 +3-5 +More than +Contractual Obligations and Contingent Commitments +Total +1 year +years +years +5 years +(in millions) +Long-term liabilities reflected on the consolidated balance sheet (1) +Long-term debt (2) +$ +667.0 +$ +— +$ +115.0 +$ +52.0 +$ +500.0 +Derivative contracts (3) +18.5 +15.6 +2.9 +— +— +Production tax liability +45.5 +23.4 +22.1 +— +— +Asset retirement obligations +41.1 +1.2 +2.4 +2.3 +35.2 +Other liabilities (4) +3.4 +0.3 +1.3 +0.5 +1.3 +775.5 +40.5 +143.7 +54.8 +536.5 +Commitments, contingencies and other arrangements (5) +Interest on long-term debt (6) +365.9 +46.7 +91.0 +81.3 +146.9 +Operating leases +6.1 +2.4 +2.4 +0.3 +1.0 +Firm transportation and processing agreements (7) +70.0 +7.5 +16.1 +14.8 +31.6 +442.0 +56.6 +109.5 +96.4 +179.5 +Total +$ +1,217.5 +$ +97.1 +$ +253.2 +$ +151.2 +$ +716.0 +__________ +(1) +Table does not include deferred income tax liability to taxing authorities of $118.8 million , due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations. +(2) +Amount presented does not agree with the consolidated balance sheet in that it excludes $10.0 million in unamortized debt discount. See Note 8, Long-Term Debt, to our consolidated financial statements included elsewhere in this report. +(3) +Represents our gross liability related to the fair value of derivative positions. +(4) +Includes funds held from revenue distribution to third-party investors, including our affiliated partnerships, for plugging liabilities related to wells we operate and deferred compensation to former executive officers. +(5) +Table does not include an undrawn $11.7 million irrevocable standby letter of credit pending issuance to a transportation service provider. See Note 8, Long-Term Debt, to our consolidated financial statements included elsewhere in this report. Additionally, the table does not include the annual repurchase obligations to investing partners or termination benefits related to employment agreements with our executive officers, due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations. See Note 11, Commitments and Contingencies - Partnership Repurchase Provision; Employment Agreements with Executive Officers, to our consolidated financial statements included elsewhere in this report. +(6) +Amounts presented include $340.7 million to the holders of our 7.75% senior notes due 2022, $8.9 million payable to the holders of our 3.25% convertible senior notes due 2016 and $4.9 million to holders of PDCM's second lien term loan. Amounts also include $11.4 million payable to the participating banks of our revolving credit facilities, of which interest of $7.3 million is related to unutilized commitments at a rate of .38% per annum, $4.0 million related to the outstanding borrowings on our revolving credit facilities of $37.0 million and $0.1 million related to our undrawn letters of credit. +(7) +Represents our gross commitment, including our proportionate share of PDCM. We will recognize in our financial statements our proportionate share based on our interest; however, with the exception of contracts entered into by PDCM, the costs of all volume shortfalls will be borne by PDC only. See Note 11, Commitments and Contingencies - Firm Transportation, Processing and Sales Agreements, to our consolidated financial statements included elsewhere in this report. +As the managing general partner of affiliated partnerships, we have liability for potential casualty losses in excess of the partnership assets and insurance. We believe that the casualty insurance coverage we and our subcontractors carry is adequate to meet this potential liability. +For information regarding our legal proceedings, see Note 11, Commitments and Contingencies – Litigation , to our consolidated financial statements included elsewhere in this report. From time to time, we are a party to various other legal proceedings in the ordinary course of business. We are not currently a party to any litigation that we believe would have a materially adverse effect on our business, financial condition, results of operations or liquidity. +45 +Critical Accounting Policies and Estimates +We have identified the following policies as critical to business operations and the understanding of our results of operations. This is not a comprehensive list of all of the accounting policies. In many cases, the accounting treatment of a particular transaction is specifically dictated by U.S. GAAP, with no need for our judgment in the application. There are also areas in which our judgment in selecting available alternatives would not produce a materially different result. However, certain of our accounting policies are particularly important to the portrayal of our financial position and results of operations and we may use significant judgment in the application. As a result, they are subject to an inherent degree of uncertainty. In applying those policies, we use our judgment to determine the appropriate assumptions to be used in the determination of certain estimates. Those estimates are based on historical experience, observation of trends in the industry and information available from other outside sources, as appropriate. For a more detailed discussion on the application of these and other accounting policies, see Note 2, Summary of Significant Accounting Policies , to our consolidated financial statements included elsewhere in this report. Our critical accounting policies and estimates are as follows: +Crude Oil and Natural Gas Properties. We account for our crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves. +Annually, we engage independent petroleum engineers to prepare reserve and economic evaluations of all our properties on a well-by-well basis as of December 31. We adjust our crude oil and natural gas reserves for major acquisitions, new drilling and divestitures during the year as needed. The process of estimating and evaluating crude oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur. Although every reasonable effort is made to ensure that reserve estimates reported represent our most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates over time. Because estimates of reserves significantly affect our DD&A expense, a change in our estimated reserves could have an effect on our net income. +Exploration costs, including geological and geophysical expenses, and delay rentals, are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but are charged to expense if the well is determined to be nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as the well has found a sufficient quantity of reserves to justify completion as a producing well and we are making sufficient progress assessing our reserves and economic and operating viability. If an in-progress exploratory well is found to be unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the well is classified as "suspended well costs" until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time when we are able to make a final determination of a well’s productive status, the well is removed from the suspended well status and the proper accounting treatment is applied. +The acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense when expired, impaired or amortized. Unproved crude oil and natural gas properties with individually significant acquisition costs are periodically assessed, and any impairment in value is charged to impairment of crude oil and natural gas properties. The amount of impairment recognized on unproved properties which are not individually significant is determined by amortizing the costs of such properties within appropriate fields based on our historical experience, acquisition dates and average lease terms, with the amortization recognized in impairment of crude oil and natural gas properties. The valuation of unproved properties is subjective and requires us to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual realizable values. +We assess our crude oil and natural gas properties for possible impairment upon a triggering event by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which we reasonably estimate the commodity to be sold. Any impairment in value is charged to impairment of crude oil and natural gas properties. The estimates of future prices may differ from current market prices of crude oil and natural gas. Any downward revisions in estimates to our reserve quantities, expectations of falling commodity prices or rising operating costs could result in a triggering event, and therefore, a reduction in undiscounted future net cash flows and an impairment of our crude oil and natural gas properties. Although our cash flow estimates are based on the relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results. +Crude Oil, Natural Gas and NGLs Sales Revenue Recognition . Crude oil, natural gas and NGLs sales are recognized when production is sold to a purchaser at a determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes and prices received. We receive payment for sales from one to two months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded two to three months later. Historically, differences have been immaterial. +46 +Fair Value of Financial Instruments. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as: +Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets. +Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means. +Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity. +Derivative Financial Instruments. We measure the fair value of our derivative instruments based on a pricing model that utilizes market-based inputs, including but not limited to the contractual price of the underlying position, current market prices, natural gas and crude oil forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of derivative liabilities and the effect of our counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position. +We validate our fair value measurement through the review of counterparty statements and other supporting documentation, the determination that the source of the inputs is valid, the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and assumptions. While we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. While we believe our valuation method is appropriate and consistent with those used by other market participants, the use of a different methodology or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value. +Net settlements on our derivative instruments are initially recorded to accounts receivable or payable, as applicable, and may not be received from or paid to counterparties to our derivative contracts within the same accounting period. Such settlements typically occur the month following the maturity of the derivative instrument. We have evaluated the credit risk of the counterparties holding our derivative assets, which are primarily financial institutions who are also major lenders in our revolving credit facility, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our counterparties on the fair value of our derivative instruments is not significant. +Deferred Income Tax Asset Valuation Allowance. Deferred income tax assets are recognized for deductible temporary differences, net operating loss carry-forwards and credit carry-forwards if it is more likely than not that the tax benefits will be realized. To the extent a deferred tax asset is not expected to be realized under the preceding criteria, we establish a valuation allowance. The factors which we consider in assessing whether we will realize the value of deferred income tax assets involve judgments and estimates of both amount and timing, which could differ from actual results, achieved in future periods. +The judgments used in applying the above policies are based on our evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results may differ from those estimates. +Accounting for Acquisitions Using Purchase Accounting. We utilize the purchase method to account for acquisitions. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. The purchase price allocations are based on appraisals, discounted cash flows, quoted market prices and estimates by management. When appropriate, we review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties. +In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped, unproved crude oil and natural gas properties and other non-crude oil and natural gas properties. To estimate the fair values of these properties, we prepare estimates of crude oil and natural gas reserves. We estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired, and estimates of future operating and development costs, to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is subject to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors. +47 +We record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. +Recent Accounting Standards +See Note 2, Summary of Significant Accounting Policies - Recent Accounting Standards , to our consolidated financial statements included elsewhere in this report. +Reconciliation of Non-U.S. GAAP Financial Measures +Adjusted cash flows from operations. We define adjusted cash flows from operations as the cash flows earned or incurred from operating activities, without regard to changes in operating assets and liabilities. We believe it is important to consider adjusted cash flows from operations, as well as cash flows from operations, as we believe it often provides more transparency into what drives the changes in our operating trends, such as production, prices, operating costs and related operational factors, without regard to whether the related asset or liability was received or paid during the same period. We also use this measure because the timing of cash received from our assets, cash paid to obtain an asset or payment of our obligations has been only a timing issue from one period to the next as we have not had accounts receivable collection problems, nor been unable to purchase assets or pay our obligations. See the Consolidated Statements of Cash Flows in this report. +Adjusted net income (loss). We define adjusted net income (loss) as net income (loss), plus loss on commodity derivatives, less gain on commodity derivatives and net settlements on commodity derivatives, each adjusted for tax effect. We believe it is important to consider adjusted net income (loss), as well as net income (loss). We believe this measure often provides more transparency into our operating trends, such as production, prices, operating costs, net settlements from derivatives and related factors, without regard to changes in our net income (loss) from our mark-to-market adjustments resulting from net changes in the fair value of unsettled derivatives. +Adjusted EBITDA. We define adjusted EBITDA as net income (loss), plus loss on commodity derivatives, interest expense, net of interest income, income taxes, impairment of crude oil and natural gas properties, depreciation, depletion and amortization, accretion of asset retirement obligations and loss on debt extinguishment, less gain on commodity derivatives and net settlements on commodity derivatives. Adjusted EBITDA is not a measure of financial performance or liquidity under U.S. GAAP and should be considered in addition to, not as a substitute for, net income (loss), nor as an indicator of cash flows reported in accordance with U.S. GAAP. Adjusted EBITDA includes certain non-cash costs incurred by the Company and does not take into account changes in operating assets and liabilities. Other companies in our industry may calculate adjusted EBITDA differently than we do, limiting its usefulness as a comparative measure. We believe adjusted EBITDA is relevant because it is a measure of our operational and financial performance, as well as a measure of our liquidity, and is used by our management, investors, commercial banks, research analysts and others to analyze such things as: +• +operating performance and return on capital as compared to our peers; +• +financial performance of our assets and our valuation without regard to financing methods, capital structure or historical cost basis; +• +ability to generate sufficient cash to service our debt obligations; and +• +viability of acquisition opportunities and capital expenditure projects, including the related rate of return. +PV-10 . We define PV-10 as the estimated present value of the future net cash flows from our proved reserves before income taxes, discounted using a 10% discount rate. We believe that PV-10 provides useful information to investors as it is widely used by professional analysts and sophisticated investors when evaluating oil and gas companies. We believe that PV-10 is relevant and useful for evaluating the relative monetary significance of our reserves. Professional analysts and sophisticated investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies' reserves. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable in evaluating us and our reserves. PV-10 is not intended to represent the current market value of our estimated reserves. +48 +The following table presents a reconciliation of our non-U.S. GAAP financial measures to its most comparable U.S. GAAP measure: +Year Ended December 31, +2013 +2012 +2011 +(in millions) +Adjusted cash flows from operations: +Adjusted cash flows from operations +$ +207.8 +$ +163.9 +$ +167.7 +Changes in assets and liabilities +(48.6 +) +10.8 +(0.9 +) +Net cash from operating activities +$ +159.2 +$ +174.7 +$ +166.8 +Adjusted net income (loss): +Adjusted net income (loss) +$ +0.5 +$ +(120.1 +) +$ +(4.3 +) +Gain (loss) on commodity derivative instruments +(23.7 +) +32.4 +46.2 +Net settlements on commodity derivative instruments +(13.1 +) +(49.5 +) +(17.6 +) +Tax effect of above adjustments +14.0 +6.5 +(10.9 +) +Net income (loss) +$ +(22.3 +) +$ +(130.7 +) +$ +13.4 +Adjusted EBITDA to net income (loss): +Adjusted EBITDA +$ +241.0 +$ +196.9 +$ +190.2 +Gain (loss) on commodity derivative instruments +(23.7 +) +32.4 +46.2 +Net settlements on commodity derivative instruments +(13.1 +) +(49.5 +) +(17.6 +) +Interest expense, net +(51.4 +) +(48.3 +) +(36.9 +) +Income tax provision +12.6 +80.2 +(6.2 +) +Impairment of crude oil and natural gas properties +(53.4 +) +(168.2 +) +(25.2 +) +Depreciation, depletion and amortization +(129.5 +) +(146.9 +) +(135.2 +) +Accretion of asset retirement obligations +(4.8 +) +(4.0 +) +(1.9 +) +Loss on extinguishment of debt +— +(23.3 +) +— +Net income (loss) +$ +(22.3 +) +$ +(130.7 +) +$ +13.4 +Adjusted EBITDA to net cash from operating activities: +Adjusted EBITDA +$ +241.0 +$ +196.9 +$ +190.2 +Interest expense, net +(51.4 +) +(48.3 +) +(36.9 +) +Exploratory dry hole costs +— +15.3 +0.2 +Stock-based compensation +12.9 +8.5 +7.4 +Amortization of debt discount and issuance costs +6.8 +7.9 +6.3 +(Gain) loss on sale of properties and equipment +3.7 +(24.3 +) +(4.3 +) +Other +(5.2 +) +7.9 +4.8 +Changes in assets and liabilities +(48.6 +) +10.8 +(0.9 +) +Net cash from operating activities +$ +159.2 +$ +174.7 +$ +166.8 +PV-10: +PV-10 +$ +2,703.9 +$ +1,708.9 +$ +1,350.3 +Present value of estimated future income tax discounted at 10% +(913.4 +) +(540.4 +) +(409.1 +) +Standardized measure of discounted future net cash flows +$ +1,790.5 +$ +1,168.5 +$ +941.2 +Amounts above include results from continuing and discontinued operations. +49 +ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK +Market-Sensitive Instruments and Risk Management +We are exposed to market risks associated with interest rate risks, commodity price risk and credit risk. We have established risk management processes to monitor and manage these market risks. +Interest Rate Risk +Changes in interest rates affect the amount of interest we earn on our interest bearing cash, cash equivalents and restricted cash accounts and the interest we pay on borrowings under our revolving credit facility. Our 7.75% senior notes due 2022 and 3.25% convertible senior notes due 2016 have fixed rates and, therefore, near-term changes in interest rates do not expose us to risk of earnings or cash flow loss; however, near-term changes in interest rates may affect the fair value of our fixed-rate debt. +As of December 31, 2013 , our interest-bearing deposit accounts included money market accounts, certificates of deposit and checking and savings accounts with various banks. The amount of our interest-bearing cash, cash equivalents and restricted cash as of December 31, 2013 was $210.7 million with a weighted-average interest rate of 0.3%. Based on a sensitivity analysis of our interest bearing deposits as of December 31, 2013 , we estimate that if market interest rates would have increased 1% in 2013 , our interest income would have increased by approximately $2.1 million. +As of December 31, 2013 , excluding the $11.7 million irrevocable standby letter of credit, we had no outstanding draws on our revolving credit facility and, representing our proportionate share, $37.0 million on PDCM's bank credit facility. We estimate that if market interest rates would have increased or decreased by 1%, our 2013 interest expense would have changed by approximately $0.4 million. +Commodity Price Risk +We are exposed to the potential risk of loss from adverse changes in the market price of crude oil, natural gas and NGLs. Pursuant to established policies and procedures, we manage a portion of the risks associated with these market fluctuations using derivative instruments. These instruments help us predict with greater certainty the effective crude oil and natural gas prices we will receive for our hedged production. We believe that our established derivative policies and procedures are effective in achieving our risk management objectives. +The following table presents our derivative positions related to crude oil and natural gas sales in effect as of December 31, 2013 : +Collars +Fixed-Price Swaps +Basis Protection Swaps +Commodity/ Index/ +Maturity Period +Quantity +(Gas - +BBtu (1) +Oil - MBbls) +Weighted-Average +Contract Price +Quantity +(Gas - +BBtu (1) +Oil - MBbls) +Weighted- +Average +Contract +Price +Quantity +(BBtu) (1) +Weighted- +Average +Contract +Price +Fair Value +December 31, +2013 (2) +(in millions) +Floors +Ceilings +Natural Gas +NYMEX +2014 +— +$ +— +$ +— +15,327.5 +$ +4.12 +6,004.0 +$ +(0.21 +) +$ +(0.9 +) +2015 +5,860.0 +4.00 +4.48 +12,230.0 +4.10 +1,620.0 +(0.27 +) +(0.2 +) +2016 +4,820.0 +4.03 +4.48 +11,920.0 +3.99 +— +— +(1.3 +) +2017 +1,630.0 +4.25 +5.00 +625.0 +4.22 +— +— +0.6 +CIG +2014 +— +— +— +4,828.0 +4.00 +— +— +0.4 +2015 +— +— +— +2,730.0 +4.01 +— +— +0.6 +Total Natural Gas +12,310.0 +47,660.5 +7,624.0 +$ +(0.8 +) +Crude Oil +NYMEX +2014 +1,032.0 +$ +82.83 +$ +102.55 +3,080.0 +$ +91.14 +— +$ +— +$ +(12.6 +) +2015 +336.0 +81.07 +97.76 +4,165.0 +88.67 +— +— +2.9 +Total Crude Oil +1,368.0 +7,245.0 +— +(9.7 +) +Total Natural Gas and Crude Oil +$ +(10.5 +) +_____________ +(1) +A standard unit of measurement for natural gas (one BBtu equals one MMcf). +(2) +Approximately 31.3% of the fair value of our derivative assets and 5.5% of our derivative liabilities were measured using significant unobservable inputs (Level 3). See Note 3, Fair Value Measurements, to the consolidated financial statements included elsewhere in this report. +50 +The following table presents annual average NYMEX and CIG closing prices for crude oil and natural gas for the years ended December 31, 2013 and 2012 , as well as average sales prices we realized for our crude oil, natural gas and NGLs production: +Year Ended December 31, +2013 +2012 +Average Index Closing Price: +Crude oil (per Bbl) +NYMEX +$ +96.76 +$ +94.92 +Natural gas (per MMBtu) +CIG +$ +3.45 +$ +2.58 +NYMEX +3.65 +2.79 +Average Sales Price Realized: +Excluding net settlements on derivatives +Crude oil (per Bbl) +$ +89.92 +$ +87.27 +Natural gas (per Mcf) +3.29 +2.63 +NGLs (per Bbl) +27.97 +27.33 +Based on a sensitivity analysis as of December 31, 2013 , it was estimated that a 10% increase in crude oil and natural gas prices, inclusive of basis, over the entire period for which we have derivatives in place, would have resulted in a decrease in fair value of the derivatives of $95.5 million; whereas a 10% decrease in prices would have resulted in an increase in fair value of $93.7 million. +See Note 3, Fair Value of Financial Instruments , and Note 4, Derivative Financial Instruments , to our consolidated financial statements included elsewhere in this report for a summary of our open derivative positions, as well as a discussion of how we determine the fair value of and account for our derivative contracts. +Credit Risk +Credit risk represents the loss that we would incur if a counterparty fails to perform under its contractual obligations. We attempt to reduce credit risk by diversifying our counterparty exposure and entering into transactions with high-quality counterparties. When exposed to significant credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis. While we believe that our credit risk analysis and monitoring procedures are reasonable, no amount of analysis can assure performance by our counterparties. +Our Oil and Gas Exploration and Production segment's crude oil, natural gas and NGLs sales are concentrated with a few predominately large customers. This concentrates the significance of our credit risk exposure to a small number of large customers. Amounts due to our Gas Marketing segment are from a diverse group of entities, including major upstream and midstream energy companies, financial institutions and end-users in various industries. We monitor their creditworthiness through our credit committee, which utilizes a number of qualitative and quantitative tools to assess credit risk and takes mitigative actions if deemed necessary. To date, we have had no material counterparty default losses in either our Oil and Gas Exploration and Production or our Gas Marketing segment. See Note 5, Concentration of Risk , to our consolidated financial statements included elsewhere in this report. +Our derivative financial instruments may expose us to the credit risk of nonperformance by the instrument's contract counterparty. We primarily use financial institutions which are lenders in our revolving credit facility as counterparties for our derivative financial instruments. Disruption in the credit markets may have a significant adverse impact on a number of financial institutions. We monitor the creditworthiness of our counterparties through our credit committee, which utilizes a number of qualitative and quantitative tools to assess credit risk and takes mitigative actions if deemed necessary. While we believe that our monitoring procedures are reasonable, no amount of analysis can assure performance by a financial institution. To date, we have had no material counterparty default losses from our derivative financial instruments. See Note 4, Derivative Financial Instruments , to our consolidated financial statements included elsewhere in this report for more detail on our derivative financial instruments. +Disclosure of Limitations +Because the information above included only those exposures that existed at December 31, 2013 , it does not consider those exposures or positions which could arise after that date. As a result, our ultimate realized gain or loss with respect to interest rate and commodity price fluctuations will depend on the exposures that arise during the period, our commodity price risk management strategies at the time, and interest rates and commodity prices at the time. +51 +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +Index to Consolidated Financial Statements, Financial Statement Schedule and Supplemental Information +Management's Report on Internal Control Over Financial Reporting +53 +Financial Statements: +Report of Independent Registered Public Accounting Firm +54 +Consolidated Balance Sheets - December 31, 2013 and 201 2 +55 +Consolidated Statements of Operations - Years Ended December 31, 2013, 2012 and 2011 +56 +Consolidated Statements of Cash Flows - Years Ended December 31, 2013, 2012 and 2011 +57 +Consolidated Statements of Equity - Years Ended December 31, 2013, 2012, and 2011 +58 +Notes to Consolidated Financial Statements +59 +Supplemental Information - Unaudited: +Crude Oil and Natural Gas Information +87 +Quarterly Financial Information +94 +Financial Statement Schedule: +Schedule II - Valuation and Qualifying Accounts +96 +52 +Management's Report on Internal Control Over Financial Reporting +Management is responsible for establishing and maintaining adequate internal control over financial reporting as such term as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. 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. 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 policies or procedures may deteriorate. +Management has assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2013 , based upon the criteria established in "Internal Control – Integrated Framework (1992)" issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2013 . +The effectiveness of the Company's internal control over financial reporting as of December 31, 2013 , has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein. +PDC ENERGY, INC. +/s/ James M. Trimble +James M. Trimble +Chief Executive Officer and President +/s/ Gysle R. Shellum +Gysle R. Shellum +Chief Financial Officer +/s/ R. Scott Meyers +R. Scott Meyers +Chief Accounting Officer +53 +Report of Independent Registered Public Accounting Firm +To the Board of Directors and Shareholders of PDC Energy, Inc.: +In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of PDC Energy, Inc. and its subsidiaries at December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013 , based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements, 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 opinions on these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated 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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. +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 (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 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. +/s/ PricewaterhouseCoopers LLP +Pittsburgh, Pennsylvania +February 20, 2014 +54 +PDC ENERGY, INC. +Consolidated Balance Sheets +(in thousands, except share and per share data) +As of December 31, +2013 +2012 +Assets +Current assets: +Cash and cash equivalents +$ +193,243 +$ +2,457 +Restricted cash +2,214 +3,942 +Accounts receivable, net +94,085 +64,880 +Accounts receivable affiliates +6,614 +4,842 +Fair value of derivatives +2,572 +52,042 +Deferred income taxes +22,374 +36,151 +Prepaid expenses and other current assets +4,711 +7,635 +Total current assets +325,813 +171,949 +Properties and equipment, net +1,653,445 +1,616,706 +Assets held for sale +2,785 +— +Fair value of derivatives +5,601 +6,883 +Other assets +37,559 +31,310 +Total Assets +$ +2,025,203 +$ +1,826,848 +Liabilities and Shareholders' Equity +Liabilities +Current liabilities: +Accounts payable +$ +109,555 +$ +82,716 +Accounts payable affiliates +41 +5,296 +Production tax liability +23,421 +25,899 +Fair value of derivatives +15,515 +18,439 +Funds held for distribution +32,578 +34,228 +Accrued interest payable +9,251 +11,056 +Other accrued expenses +23,059 +25,715 +Total current liabilities +213,420 +203,349 +Long-term debt +656,990 +676,579 +Deferred income taxes +118,767 +148,427 +Asset retirement obligation +37,811 +61,563 +Fair value of derivatives +3,015 +10,137 +Liabilities held for sale +2,061 +— +Other liabilities +25,545 +23,612 +Total liabilities +1,057,609 +1,123,667 +Commitments and contingent liabilities +Shareholders' equity +Preferred shares - par value $0.01 per share, 50,000,000 shares authorized, none issued +— +— +Common shares - par value $0.01 per share, 100,000,000 authorized, 35,675,656 and 30,294,224 issued as of December 31, 2013 and 2012, respectively +357 +303 +Additional paid-in capital +674,211 +387,494 +Retained earnings +293,267 +315,568 +Treasury shares - at cost, 5,508 and 5,059 as of December 31, 2013 and 2012, respectively +(241 +) +(184 +) +Total shareholders' equity +967,594 +703,181 +Total Liabilities and Shareholders' Equity +$ +2,025,203 +$ +1,826,848 +See accompanying Notes to Consolidated Financial Statements +55 +PDC ENERGY, INC. +Consolidated Statements of Operations +(in thousands, except per share data) +Year Ended December 31, +2013 +2012 +2011 +Revenues +Crude oil, natural gas and NGLs sales +$ +359,398 +$ +238,361 +$ +223,297 +Sales from natural gas marketing +69,787 +45,371 +63,470 +Commodity price risk management gain (loss), net +(23,905 +) +32,339 +46,090 +Well operations, pipeline income and other +6,034 +4,534 +4,432 +Total revenues +411,314 +320,605 +337,289 +Costs, expenses and other +Production costs +73,390 +54,700 +44,832 +Cost of natural gas marketing +70,084 +45,023 +62,831 +Exploration expense +7,039 +20,894 +5,734 +Impairment of crude oil and natural gas properties +53,435 +5,895 +2,301 +General and administrative expense +63,969 +58,815 +61,454 +Depreciation, depletion, and amortization +127,260 +98,778 +87,633 +Accretion of asset retirement obligations +4,586 +3,687 +1,398 +(Gain) loss on sale of properties and equipment +1,392 +(4,353 +) +(196 +) +Total cost, expenses and other +401,155 +283,439 +265,987 +Income from operations +10,159 +37,166 +71,302 +Loss on extinguishment of debt +— +(23,283 +) +— +Interest expense +(51,898 +) +(48,287 +) +(36,985 +) +Interest income +470 +8 +47 +Income (loss) from continuing operations before income taxes +(41,269 +) +(34,396 +) +34,364 +Provision for income taxes +14,797 +12,701 +(11,800 +) +Income (loss) from continuing operations +(26,472 +) +(21,695 +) +22,564 +Income (loss) from discontinued operations, net of tax +4,171 +(109,017 +) +(9,127 +) +Net income (loss) +$ +(22,301 +) +$ +(130,712 +) +$ +13,437 +Earnings per share: +Basic +Income (loss) from continuing operations +$ +(0.82 +) +$ +(0.78 +) +$ +0.96 +Income (loss) from discontinued operations +0.13 +(3.94 +) +(0.39 +) +Net income (loss) +$ +(0.69 +) +$ +(4.72 +) +$ +0.57 +Diluted +Income (loss) from continuing operations +$ +(0.82 +) +$ +(0.78 +) +$ +0.95 +Income (loss) from discontinued operations +0.13 +(3.94 +) +(0.39 +) +Net income (loss) +$ +(0.69 +) +$ +(4.72 +) +$ +0.56 +Weighted-average common shares outstanding: +Basic +32,426 +27,677 +23,521 +Diluted +32,426 +27,677 +23,871 +See accompanying Notes to Consolidated Financial Statements +56 +PDC ENERGY, INC. +Consolidated Statements of Cash Flows +(in thousands) +Year Ended December 31, +2013 +2012 +2011 +Cash flows from operating activities: +Net income (loss) +$ +(22,301 +) +$ +(130,712 +) +$ +13,437 +Adjustments to net income (loss) to reconcile to net cash from operating activities: +Net change in fair value of unsettled derivatives +36,801 +17,134 +(28,601 +) +Depreciation, depletion and amortization +129,518 +146,879 +135,154 +Impairment of crude oil and natural gas properties +53,438 +168,149 +25,159 +Prepaid well costs write-offs +74 +3,916 +1,359 +Loss on extinguishment of debt +— +23,283 +— +Exploratory dry hole costs +— +15,347 +177 +Accretion of asset retirement obligation +4,747 +4,060 +1,897 +Stock-based compensation +12,880 +8,495 +8,781 +Excess tax benefits from stock-based compensation +(2,489 +) +— +(1,311 +) +(Gain) loss from sale of properties and equipment +3,722 +(24,273 +) +(4,263 +) +Amortization of debt discount and issuance costs +6,783 +7,864 +6,265 +Deferred income taxes +(15,883 +) +(80,379 +) +9,530 +Other +460 +4,123 +135 +Total adjustments to net income (loss) to reconcile to net cash from operating activities: +230,051 +294,598 +154,282 +Changes in assets and liabilities: +Accounts receivable +(41,509 +) +6,843 +(3,451 +) +Other assets +3,461 +(2,908 +) +(3,893 +) +Restricted cash +(8 +) +8,859 +(8,603 +) +Production tax liability +4,121 +2,499 +5,436 +Accounts payable and accrued expenses +(11,485 +) +(5,050 +) +12,422 +Other liabilities +(3,165 +) +592 +(2,796 +) +Total changes in assets and liabilities +(48,585 +) +10,835 +(885 +) +Net cash from operating activities +159,165 +174,721 +166,834 +Cash flows from investing activities: +Capital expenditures +(394,948 +) +(347,729 +) +(334,496 +) +Acquisition of crude oil and natural gas properties, net of cash acquired +(9,658 +) +(312,223 +) +(145,894 +) +Proceeds from acquisition adjustments +7,579 +14,469 +— +Proceeds from sale of properties and equipment, net +179,919 +193,544 +23,140 +Other +— +— +849 +Net cash from investing activities +(217,108 +) +(451,939 +) +(456,401 +) +Cash flows from financing activities: +Proceeds from revolving credit facility +260,250 +682,000 +417,194 +Repayment of revolving credit facility +(283,500 +) +(839,750 +) +(183,713 +) +Proceeds from senior notes offering +— +500,000 +— +Redemption of senior notes +— +(221,840 +) +— +Payment of debt issuance costs +(2,352 +) +(11,969 +) +(680 +) +Proceeds from sale of common stock, net of issuance costs +275,847 +164,496 +— +Excess tax benefits from stock-based compensation +2,489 +— +1,311 +Contribution from noncontrolling interest +— +— +12,464 +Purchase of treasury shares +(4,133 +) +(1,500 +) +(3,143 +) +Proceeds from exercise of stock options +128 +— +— +Net cash from financing activities +248,729 +271,437 +243,433 +Net change in cash and cash equivalents +190,786 +(5,781 +) +(46,134 +) +Cash and cash equivalents, beginning of year +2,457 +8,238 +54,372 +Cash and cash equivalents, end of year +$ +193,243 +$ +2,457 +$ +8,238 +Supplemental cash flow information: +Cash payments (receipts) for: +Interest, net of capitalized interest +$ +48,844 +$ +41,768 +$ +29,429 +Income taxes +(3,014 +) +1,845 +(1,498 +) +Non-cash investing activities: +Change in accounts payable related to purchases of properties and equipment +33,328 +288 +23,837 +Change in asset retirement obligation, with a corresponding change to crude oil and natural gas properties, net of disposals +2,112 +11,967 +17,538 +Change in accounts receivable related to disposition of properties and equipment +808 +— +— +Change in other assets related to disposition of properties and equipment +3,350 +— +— +See Note 15, Acquisitions , for non-cash transactions related to our acquisitions +See accompanying Notes to Consolidated Financial Statements +57 +PDC ENERGY, INC. +Consolidated Statements of Equity +(in thousands, except share and per share data) +Year Ended December 31, +2013 +2012 +2011 +Common shares, issued: +Shares beginning of year +30,294,224 +23,634,958 +23,462,326 +Shares issued pursuant to sale of equity +5,175,000 +6,500,000 +— +Exercise of stock options +10,763 +— +2,814 +Issuance of stock awards, net of forfeitures +212,926 +173,737 +242,334 +Retirement of treasury shares +(17,257 +) +(14,471 +) +(72,516 +) +Shares end of year +35,675,656 +30,294,224 +23,634,958 +Treasury shares: +Shares beginning of year +5,059 +2,938 +2,938 +Purchase of treasury shares +84,642 +44,576 +87,588 +Issuance of treasury shares +(67,334 +) +(28,587 +) +(15,072 +) +Retirement of treasury shares +(17,257 +) +(14,471 +) +(72,516 +) +Non-employee directors' deferred compensation plan +398 +603 +— +Shares end of year +5,508 +5,059 +2,938 +Common shares outstanding +35,670,148 +30,289,165 +23,632,020 +Equity: +Shareholders' equity +Preferred shares, par value $0.01 per share: +Balance beginning and end of year +$ +— +$ +— +$ +— +Common shares, par value $0.01 per share: +Balance beginning of year +303 +236 +235 +Shares issued pursuant to sale of equity +52 +65 +— +Issuance of stock awards, net of forfeitures +2 +2 +1 +Balance end of year +357 +303 +236 +Additional paid-in capital: +Balance beginning of year +387,494 +217,707 +209,198 +Proceeds from sale of equity, net of issuance costs +275,795 +164,431 +— +Exercise of stock options +125 +— +— +Stock-based compensation expense +12,402 +8,495 +8,781 +Issuance of treasury shares +(3,270 +) +(955 +) +(472 +) +Retirement of treasury shares +(824 +) +(491 +) +(2,671 +) +Tax impact of stock-based compensation +2,489 +(1,693 +) +785 +Contribution by investing partner in PDCM +— +— +12,464 +Effect of PDCM deconsolidation/change in ownership interest +— +— +(10,378 +) +Balance end of year +674,211 +387,494 +217,707 +Retained earnings: +Balance beginning of year +315,568 +446,280 +432,843 +Net income (loss) attributable to shareholders +(22,301 +) +(130,712 +) +13,437 +Balance end of year +293,267 +315,568 +446,280 +Treasury shares, at cost: +Balance beginning of year +(184 +) +(111 +) +(111 +) +Purchase of treasury shares +(4,133 +) +(1,500 +) +(3,143 +) +Issuance of treasury shares +3,271 +955 +472 +Retirement of treasury shares +824 +491 +2,671 +Non-employee directors' deferred compensation plan +(19 +) +(19 +) +— +Balance end of year +(241 +) +(184 +) +(111 +) +Total shareholders' equity +967,594 +703,181 +664,112 +Noncontrolling interests in subsidiary +Balance beginning of year +— +— +76 +Net loss attributed to noncontrolling interest in subsidiary +— +— +(76 +) +Balance end of year +— +— +— +Total noncontrolling interests in subsidiary +— +— +— +Total Equity +$ +967,594 +$ +703,181 +$ +664,112 +See accompanying Notes to Consolidated Financial Statements +58 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +NOTE 1 - NATURE OF OPERATIONS AND BASIS OF PRESENTATION +PDC Energy, Inc. is a domestic independent exploration and production company that produces, develops, acquires, and explores for crude oil, natural gas and NGLs with primary operations in the Wattenberg Field in Colorado, the Utica Shale in southeastern Ohio and the Appalachia-Marcellus Shale in northern West Virginia. Our operations in the Wattenberg Field are focused on the liquid-rich horizontal Niobrara and Codell plays. We are currently focusing our Ohio development in the liquid-rich portion of the Utica Shale play and are pursuing horizontal development of the Marcellus Shale in West Virginia. As of December 31, 2013 , we owned an interest in approximately 3,100 gross wells. We are engaged in two business segments: (1) Oil and Gas Exploration and Production and (2) Gas Marketing. +The consolidated financial statements include the accounts of PDC, our wholly owned subsidiaries and our proportionate share of PDC Mountaineer, LLC and our affiliated partnerships. Pursuant to the proportionate consolidation method, our accompanying consolidated financial statements include our pro rata share of assets, liabilities, revenues and expenses of the entities which we proportionately consolidate. All material intercompany accounts and transactions have been eliminated in consolidation. +The preparation of our consolidated financial statements in accordance with U.S. GAAP requires us to make estimates and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to our consolidated financial statements include estimates of crude oil, natural gas and NGLs sales revenue, crude oil, natural gas and NGLs reserves, future cash flows from crude oil and natural gas properties, valuation of derivative instruments and valuation of deferred income tax assets. +Certain reclassifications have been made to prior period financial statements to conform to the current year presentation. These reclassifications had no impact on previously reported cash flows, net income, earnings per share or shareholders' equity. +NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Cash Equivalents. We consider all highly liquid investments with original maturities of three months or less to be cash equivalents. +Restricted Cash. We are required by certain government agencies or agreements to maintain bonds or cash accounts for various operating activities. As of December 31, 2013 , we had collateral in the form of certificates of deposit and cash totaling $3.3 million which consisted of $2.2 million and $1.1 million included in restricted cash and other assets, respectively. As of December 31, 2012 , we had collateral in the form of certificates of deposit and cash totaling $5.3 million which consisted of $3.9 million and $1.4 million included in restricted cash and other assets, respectively. +Inventory. Inventory consists of crude oil, stated at the lower of cost to produce or market, and other production supplies intended to be used in our crude oil and natural gas operations. As of December 31, 2013 and 2012 , inventory of $0.9 million and $1.2 million , respectively, is included in prepaid expenses and other current assets on the consolidated balance sheets. +Derivative Financial Instruments. We are exposed to the effect of market fluctuations in the prices of crude oil, natural gas and NGLs. We employ established policies and procedures to manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. Our policy prohibits the use of natural gas and crude oil derivative instruments for speculative purposes. +All derivative assets and liabilities are recorded on our consolidated balance sheets at fair value. We have elected not to designate any of our derivative instruments as hedges. Classification of net settlements resulting from maturities and changes in fair value of unsettled derivatives depends on the purpose for issuing or holding the derivative. Accordingly, changes in the fair value of our derivative instruments are recorded in the consolidated statements of operations. Changes in the fair value of derivative instruments related to our Oil and Gas Exploration and Production segment are recorded in commodity price risk management, net. Changes in the fair value of derivative instruments related to our Gas Marketing segment are recorded in sales from and cost of natural gas marketing. Changes in the fair value of the derivative instruments designated to our affiliated partnerships are recorded on the consolidated balance sheets in accounts receivable affiliates and accounts payable affiliates. As positions designated to our affiliated partnerships mature, the cash settlements are netted for distribution. Net settlements are paid to the partnerships or deducted from the partnerships’ cash distributions from production. The affiliated partnerships bear their designated share of counterparty risk. As of December 31, 2013 , our affiliated partnerships had no outstanding derivative instruments. +The validation of the derivative instrument's fair value is performed internally and, while we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. See Note 3, Fair Value of Financial Instruments , and Note 4, Derivative Financial Instruments , for a discussion of our derivative fair value measurements and a summary fair value table of our open positions as of December 31, 2013 and 2012 , respectively. +Properties and Equipment. Significant accounting polices related to our properties and equipment are discussed below. +Crude Oil and Natural Gas Properties. We account for our crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves. We calculate quarterly DD&A expense by using our estimated prior period-end reserves as the denominator, with the exception of our fourth quarter where we use the year-end reserve estimate adjusted to add back fourth quarter production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized in the consolidated statement of operations as a gain or loss. Upon the sale of individual wells or a portion of a field, the proceeds are credited to accumulated DD&A. +59 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Exploration costs, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but charged to expense if the well is determined to be economically nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as we have found a sufficient quantity of reserves to justify completion as a producing well, we are making sufficient progress assessing our reserves and economic and operating viability or we have not made sufficient progress to allow for final determination of productivity. If an in-progress exploratory well is found to be economically unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the costs associated with the well are classified as "suspended well costs" until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time we are able to make a final determination of a well’s productive status, the well is removed from suspended well status and the proper accounting treatment is recorded. See Note 6, Properties and Equipment , for disclosure related to changes in our capitalized exploratory well costs. +Proved Property Impairment. Upon a triggering event, we assess our producing crude oil and natural gas properties for possible impairment by comparing net capitalized costs, or carrying value, to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which we reasonably estimate the commodity to be sold. The estimates of future prices may differ from current market prices of crude oil, natural gas and NGLs. Certain events, including but not limited to downward revisions in estimates to our reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event and, therefore, a possible impairment of our proved crude oil and natural gas properties. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis and is measured by the amount by which the net capitalized costs exceed their fair value. Impairments are included in the consolidated statement of operations line item impairment of crude oil and natural gas properties, with a corresponding impact on accumulated DD&A on the consolidated balance sheet. +Unproved Property Impairment. The acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense when expired, impaired or amortized. Unproved crude oil and natural gas properties with individually significant acquisition costs are periodically assessed for impairment. Unproved crude oil and natural gas properties which are not individually significant are amortized, by field, based on our historical experience, acquisition dates and average lease terms. Impairment and amortization charges related to unproved crude oil and natural gas properties are charged to the consolidated statement of operations line item impairment of crude oil and natural gas properties. +Other Property and Equipment. Other property and equipment is carried at cost. Depreciation is provided principally on the straight-line method over the assets' estimated useful lives. We review these long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of the asset exceeds our estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. No impairment to other property and equipment was recognized in 2013, 2012 or 2011. +The following table presents the estimated useful lives of our other property and equipment: +Pipelines and related facilities +10 - 17 years +Transportation and other equipment +3 - 20 years +Buildings +20 - 30 years +Maintenance and repair costs on other property and equipment are charged to expense as incurred. Major renewals and improvements are capitalized and depreciated over the remaining useful life of the asset. Upon the sale or other disposition of assets, the cost and related accumulated DD&A are removed from the accounts, the proceeds are applied thereto and any resulting gain or loss is reflected in income. Total depreciation expense related to other property and equipment was $5.1 million , $4.7 million and $4 million in 2013 , 2012 and 2011 , respectively. +Capitalized Interest. Interest costs are capitalized as part of the historical cost of acquiring assets. Investments in unproved crude oil and natural gas properties and major development projects, on which DD&A is not currently recorded and on which exploration or development activities are in progress, qualify for capitalization of interest. Major construction projects also qualify for interest capitalization until the asset is ready to be placed into service. Capitalized interest is calculated by multiplying our weighted-average interest rate on our debt outstanding by the qualifying costs. Interest capitalized may not exceed gross interest expense for the period. As the qualifying asset is placed into service, we begin amortizing the related capitalized interest over the useful life of the asset. Capitalized interest totaled $1.9 million , $1.2 million and $1.7 million in 2013 , 2012 and 2011 , respectively. +Assets Held for Sale. Assets held for sale are valued at the lower of their carrying amount or estimated fair value, less costs to sell. If the carrying amount of the assets exceeds their estimated fair value, an impairment loss is recognized. Fair values are estimated using accepted valuation techniques such as a discounted cash flow model, valuations performed by third parties, earnings multiples or indicative bids, when available. Management considers historical experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial statements. DD&A expense is not recorded on assets to be divested once they are classified as held for sale. Assets classified as held for sale are +60 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +expected to be disposed of within one year. Assets to be divested are classified in the consolidated financial statements as held for sale and the activities of assets to be divested are classified either as discontinued operations or continuing operations. For assets classified as discontinued operations, the results of operations are reclassified from their historical presentation to discontinued operations on the consolidated statements of operations for all periods presented. The gains or losses associated with these divested assets are recorded in discontinued operations on the consolidated statements of operations. Management does not expect any continuing involvement with businesses classified as discontinued operations following their divestiture. For businesses classified as held for sale that do not qualify for discontinued operations treatment, the results of operations continue to be reported in continuing operations. +Production Tax Liability. Production tax liability represents estimated taxes, primarily severance, ad valorem and property, to be paid to the states and counties in which we produce crude oil, natural gas and NGLs, including the production of our affiliated partnerships. Our share of these taxes is expensed to production costs. The partnerships' share, not owned by us, is recognized as a receivable in accounts receivable affiliates on the consolidated balance sheets. The long-term portion of the production tax liability is included in other liabilities on the consolidated balance sheets and was $22.1 million and $18.7 million in December 31, 2013 and 2012 , respectively. +Income Taxes. We account for income taxes under the asset and liability method. We recognize deferred tax assets and liabilities for the future tax consequences attributable to operating loss and credit carryforwards and differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. If we determine that it is more likely than not that some portion or all of the deferred tax assets will not be realized, we record a valuation allowance, thereby reducing the deferred tax assets to what we consider realizable. As of December 31, 2013 and 2012 , we had no valuation allowance. +Debt Issuance Costs. Debt issuance costs are capitalized and amortized over the life of the respective borrowings using the effective interest method. As of December 31, 2013 and 2012 , included in other assets was $16.6 million and $17.4 million , respectively, related to debt issuance costs. The December 31, 2013 amount included $1.3 million in costs related to the issuance of our 3.25% convertible senior notes due 2016, $9.8 million related to our 7.75% senior notes due 2022 and $5.5 million related to our revolving credit facility and the PDCM credit facility. The December 31, 2012 amount included $1.9 million in costs related to the issuance of our 3.25% convertible senior notes due 2016, $10.9 million related to our 7.75% senior notes due 2022 and $4.6 million related to our revolving credit facility and the PDCM credit facility. +Asset Retirement Obligations. We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the well is completed. Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the associated long-lived asset by the same amount as the liability. Over time, the liability is accreted for the change in the present value. The initial capitalized cost, net of salvage value, is depleted over the useful life of the related asset through a charge to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from changes in retirement costs or the estimated timing of settling asset retirement obligations. See Note 9, Asset Retirement Obligations , for a reconciliation of the changes in our asset retirement obligation. +Treasury Shares. We record treasury share purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as reductions in shareholders’ equity in the consolidated balance sheets. When we retire treasury shares, we charge any excess of cost over the par value entirely to additional paid-in-capital ("APIC"), to the extent we have amounts in APIC, with any remaining excess cost being charged to retained earnings. +Revenue Recognition. Significant accounting polices related to our revenue recognition are discussed below. +Crude oil, natural gas and NGLs sales. Crude oil, natural gas and NGLs revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. We currently use the "net-back" method of accounting for transportation and processing arrangements of our sales pursuant to which the transportation and/or processing is provided by or through the purchaser. Under these arrangements, we sell gas at the wellhead and collect a price and recognize revenues based on the wellhead sales price since transportation and processing costs downstream of the wellhead are incurred by the purchasers and reflected in the wellhead price. The majority of our natural gas and NGLs in the Wattenberg Field are sold on a long-term basis, primarily over the life of the lease. Sales of natural gas and NGLs in other regions, along with crude oil, are sold under short-term contracts of less than one year. Virtually all of our contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line and the quality of the natural gas. +Well operations and pipeline income . We are paid a monthly operating fee for each well we operate and the natural gas transported for outside owners, including the affiliated partnerships we sponsor. Well operations and pipeline income is recognized when persuasive evidence of an arrangement exists, the sales price is fixed or determinable, services have been rendered and collection of revenues is reasonably assured. +Natural gas marketing. Natural gas marketing is reported on the gross method of accounting, based on the nature of the agreements between our natural gas marketing subsidiary, RNG, suppliers and customers. RNG purchases gas from many small producers and bundles the gas together for a price advantage to sell in larger amounts to purchasers of natural gas. RNG has latitude in establishing price and discretion in supplier and purchaser selection. Natural gas marketing revenues and expenses reflect the full cost and revenue of those transactions because RNG takes title to the gas it purchases from the various producers and bears the risks and rewards of that ownership. Both the net settlements +61 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +and net change in fair value of unsettled derivatives of the RNG commodity-based derivative transactions for natural gas marketing are included in sales from or cost of natural gas marketing, as applicable. +Accounting for Acquisitions. We utilize the purchase method to account for acquisitions. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based upon respective fair values as of the acquisition date. The purchase price allocations are based upon appraisals, discounted cash flows, quoted market prices and estimates by management. When appropriate, we review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties. +In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped, unproved crude oil and natural gas properties and other non-crude oil and natural gas properties. To estimate the fair value of these properties, we prepare estimates of crude oil and natural gas reserves. We estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired, and estimates of future operating and development costs, to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is subject to additional project-specific risk factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors. +We record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. +Stock-Based Compensation. Stock-based compensation is recognized in our financial statements based on the grant-date fair value of the equity instrument awarded. Stock based compensation expense is recognized in the financial statements on a straight-line basis over the vesting period for the entire award. To the extent compensation cost relates to employees directly involved in crude oil and natural gas exploration and development activities, such amounts may be capitalized to properties and equipment. Amounts not capitalized to properties and equipment are recognized in the related cost and expense line item in the consolidated statement of operations. No amounts for stock-based compensation were capitalized in 2013 , 2012 and 2011 . +Recent Accounting Standards. +Recently Adopted Accounting Standard. On January 1, 2013, we adopted changes issued by the Financial Accounting Standards Board ("FASB") regarding the disclosure of offsetting assets and liabilities. These changes require an entity to disclose both gross and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an enforceable master netting arrangement or similar agreement. The enhanced disclosures enable users of an entity’s financial statements to understand and evaluate the effect or potential effect of master netting arrangements on the entity’s financial position, including the effect or potential effect of rights of setoff associated with certain financial instruments and derivative instruments. Adoption of these changes had no impact on the consolidated financial statements, except for additional disclosures. +Recently Issued Accounting Standard. On July 18, 2013, the FASB issued an update to accounting for income taxes. The update provides clarification on the presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss or a tax credit carryforward exists. The update is effective for public entities for fiscal years, and interim periods within those years, beginning after December 15, 2013. Early adoption is permitted. We are currently evaluating the impact of adopting this update on our financial statements, but do not believe it will have a material impact. +NOTE 3 - FAIR VALUE OF FINANCIAL INSTRUMENTS +Derivative Financial Instruments +Determination of fair value. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as: +Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets. +Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in +62 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means. +Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity. +Derivative Financial Instruments. We measure the fair value of our derivative instruments based on a pricing model that utilizes market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of derivative liabilities and the effect of our counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position. +We validate our fair value measurement through the review of counterparty statements and other supporting documentation, the determination that the source of the inputs is valid, the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and assumptions. While we use common industry practices to develop our valuation techniques and believe our valuation method is appropriate and consistent with those used by other market participants, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. +Our fixed-price swaps, basis swaps and physical purchases are included in Level 2 and our crude oil and natural gas collars, natural gas calls and physical sales are included in Level 3. The following table presents, for each applicable level within the fair value hierarchy, our derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis: +As of December 31, +2013 +2012 +Significant Other +Observable +Inputs +(Level 2) +Significant +Unobservable +Inputs +(Level 3) +Total +Significant Other +Observable +Inputs +(Level 2) +Significant +Unobservable +Inputs +(Level 3) +Total +(in thousands) +Assets: +Commodity-based derivative contracts +$ +5,325 +$ +2,385 +$ +7,710 +$ +42,798 +$ +15,750 +$ +58,548 +Basis protection derivative contracts +463 +— +463 +377 +— +377 +Total assets +5,788 +2,385 +8,173 +43,175 +15,750 +58,925 +Liabilities: +Commodity-based derivative contracts +17,537 +988 +18,525 +9,839 +2,081 +11,920 +Basis protection derivative contracts +5 +— +5 +16,656 +— +16,656 +Total liabilities +17,542 +988 +18,530 +26,495 +2,081 +28,576 +Net asset (liability) +$ +(11,754 +) +$ +1,397 +$ +(10,357 +) +$ +16,680 +$ +13,669 +$ +30,349 +63 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents a reconciliation of our Level 3 assets measured at fair value: +2013 +2012 +2011 +(in thousands) +Fair value, net asset, beginning of period +$ +13,669 +$ +22,107 +$ +10,762 +Changes in fair value included in statement of operations line item: +Commodity price risk management gain (loss), net +(1,521 +) +7,576 +13,487 +Sales from natural gas marketing +13 +63 +114 +Changes in fair value included in balance sheet line item (1): +Accounts receivable affiliates +— +— +49 +Accounts payable affiliates +— +(319 +) +(454 +) +Settlements included in statement of operations line items: +Commodity price risk management gain (loss), net +(6,361 +) +(15,644 +) +(1,712 +) +Sales from natural gas marketing +(37 +) +(114 +) +(139 +) +Income (loss) from discontinued operations, net of tax +(4,366 +) +— +— +Fair value, net asset end of period +$ +1,397 +$ +13,669 +$ +22,107 +Net change in fair value of unsettled derivatives included in statement of operations line item: +Commodity price risk management gain (loss), net +$ +(1,032 +) +$ +3,665 +$ +11,669 +Sales from natural gas marketing +4 +1 +(3 +) +Total +$ +(1,028 +) +$ +3,666 +$ +11,666 +__________ +(1) +Represents the change in fair value related to derivative instruments entered into by us and designated to our affiliated partnerships. +The significant unobservable input used in the fair value measurement of our derivative contracts is the implied volatility curve, which is provided by a third-party vendor. A significant increase or decrease in the implied volatility, in isolation, would have a directionally similar effect resulting in a significantly higher or lower fair value measurement of our Level 3 derivative contracts. +Non-Derivative Financial Assets and Liabilities +The carrying value of the financial instruments included in current assets and current liabilities approximate fair value due to the short-term maturities of these instruments. +The liability associated with our non-qualified deferred compensation plan for non-employee directors may be settled in cash or shares of our common stock. The carrying value of this obligation is based on the quoted market price of our common stock, which is a Level 1 input. +The portion of our long-term debt related to our revolving credit facility, as well as our proportionate share of PDCM's credit facility, approximates fair value due to the variable nature of related interest rates. We have not elected to account for the portion of our long-term debt related to our senior notes under the fair value option; however, as of December 31, 2013 , we estimate the fair value of the portion of our long-term debt related to the 3.25% convertible senior notes due 2016 to be $165.4 million , or 143.9% of par value, and the portion related to our 7.75% senior notes due 2022 to be $543.1 million , or 108.6% of par value. We determined these valuations based upon measurements of trading activity and broker and/or dealer quotes, respectively, which are published market prices, and therefore are Level 2 inputs. +See Note 2, Summary of Significant Accounting Policies - Properties and Equipment, Crude Oil and Natural Gas Properties and Asset Retirement Obligations, for a discussion of how we determined fair value for these assets and liabilities. +NOTE 4 - DERIVATIVE FINANCIAL INSTRUMENTS +Our results of operations and operating cash flows are affected by changes in market prices for crude oil, natural gas and NGLs. To manage a portion of our exposure to price volatility from producing crude oil and natural gas, we utilize the following economic hedging strategies for each of our business segments. +• +For crude oil and natural gas sales, we enter into derivative contracts to protect against price declines in future periods. While we structure these derivatives to reduce our exposure to changes in price associated with the derivative commodity, they also limit the benefit we might otherwise have received from price increases in the physical market; and +• +For natural gas marketing, we enter into fixed-price physical purchase and sale agreements that qualify as derivative contracts. In order to offset the fixed-price physical derivatives in our natural gas marketing, we enter into financial derivative instruments +that have the effect of locking in the prices we will receive or pay for the same volumes and period, offsetting the physical derivative. +We believe our derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. As of December 31, 2013 , we had derivative instruments in place for a portion of our anticipated production through 2017 for a total of 59,971 BBtu of natural gas and 8,613 MBbls of crude oil. +As of December 31, 2013 , our derivative instruments were comprised of commodity swaps, collars, basis protection swaps and physical sales and purchases. +• +Collars contain a fixed floor price and ceiling price (call). If the index price falls below the fixed put strike price, we receive the market price from the purchaser and receive the difference between the put strike price and index price from the counterparty. If the index price exceeds the fixed call strike price, we receive the market price from the purchaser and pay the difference between the call strike price and index price to the counterparty. If the index price is between the put and call strike price, no payments are due to or from the counterparty; +• +Swaps are arrangements that guarantee a fixed price. If the index price is below the fixed contract price, we receive the market price from the purchaser and receive the difference between the index price and the fixed contract price from the counterparty. If the index price is above the fixed contract price, we receive the market price from the purchaser and pay the difference between the index price and the fixed contract price to the counterparty. If the index price and contract price are the same, no payment is due to or from the counterparty; +• +Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point. For CIG-basis protection swaps and TCO-basis protection swaps, which currently have negative differentials to NYMEX, we receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract. If the market price and contract price are the same, no payment is due to or from the counterparty; and +• +Physical sales and purchases are derivatives for fixed-priced physical transactions where we sell or purchase third-party supply at fixed rates. These physical derivatives are offset by financial swaps: for a physical sale the offset is a swap purchase and for a physical purchase the offset is a swap sale. +64 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the location and fair value amounts of our derivative instruments on the consolidated balance sheets as of December 31, 2013 and 2012 : +Derivatives instruments: +Balance sheet line item +2013 +2012 +(in thousands) +Derivative assets: +Current +Commodity contracts +Related to crude oil and natural gas sales +Fair value of derivatives +$ +2,016 +$ +46,657 +Related to affiliated partnerships (1) +Fair value of derivatives +— +4,707 +Related to natural gas marketing +Fair value of derivatives +361 +319 +Basis protection contracts +Related to crude oil and natural gas sales +Fair value of derivatives +195 +359 +2,572 +52,042 +Non Current +Commodity contracts +Related to crude oil and natural gas sales +Fair value of derivatives +5,055 +6,653 +Related to natural gas marketing +Fair value of derivatives +278 +212 +Basis protection contracts +Related to crude oil and natural gas sales +Fair value of derivatives +268 +18 +5,601 +6,883 +Total derivative assets +$ +8,173 +$ +58,925 +Derivative liabilities: +Current +Commodity contracts +Related to crude oil and natural gas sales +Fair value of derivatives +$ +15,263 +$ +1,698 +Related to natural gas marketing +Fair value of derivatives +247 +226 +Basis protection contracts +Related to crude oil and natural gas sales +Fair value of derivatives +— +14,375 +Related to affiliated partnerships (2) +Fair value of derivatives +— +2,140 +Related to natural gas marketing +Fair value of derivatives +5 +— +15,515 +18,439 +Non Current +Commodity contracts +Related to crude oil and natural gas sales +Fair value of derivatives +2,782 +9,828 +Related to natural gas marketing +Fair value of derivatives +233 +168 +Basis protection contracts +Related to crude oil and natural gas sales +Fair value of derivatives +— +141 +3,015 +10,137 +Total derivative liabilities +$ +18,530 +$ +28,576 +__________ +(1) +Represents derivative positions designated to our affiliated partnerships. Accordingly, our accompanying consolidated balance sheets include a corresponding payable to our affiliated partnerships representing their proportionate share of the derivative assets. +(2) +Represents derivative positions designated to our affiliated partnerships. Accordingly, our accompanying consolidated balance sheets include a corresponding receivable from our affiliated partnerships representing their proportionate share of the derivative liabilities. +65 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the impact of our derivative instruments on our consolidated statements of operations: +Year Ended December 31, +Consolidated statement of operations line item +2013 +2012 +2011 +Commodity price risk management gain (loss), net +Net settlements +$ +12,913 +$ +49,416 +$ +17,243 +Net change in fair value of unsettled derivatives +(36,818 +) +(17,077 +) +28,847 +Total commodity price risk management gain (loss), net +$ +(23,905 +) +$ +32,339 +$ +46,090 +Sales from natural gas marketing +Net settlements +$ +446 +$ +2,170 +$ +2,970 +Net change in fair value of unsettled derivatives +429 +(1,658 +) +(161 +) +Total sales from natural gas marketing +$ +875 +$ +512 +$ +2,809 +Cost of natural gas marketing +Net settlements +$ +(257 +) +$ +(2,029 +) +$ +(2,571 +) +Net change in fair value of unsettled derivatives +(412 +) +1,601 +(85 +) +Total cost of natural gas marketing +$ +(669 +) +$ +(428 +) +$ +(2,656 +) +All of our financial derivative agreements contain master netting provisions that provide for the net settlement of all contracts through a single payment in the event of early termination. Our fixed-price physical purchase and sale agreements that qualify as derivative contracts are not subject to master netting provisions and are not significant. We have elected not to offset the fair value positions recorded on our consolidated balance sheets. +The following table reflects the impact of netting agreements on gross derivative assets and liabilities as of December 31, 2013 and 2012 : +As of December 31, 2013 +Derivatives instruments, recorded in consolidated balance sheet, gross +Effect of master netting agreements +Derivative instruments, net +(in thousands) +Asset derivatives: +Derivative instruments, at fair value +$ +8,173 +$ +(5,623 +) +$ +2,550 +Liability derivatives: +Derivative instruments, at fair value +$ +18,530 +$ +(5,623 +) +$ +12,907 +As of December 31, 2012 +Derivatives instruments, recorded in consolidated balance sheet, gross +Effect of master netting agreements +Derivative instruments, net +(in thousands) +Asset derivatives: +Derivative instruments, at fair value +$ +58,925 +$ +(11,437 +) +$ +47,488 +Liability derivatives: +Derivative instruments, at fair value +$ +28,576 +$ +(11,437 +) +$ +17,139 +66 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 5 - CONCENTRATION OF RISK +Accounts Receivable. The following table presents the components of accounts receivable, net of allowance for doubtful accounts: +As of December 31, +2013 +2012 +(in thousands) +Crude oil, natural gas and NGLs sales +$ +66,257 +$ +39,837 +Joint interest billings +20,558 +6,896 +Natural gas marketing +6,210 +8,209 +Reimbursements for title defects +— +7,579 +Other +2,321 +3,385 +Allowance for doubtful accounts +(1,261 +) +(1,026 +) +Accounts receivable, net +$ +94,085 +$ +64,880 +Our accounts receivable primarily relates to sales of our crude oil, natural gas and NGLs production, derivative counterparties and other third parties that own working interests in the properties we operate. Inherent to our industry is the concentration of crude oil, natural gas and NGLs sales to a limited number of customers. This concentration has the potential to impact our overall exposure to credit risk in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions. We record an allowance for doubtful accounts representing our best estimate of probable losses from our existing accounts receivable. In making our estimate, we consider, among other things, our historical write-offs and overall creditworthiness of our customers. Further, consideration is given to well production data for receivables related to well operations. Our estimate of uncollectible amounts changes periodically. For the each of the years in the three-year period ended December 31, 2013 , amounts written off to allowance for doubtful accounts were not material. As of December 31, 2013 , we had two customers representing 10% or greater of our accounts receivable balance: Suncor Energy Marketing and DCP Midstream, representing 26.3% and 10.8% , respectively, of our accounts receivable balance. The $7.6 million of accounts receivable at December 31, 2012 related to reimbursements for title defects discovered subsequent to closing of the Merit Acquisition. The reimbursement was received in January 2013. +Major Customers. The following table presents the individual customers constituting 10% or more of total revenues: +Year Ended December 31, +Customer +2013 +2012 +2011 +Suncor Energy Marketing, Inc. +31.3 +% +29.8 +% +25.7 +% +DCP Midstream, LP +14.6 +% +12.2 +% +11.5 +% +Derivative Counterparties. A significant portion of our liquidity is concentrated in derivative instruments that enable us to manage a portion of our exposure to price volatility from producing crude oil and natural gas. These arrangements expose us to credit risk of nonperformance by our counterparties. We primarily use financial institutions who are also major lenders under our revolving credit facility as counterparties to our derivative contracts. To date, we have had no derivative counterparty default losses. We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our current counterparties on the fair value of our derivative instruments is not significant. +67 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the counterparties that expose us to credit risk as of December 31, 2013 , with regard to our derivative assets: +Fair Value of +Derivative Assets +Counterparty Name +As of December 31, 2013 +(in thousands) +Wells Fargo Bank, N.A. (1) +$ +2,496 +Bank of Montreal (1) +1,102 +Canadian Imperial Bank of Commerce (1) +1,054 +Other lenders in our revolving credit facility +3,380 +Various (2) +141 +Total +$ +8,173 +____________ +(1) Major lender in our revolving credit facility. See Note 8, Long-Term Debt. +(2) Represents a total of 19 counterparties. +NOTE 6 - PROPERTIES AND EQUIPMENT +The following table presents the components of properties and equipment, net of accumulated DD&A: +As of December 31, +2013 +2012 +(in thousands) +Properties and equipment, net: +Crude oil and natural gas properties +Proved +$ +1,781,681 +$ +2,075,924 +Unproved +307,203 +319,327 +Total crude oil and natural gas properties +2,088,884 +2,395,251 +Pipelines and related facilities +21,781 +47,786 +Equipment and other +29,246 +34,858 +Land and buildings +13,617 +14,935 +Construction in progress +53,810 +67,217 +Gross properties and equipment +2,207,338 +2,560,047 +Accumulated DD&A +(553,893 +) +(943,341 +) +Properties and equipment, net +$ +1,653,445 +$ +1,616,706 +The following table presents impairment charges recorded for crude oil and natural gas properties: +Year Ended December 31, +2013 +2012 +2011 +(in thousands) +Continuing operations: +Impairment of proved properties +$ +48,750 +$ +— +$ +— +Impairment of individually significant unproved properties +1,082 +1,629 +1,108 +Amortization of individually insignificant unproved properties +3,603 +4,266 +1,193 +Total continuing operations +53,435 +5,895 +2,301 +Discontinued operations: +Impairment of proved properties +— +161,185 +22,460 +Impairment of individually significant unproved properties +— +313 +— +Amortization of individually insignificant unproved properties +3 +756 +398 +Total discontinued operations +3 +162,254 +22,858 +Total impairment of crude oil and natural gas properties +$ +53,438 +$ +168,149 +$ +25,159 +68 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +In the first quarter of 2013, we recognized an impairment charge of approximately $45.0 million related to all of our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin producing properties located in West Virginia and Pennsylvania owned directly by us, as well as through our proportionate share of PDCM. The impairment charge represented the excess of the carrying value of the assets over the estimated fair value, less cost to sell. The fair value of the assets was determined based upon estimated future cash flows from unrelated third-party bids, a Level 3 input. Pursuant to a purchase and sale agreement entered into in October 2013, we determined that the carrying value of the above-mentioned properties exceeded the transaction sales price, a Level 3 input, less costs to sell. As a result, we recognized an additional impairment charge of approximately $3.8 million in the third quarter of 2013 to reduce the carrying value of the net assets to reflect the current net sales price. The impairment charge was included in the consolidated statement of operations line item impairment of crude oil and natural gas properties. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information regarding these properties. +In 2012, we recognized an impairment charge of $161.2 million to write-down our Piceance Basin proved oil and natural gas properties to fair value. The fair value was based on estimated future cash flows from an unrelated third-party bid, a Level 3 input. The impairment charge was included in the consolidated statement of operations line item impairment of crude oil and natural gas properties. +In 2011, we recognized an impairment charge of $22.5 million to write-down our NECO assets to fair value. The fair value was based on unrelated third-party bids, a Level 3 input. The impairment charge was included in the consolidated statement of operations line item impairment of crude oil and natural gas properties. +Suspended Well Costs +The following table presents the capitalized exploratory well costs pending determination of proved reserves, and included in properties and equipment on the consolidated balance sheets: +2013 +2012 +2011 +(in thousands, except for number of wells) +Balance beginning of year, January 1, +$ +19,567 +$ +4,432 +$ +2,297 +Additions to capitalized exploratory well costs pending the determination of proved reserves +13,424 +30,482 +3,692 +Reclassifications to wells, facilities and equipment based on the determination of proved reserves +(32,991 +) +— +(1,557 +) +Capitalized exploratory well costs charged to expense +— +(15,347 +) +— +Balance end of year, December 31, +$ +— +$ +19,567 +$ +4,432 +Number of wells pending determination at December 31, +— +2 +6 +As of December 31, 2013 , none of our wells pending determination were classified as exploratory wells. +Additions to capitalized exploratory well costs pending determination of proved reserves increased in 2012 as compared to 2011 as we increased our exploratory drilling activities in the Utica Shale play. In 2012, capitalized well costs related to two vertical stratigraphic test wells in southeastern Ohio were expensed at a cost of $12.2 million . Additionally, three Rose Run test wells in Ohio and a well in southeast Colorado were determined to have noncommercial quantities of hydrocarbons and were expensed at a cost of $1.2 million and $0.9 million , respectively. +The following table presents an aging of capitalized exploratory well costs based on the date that drilling commenced and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the commencement of drilling: +As of December 31, +2012 +2011 +(in thousands) +Exploratory well costs capitalized for a period of one year or less +$ +19,567 +$ +3,587 +Exploratory well costs capitalized for a period greater than one year since commencement of drilling +— +845 +Balance end of year, December 31, +$ +19,567 +$ +4,432 +Number of projects with exploratory well costs that have been capitalized for a period greater than one year since commencement of drilling +— +2 +69 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 7 - INCOME TAXES +The table below presents the components of our provision for income taxes from continuing operations for the years presented: +Year Ended December 31, +2013 +2012 +2011 +(in thousands) +Current: +Federal +$ +1,355 +$ +— +$ +2,594 +State +199 +(199 +) +750 +Total current income taxes +1,554 +(199 +) +3,344 +Deferred: +Federal +11,145 +12,133 +(13,309 +) +State +2,098 +767 +(1,835 +) +Total deferred income taxes +13,243 +12,900 +(15,144 +) +Income tax benefit (expense) from continuing operations +$ +14,797 +$ +12,701 +$ +(11,800 +) +In 2012 and 2011, we continued to utilize tax deferral strategies such as bonus depreciation, accelerated depreciation and intangible drilling cost expense elections to minimize our current taxes. As a result of these elections and deferral strategies, we generated federal and state net operating losses (“NOLs”) in 2012 and 2011. In 2013 we limited our deferral strategies to only the continued utilization of accelerated depreciation in an effort to utilize our federal NOLs. The majority of our federal NOLs and some of our state NOLs, except for Colorado due to statutory limits, are being utilized in 2013 to offset the 2013 taxable gain on the sale of our non-core Colorado assets. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information regarding the sale of our non-core Colorado assets. The remaining federal NOLs and state NOLs will be carried forward to offset taxable income in 2014 or prospective years. +The following table presents a reconciliation of the statutory rate to the effective tax rate related to our provision for income taxes from continuing operations: +Year Ended December, 31, +2013 +2012 +2011 +Statutory tax rate +35.0 +% +35.0 +% +35.0 +% +State income tax, net +3.3 +1.0 +2.0 +Percentage depletion +1.8 +1.9 +(2.5 +) +Non-deductible compensation +(3.4 +) +(0.5 +) +— +Non-deductible meals and entertainment +(0.5 +) +(0.5 +) +0.3 +State deferred rate change +— +— +1.3 +Unrecognized tax benefits +(0.1 +) +— +(2.6 +) +Federal return examination adjustments +— +— +0.4 +Return to provision adjustments +(0.5 +) +— +0.3 +Other +0.3 +— +0.1 +Effective tax rate +35.9 +% +36.9 +% +34.3 +% +70 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2013 and 2012 are presented below: +As of December 31, +2013 +2012 +(in thousands) +Deferred tax assets: +Net change in fair value of unsettled derivatives +$ +6,205 +$ +— +Deferred compensation +8,507 +7,216 +Asset retirement obligations +11,630 +10,325 +State NOL and tax credit carryforwards, net +5,182 +6,117 +Percentage depletion - carryforward +4,570 +4,702 +Alternative minimum tax - credit carryforward +3,165 +2,351 +Federal NOL carryforward +4,601 +21,281 +Other +6,229 +2,276 +Deferred tax assets +50,089 +54,268 +Deferred tax liabilities: +Properties and equipment +120,746 +122,742 +Investment in PDCM +21,962 +31,445 +Net change in fair value of unsettled derivatives +— +7,163 +Convertible debt +3,774 +5,194 +Total gross deferred tax liabilities +146,482 +166,544 +Net deferred tax liability +$ +96,393 +$ +112,276 +Classification in the consolidated balance sheets: +Deferred income tax assets +$ +22,374 +$ +36,151 +Deferred income tax liability +118,767 +148,427 +Net deferred tax liability +$ +96,393 +$ +112,276 +Deferred tax assets decreased primarily due to the utilization of a significant portion of our federal NOL carryforward in 2013. This decrease was partially offset by the addition of the deferred tax asset associated with the unrealized tax loss for the fair value of unsettled derivatives. +Deferred tax liabilities for properties and equipment remained relatively unchanged in 2013 primarily as a result of our tax gain on the sale of our non-core Colorado properties and equipment being offset by our continued use of statutory provisions for accelerated amortization of intangible drilling costs and accelerated tax depreciation. The deferred tax liability associated with our investment in PDCM decreased due to PDCM’s sale of its shallow Devonian assets. In addition, the fair value of derivatives at December 31, 2013 resulted in an unrealized tax loss versus an unrealized tax gain at December 31, 2012. +As of December 31, 2013 , we have state NOL carryforwards of $136.1 million that begin to expire in 2030 , state credit carryforwards of $1.1 million that begin to expire in 2023 and federal NOL carryforwards of $13.6 million that will expire in 2032 . Approximately $0.2 million of excess tax benefits relating to stock-based compensation that are a component of our NOL carryforwards, when realized, will be credited to APIC. +Unrecognized tax benefits were immaterial for each of the years in the three-year period ended December 31, 2013 . Interest and penalties related to uncertain tax positions are recognized in income tax expense. Accrued interest and penalties related to uncertain tax positions were immaterial for each of the years in the three-year period ended December 31, 2013 . The total amount of unrecognized tax benefits that would affect the effective tax rate, if recognized, was $0.1 million as of December 31, 2013 and $0.2 million as of December 31, 2012 . As of December 31, 2013, we expect a decrease in the unrecognized tax benefit in the next twelve months due to the expiration of the relevant statute of limitations. During 2013, we reduced our liability for any uncertain tax benefits, of which the remaining balance is related to our state tax filings, due to the expiration of the relevant statute of limitations. The statute of limitations for most of our state tax jurisdictions is open from 2009 forward. +In accordance with the CAP program, the IRS completed its “post filing review” of our 2011 tax return in January 2013 and they are currently completing their “post filing review” of our 2012 tax return. We have been issued a “no change” letter for both of the reviewed tax years. The CAP audit employs a real-time review of our books and tax records by the IRS that is intended to permit issue resolution prior to, or shortly after, the filing of the tax returns. We are currently participating in the CAP program for the review of our 2013 tax year and we have been invited and have accepted continued participation in the program for our 2014 tax year. Participation in the CAP program has enabled us +71 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +to currently have no uncertain tax benefits associated with our federal tax return filings. During 2011, we reduced our liability for uncertain tax benefits by $0.8 million due to the accelerated examination and settlement of our 2007-2009 tax years upon entering the CAP program. +As of December 31, 2013, we were current with our income tax filings in all applicable state jurisdictions. In 2013, the State of Colorado examined our 2008 through 2011 Colorado Corporate Income Tax Returns and proposed no adjustments. +NOTE 8 - LONG-TERM DEBT +Long-term debt consists of the following: +As of December 31, +2013 +2012 +(in thousands) +Senior notes: +3.25% Convertible senior notes due 2016: +Principal amount +$ +115,000 +$ +115,000 +Unamortized discount +(10,010 +) +(13,671 +) +3.25% Convertible senior notes due 2016, net of discount +104,990 +101,329 +7.75% Senior notes due 2022: +7.75% Senior notes due 2022 +500,000 +500,000 +Total senior notes +604,990 +601,329 +Credit facilities: +Corporate +— +49,000 +PDCM +37,000 +26,250 +Total credit facilities +37,000 +75,250 +PDCM second lien term loan +15,000 +— +Long-term debt +$ +656,990 +$ +676,579 +Senior Notes +3.25% Convertible Senior Notes Due 2016. In November 2010 , we issued $115 million aggregate principal amount 3.25% convertible senior notes due 2016 (the "Convertible Notes") in a private placement to qualified institutional buyers. The maturity for the payment of principal is May 15, 2016 . Interest is payable semi-annually in arrears on each May 15 and November 15 . The Convertible Notes are senior, unsecured obligations and rank senior in right of payment to our existing and future indebtedness that is expressly subordinated in right of payment to the Convertible Notes; equal in right of payment to our existing and future unsecured indebtedness that is not expressly subordinated (including our 2022 Senior Notes); effectively junior in right of payment to any of our secured indebtedness (including our obligations under our senior secured credit facility) to the extent of the value of the assets securing such indebtedness; and structurally junior to all existing and future indebtedness (including trade payables) incurred by our subsidiaries. The indenture governing the convertible notes does not contain any restrictive financial covenants. The Convertible Notes and the common stock issuable upon conversion of the Convertible Notes, if any, have not been registered under the Securities Act of 1933 or any state securities laws, nor are we required to register such convertible notes or common shares. The Convertible Notes are governed by an indenture between the Company and the Bank of New York Mellon, as trustee. +We may not redeem the Convertible Notes prior to their maturity. However, prior to November 15, 2015 , holders of the Convertible Notes may convert upon specified events as defined in the governing indenture. The notes are convertible at any time thereafter at an initial conversion rate of 23.5849 shares per $1,000 principal amount, which is equal to a conversion price of approximately $42.40 per share. The conversion rate is subject to adjustment upon certain events. Upon conversion, the Convertible Notes may be settled, at our election, in shares of our common stock, cash or a combination of cash and shares of our common stock. We have initially elected a net-settlement method to satisfy our conversion obligation, which allows us to settle the principal amount of the Convertible Notes in cash and to settle the excess conversion value in shares, as well as cash in lieu of fractional shares. +We allocated the gross proceeds of the Convertible Notes between the liability and equity components of the debt. The initial $94.3 million liability component was determined based on the fair value of similar debt instruments with similar terms, excluding the conversion feature, and priced on the same day we issued our Convertible Notes. The initial $20.7 million equity component represents the debt discount and was calculated as the difference between the liability component of the debt and the gross proceeds of the convertible notes. As of December 31, 2013 , the unamortized debt discount will be amortized over the remaining contractual term to maturity of the convertible notes of 2.4 years using an effective interest rate of 7.4% . For 2013 , interest expense related to the indebtedness and the amortization of the discount was $3.7 million each compared to $3.7 million and $3.4 million , respectively, in 2012 and $3.7 million and $3.2 million , respectively, in 2011 . As of December 31, 2013 , notwithstanding the inability to convert, the “if-converted” value of the Convertible Notes exceeded the principal amount by approximately $29.3 million . +72 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +7.75% Senior Notes Due 2022. In October 2012 , we issued $500 million aggregate principal amount 7.75% senior notes due October 15, 2022 (the "2022 Senior Notes") in a private placement to qualified institutional investors. The 2022 Senior Notes accrue interest from the date of issuance and interest is payable semi-annually in arrears on April 15 and October 15 . Approximately $11 million in costs associated with the issuance of the 2022 Senior Notes have been capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes using the effective interest method. The 2022 Senior Notes are senior unsecured obligations and rank senior in right of payment to any of our future indebtedness that is expressly subordinated to the notes. The 2022 Senior Notes rank equally in right of payment with all our existing and future senior indebtedness (including our Convertible Notes) and rank effectively junior in right of payment to all of our secured indebtedness (to the extent of the value of the collateral securing such indebtedness), including borrowings under our revolving credit facility. +In connection with the issuance of the 2022 Senior Notes, we entered into a registration rights agreement with the initial purchasers in which we agreed to file a registration statement with the SEC related to an offer to exchange the notes for substantially identical registered notes and to use commercially reasonable efforts to cause the exchange offer to be completed on or prior to September 28, 2013. The registration statement was declared effective by the SEC in July 2013 and the exchange offer was completed in August 2013. +At any time prior to October 15, 2017 , we may redeem all or part of the 2022 Senior Notes at a make-whole price set forth in the indenture, and on or after October 15, 2017 , we may redeem the notes at fixed redemption prices, plus accrued and unpaid interest, if any, to the date of redemption. +At any time prior to October 15, 2015 , we may redeem up to 35% of the outstanding 2022 Senior Notes with proceeds from certain equity offerings at a redemption price of 107.75% of the principal amount of the notes redeemed, plus accrued and unpaid interest, as long as: +• +at least 65% of the aggregate principal amount of the notes issued on October 3, 2012 remains outstanding after each such redemption; and +• +the redemption occurs within 180 days after the closing of the equity offering. +Upon the occurrence of a "change of control" as defined in the indenture for the 2022 Senior Notes, holders will have the right to require us to repurchase all or a portion of the notes at a price equal to 101% of the aggregate principal amount of the notes repurchased, together with any accrued and unpaid interest to the date of purchase. In connection with certain asset sales, we will be required to use the net cash proceeds of the asset sale to make an offer to purchase the notes at 100% of the principal amount, together with any accrued and unpaid interest to the date of purchase. +The indenture governing the 2022 Senior Notes contains covenants that, among other things, limit our ability and the ability of our subsidiaries to incur additional indebtedness; pay dividends or make distributions on our stock; purchase or redeem stock or subordinated indebtedness; make certain investments; create certain liens; restrict dividends or other payments by restricted subsidiaries; enter into transactions with affiliates; sell assets; and merge or consolidate with another company. +As of December 31, 2013 , we were in compliance with all covenants related to the Convertible Notes and the 2022 Senior Notes, and expect to remain in compliance throughout the next twelve-month period. +Credit Facilities +Revolving Credit Facility . In May 2013 , we entered into a Third Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A. as administrative agent and other lenders party thereto. This agreement amends and restates the credit agreement dated November 2010 and expires in May 2018 . The revolving credit facility is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes and to support letters of credit. The revolving credit facility provides for a maximum of $1 billion in allowable borrowing capacity, subject to the borrowing base. As of December 31, 2013 , the borrowing base was $450 million . The borrowing base is based on, among other things, the loan value assigned to the proved reserves attributable to our and our subsidiaries' crude oil and natural gas interests, excluding proved reserves attributable to PDCM and our affiliated partnerships. The borrowing base is subject to a semi-annual size redetermination based upon quantification of our reserves at June 30 and December 31, and is also subject to a redetermination upon the occurrence of certain events. On October 31, 2013, we completed the semi-annual redetermination of our borrowing base and the borrowing base was reaffirmed at $450 million . The revolving credit facility is secured by a pledge of the stock of certain of our subsidiaries, mortgages of certain producing crude oil and natural gas properties and substantially all of our and such subsidiaries' other assets. Neither PDCM nor our affiliated partnerships are guarantors of our obligations under the revolving credit facility. As of December 31, 2013 , we had no outstanding draws on our revolving credit facility compared to $49.0 million at a weighted-average interest rate of 2.3% as of December 31, 2012 . +The outstanding principal amount under the revolving credit facility accrues interest at a varying interest rate that fluctuates with an alternate base rate (equal to the greater of JPMorgan Chase Bank, N.A.'s prime rate, the federal funds rate plus a premium and 1-month LIBOR plus a premium), or at our election, a rate equal to the rate for dollar deposits in the London interbank market for certain time periods. Additionally, commitment fees, interest margin and other bank fees, charged as a component of interest, vary with our utilization of the facility. No principal payments are required until the credit agreement expires in May 2018 , or in the event that the borrowing base falls below the outstanding balance. +The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests on a quarterly basis. The financial tests, as defined per the revolving credit facility, include requirements to: (a) maintain a minimum current +73 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +ratio of 1.00 to 1.00 and (b) not exceed a maximum leverage ratio of 4.25 to 1.00. As of December 31, 2013 , we were in compliance with all the revolving credit facility covenants and expect to remain in compliance throughout the next twelve-month period. +The revolving credit facility contains restrictions as to when we can directly or indirectly, retire, redeem, repurchase or prepay in cash any part of the principal of the 2022 Senior Notes or the Convertible Notes. Among other things, the restriction on redemption of the Convertible Notes requires that immediately after giving effect to any such retirement, redemption, defeasance, repurchase, settlement or prepayment, the aggregate commitment under the revolving credit facility exceed the aggregate credit exposure under such facility by at least the greater of $115 million or an amount equal to or greater than 30% of such aggregate commitment. The restriction on redemption of the 2022 Senior Notes permits redemption only with the proceeds of issuances of "Permitted Refinancing Indebtedness," which may not exceed $750 million. +As of December 31, 2013 , RNG, a wholly owned subsidiary of PDC, had an approximately $11.7 million irrevocable standby letter of credit in favor of a third-party transportation service provider to secure firm transportation of the natural gas produced by third-party producers for whom we market production in the Appalachian Basin. The letter of credit reduces the amount of available funds under our revolving credit facility by an equal amount. The letter of credit expires in September 2014. As of December 31, 2013 , the available funds under our revolving credit facility, including a reduction for the $11.7 million irrevocable standby letter of credit in effect, was $438.3 million . +PDCM Credit Facility. PDCM has a credit facility dated April 2010 , as amended in May 2013 , with a borrowing base of $105 million , of which our proportionate share is approximately $53 million . The maximum allowable facility amount is $400 million . No principal payments are required until the credit agreement expires in April 2017 , or in the event that the borrowing base falls below the outstanding balance. The credit facility is subject to and secured by PDCM's properties, including our proportionate share of such properties. The borrowing base is subject to size redetermination semi-annually based upon a valuation of PDCM's reserves at June 30 and December 31. Either PDCM or the lenders may request a redetermination upon the occurrence of certain events. The credit facility is utilized by PDCM for the exploration and development of its Appalachia-Marcellus Shale assets. +The credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests that must be met on a quarterly basis. The financial tests, as defined by the credit facility, include requirements to maintain a minimum current ratio of 1.0 to 1.0, not to exceed a debt to EBITDAX ratio of 4.25 to 1.0 (declining to 4.0 to 1.0 on July 1, 2014) and to maintain a minimum interest coverage ratio of 2.5 to 1.0. As of December 31, 2013 , our proportionate share of PDCM's outstanding credit facility balance was $37.0 million compared to $26.3 million as of December 31, 2012 . The weighted-average borrowing rate on PDCM's credit facility was 3.7% per annum as of December 31, 2013 , compared to 3.5% as of December 31, 2012 . +As of December 31, 2013 , PDCM was in compliance with all credit facility covenants and expects to remain in compliance throughout the next twelve-month period. +PDCM Second Lien Term Loan +In July 2013 , PDCM entered into a Second Lien Credit Agreement ("Term Loan Agreement") with Wells Fargo Energy Capital as administrative agent and a syndicate of other lenders party thereto. The aggregate commitment under the Term Loan Agreement is $30 million , of which our proportionate share is $15 million . The aggregate commitment may increase periodically up to a maximum of $75 million , as PDCM's reserve value increases and the covenants under the Term Loan Agreement allow. The Term Loan Agreement matures in October 2017 . Amounts borrowed accrue interest, at PDCM's discretion, at either an alternative base rate plus a margin of 6% per annum or an adjusted LIBOR for the interest period in effect plus a margin of 7% per annum. As of December 31, 2013 , amounts borrowed and outstanding on the Term Loan Agreement were $30 million , of which our proportionate share is $15 million . The weighted-average borrowing rate on the Term Loan was 8.5% per annum as of December 31, 2013 . +The Term Loan Agreement contains financial covenants that must be met on a quarterly basis, including requirements to maintain a minimum current ratio of 1.0 to 1.0, not to exceed a debt to EBITDAX ratio of 4.5 to 1.0, to maintain a minimum interest coverage ratio of 2.25 to 1.0 and a present value of future net revenues to total debt ratio of 1.50 to 1.00. As of December 31, 2013 , PDCM was in compliance with all Term Loan Agreement covenants and expects to remain in compliance throughout the next twelve-month period. +74 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 9 - ASSET RETIREMENT OBLIGATIONS +The following table presents the changes in carrying amounts of the asset retirement obligations associated with our working interest in crude oil and natural gas properties: +2013 +2012 +(in thousands) +Balance at beginning of year, January 1 +$ +62,563 +$ +46,566 +Obligations incurred with development activities and assumed with acquisitions +2,389 +14,169 +Accretion expense +4,747 +4,060 +Revisions in estimated cash flows +612 +— +Obligations discharged with divestitures of properties and asset retirements (1) +(29,281 +) +(2,232 +) +Balance end of year, December 31 +41,030 +62,563 +Less: Liabilities held for sale (1) +(2,061 +) +— +Less: Current portion +(1,158 +) +(1,000 +) +Long-term portion +$ +37,811 +$ +61,563 +______________ +(1) +Represents asset retirement obligations related to assets sold and assets held for sale. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information. +NOTE 10 - EMPLOYEE BENEFIT PLANS +We sponsor a qualified retirement plan covering substantially all of our employees. The plan consists of both a traditional and a Roth 401(k) component, as well as a profit sharing component. The 401(k) components enable eligible employees to contribute a portion of their compensation through payroll deductions in accordance with specific guidelines. We provide a discretionary matching contribution based on a percentage of the employees' contributions up to certain limits. Our contribution to the profit sharing component is discretionary. Our total combined expense for the plan was $3.7 million , $3.4 million and $2.6 million for 2013 , 2012 and 2011 , respectively. +We provide a supplemental retirement benefit of deferred compensation under terms of the various employment agreements with certain former executive officers. Expenses related to this plan are charged to general and administrative expenses and the related costs were immaterial in 2013 , 2012 and 2011 . As of December 31, 2013 and 2012 , the liability related to this benefit was $1.8 million and $2.0 million , respectively, which was included in other liabilities on the consolidated balance sheets, with the exception of $0.3 million included in other accrued expenses as of December 31, 2013 and 2012 . +We provide a supplemental health care benefit covering certain former executive officers and their spouses in accordance with each officer's employment agreement. Expenses incurred during 2013 , 2012 and 2011 related to this plan were immaterial. As of December 31, 2013 and 2012 , the related liability of $0.7 million is included in other liabilities on the consolidated balance sheets. +We maintain a non-qualified deferred compensation plan for our non-employee directors. The amount of compensation deferred by each participant is based on participant elections. The amounts deferred pursuant to the plan are invested in our common stock, maintained in a rabbi trust and are classified in the consolidated balance sheets as treasury shares as a component of shareholders' equity. The plan may be settled in either cash or shares as requested by the participant. The liability related to this plan, which was included in other liabilities on the consolidated balance sheets, was immaterial as of December 31, 2013 and 2012 . +NOTE 11 - COMMITMENTS AND CONTINGENCIES +Firm Transportation, Processing and Sales Agreements. We enter into contracts that provide firm transportation, sales and processing charges on pipeline systems through which we transport or sell natural gas. Satisfaction of the volume requirements includes volumes produced by us, volumes purchased from third parties and volumes produced by PDCM, our affiliated partnerships and other third-party working interest owners. We record in our financial statements only our share of costs based upon our working interest in the wells. These contracts require us to pay these transportation and processing charges whether the required volumes are delivered or not. With the exception of contracts entered into by PDCM, the costs of any volume shortfalls are borne by PDC. +75 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents gross volume information, including our proportionate share of PDCM, related to our long-term firm transportation, sales and processing agreements for pipeline capacity: +Year Ending December 31, +Area +2014 +2015 +2016 +2017 +2018 and +Through +Expiration +Total +Expiration +Date +Volume (MMcf) +Appalachia-Marcellus Shale +18,212 +19,485 +21,044 +20,987 +125,336 +205,064 +January 31, 2026 +Utica Shale +2,454 +2,738 +2,745 +2,737 +15,285 +25,959 +July 22, 2023 +Total +20,666 +22,223 +23,789 +23,724 +140,621 +231,023 +Dollar commitment (in thousands) +$ +7,547 +$ +7,907 +$ +8,230 +$ +7,790 +$ +38,526 +$ +70,000 +In March 2013, we entered into long-term agreements with a subsidiary of MarkWest Energy Partners, LP to provide midstream services, including gas gathering, processing, fractionation and marketing, to support our northern Utica Shale operations. The primary term of the agreements commenced in July 2013 when our natural gas began to flow into the gathering system. The gas processing agreement includes minimum volume commitments as shown in the table above, with certain fees assessed for any shortfall. +Litigation. The Company is involved in various legal proceedings that it considers normal to its business. The Company reviews the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in the best interests of the Company. There is no assurance that settlements can be reached on acceptable terms or that adverse judgments, if any, in the remaining litigation will not exceed the amounts reserved. Although the results cannot be known with certainty, we currently believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position, results of operations or liquidity. +Alleged Class Action Regarding 2010 and 2011 Partnership Purchases +In December 2011, the Company and its wholly-owned merger subsidiary were served with an alleged class action on behalf of certain former partnership unit holders, related to its partnership repurchases completed by mergers in 2010 and 2011. The action was filed in U.S. District Court for the Central District of California and is titled Schulein v. Petroleum Development Corp . The complaint primarily alleges that the disclosures in the proxy statements issued in connection with the mergers were inadequate, and a state law breach of fiduciary duty. In June 2012, the Court denied the Company's motion to dismiss. In January 2014, the plaintiffs were conditionally certified as a class by the court. Jury trial is scheduled for May 2014. We have not recorded a liability for claims pending because we believe we have good legal defenses to the asserted claims and it is not possible for management to reasonably estimate monetary damages resulting from this claim. +Environmental. Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures to avoid environmental contamination and mitigate the risks from environmental contamination. We conduct periodic reviews to identify changes in our environmental risk profile. Liabilities are recorded when environmental damages resulting from past events are probable and the costs can be reasonably estimated. As of December 31, 2013 and December 31, 2012 , we had accrued environmental liabilities in the amount of $5.4 million and $8.4 million , respectively, included in other accrued expenses on the consolidated balance sheet. We are not aware of any environmental claims existing as of December 31, 2013 which have not been provided for or would otherwise have a material impact on our financial statements. However, there can be no assurance that current regulatory requirements will not change or unknown past non-compliance with environmental laws will not be discovered on our properties. +Lease Agreements. We entered into operating leases, principally for the leasing of natural gas compressors, office space and general office equipment. +The following table presents the minimum future lease payments under the non-cancelable operating leases as of December 31, 2013 : +Year Ending December 31, +2014 +2015 +2016 +2017 +2018 +Thereafter +Total +(in thousands) +Minimum Lease Payments +$ +2,427 +$ +1,970 +$ +471 +$ +257 +$ +34 +$ +941 +$ +6,100 +Operating lease expense for the years ended 2013 , 2012 and 2011 was $7 million , $6.1 million and $5.9 million , respectively. +76 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Employment Agreements with Executive Officers . Each of our senior executive officers may be entitled to a severance payment and certain other benefits upon the termination of the officer's employment pursuant to the officer's employment agreement and/or the Company's executive severance compensation plan. The nature and amount of such benefits would vary based upon, among other things, whether the termination followed a change of control of the Company. +See Note 16, Transactions With Affiliates , for a discussion related to the separation agreement entered into with our former chief executive officer in 2011. +NOTE 12 - COMMON STOCK +Sale of Equity Securities +In August 2013 , we completed a public offering of 5,175,000 shares of our common stock, par value $0.01 per share, at a price to us of $53.37 per share. Net proceeds of the offering were approximately $275.8 million , after deducting offering expenses and underwriting discounts, of which $51,750 is included in common shares-par value and approximately $275.8 million is included in APIC on the consolidated balance sheet. The shares were issued pursuant to an effective shelf registration statement on Form S-3 filed with the SEC in January 2012. +In May 2012 , we completed a public offering of 6,500,000 shares of our common stock at an offering price of $26.50 per share. Net proceeds of the offering were approximately $164.5 million , after deducting underwriting discounts and commissions and offering expenses, of which $65,000 is included in common shares-par value and $164.4 million is included in APIC on the consolidated balance sheet. The shares were issued pursuant to an effective shelf registration statement on Form S-3 filed with the SEC in January 2012. +Stock-Based Compensation Plans +2010 Long-Term Equity Compensation Plan . In June 2010 , our shareholders approved a long-term equity compensation plan for our employees and non-employee directors (the "2010 Plan"). The plan was amended in June 2013. In accordance with the 2010 Plan, up to 3,000,000 new shares of our common stock are authorized for issuance. Shares issued may be either authorized but unissued shares, treasury shares or any combination of these shares. Additionally, the 2010 Plan permits the reuse or reissuance of shares of common stock which were canceled, expired, forfeited or, in the case of stock appreciation rights ("SARs"), paid out in the form of cash. Awards may be issued to our employees in the form of incentive or non-qualified stock options, SARs, restricted stock, restricted stock units ("RSUs"), performance shares and performance units, and to our non-employee directors in the form of non-qualified stock options, SARs, restricted stock and RSUs. Awards may vest over periods set at the discretion of the Compensation Committee of our Board of Directors (the "Compensation Committee") with certain minimum vesting periods. With regard to incentive or non-qualified stock options and SARs, awards have a maximum exercisable period of ten years. In no event may an award be granted under the 2010 Plan on or after April 1, 2020. As of December 31, 2013 , 1,708,107 shares remain available for issuance pursuant to the 2010 Plan. +2004 Long-Term Equity Compensation Plan. As approved by the shareholders in June 2004, we maintain a long-term equity compensation plan for our officers and certain key employees (the "2004 Plan"). Awards pursuant to the plan vest over periods set at the discretion of the Compensation Committee and, with regard to options, have a maximum exercisable period of ten years. We no longer issue awards pursuant to the 2004 Plan. As of December 31, 2013 , all awards granted pursuant to the 2004 Plan had vested and are exercisable through April 19, 2020. +77 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table provides a summary of the impact of our outstanding stock-based compensation plans on the results of operations for the periods presented: +Year Ended December 31, +2013 +2012 +2011(1) +(in thousands) +Stock-based compensation expense +$ +12,880 +$ +8,495 +$ +8,781 +Income tax benefit +(4,697 +) +(3,245 +) +(3,344 +) +Net stock-based compensation expense +$ +8,183 +$ +5,250 +$ +5,437 +__________ +(1) Includes a $2.5 million pre-tax charge related to a separation agreement with our former chief executive officer. See Note 16, Transactions with Affiliates, for additional information regarding the related separation agreement. +Stock Option Awards +We have granted stock options pursuant to various stock compensation plans. Outstanding options expire ten years from the date of grant and become exercisable ratably over a four year period. We have not issued any new stock option awards since 2006. As of December 31, 2013 , all compensation cost related to stock options has been fully recognized in our consolidated statements of operations. +The following table presents the changes in our stock option awards. The aggregate intrinsic value of options outstanding for each period presented was immaterial: +Year Ended December 31, +2013 +2012 +2011 +Number of +Shares +Underlying +Options +Weighted-Average +Exercise +Price +Per Share +Weighted- Average +Remaining +Contractual +Term (in years) +Aggregate Intrinsic +Value (in thousands) +Number of +Shares +Underlying +Options +Weighted-Average +Exercise +Price +Per Share +Number of +Shares +Underlying +Options +Weighted-Average +Exercise +Price +Per Share +Outstanding beginning of year, January 1, +6,973 +$ +41.09 +2.6 +$ +— +6,973 +$ +41.09 +10,306 +$ +41.90 +Exercised +(3,450 +) +37.15 +— +77 +— +— +— +— +Forfeited +— +— +— +— +— +— +(3,333 +) +43.60 +Outstanding end of year, December 31, +3,523 +44.95 +2.2 +29 +6,973 +41.09 +6,973 +41.09 +Exercisable at December 31, +3,523 +44.95 +2.2 +29 +6,973 +41.09 +6,973 +41.09 +SARs +The SARs vest ratably over a three-year period and may be exercised at any point after vesting through 10 years from the date of issuance. Pursuant to the terms of the awards, upon exercise, the executive officers will receive, in shares of common stock, the excess of the market price of the award on the date of exercise over the market price of the award on the date of issuance. +In January 2013 , the Compensation Committee awarded 87,078 SARs to our executive officers. The fair value of each SAR award was estimated on the date of grant using a Black-Scholes pricing model using the following assumptions: +Year Ended December 31, +2013 +2012 +2011 +Expected term of award +6 years +6 years +6 years +Risk-free interest rate +1.0 +% +1.1 +% +2.5 +% +Expected volatility +65.5 +% +64.3 +% +60.2 +% +Weighted-average grant date fair value per share +$ +21.96 +$ +17.61 +$ +25.22 +The expected life of the award was estimated using historical stock option exercise behavior data. The risk-free interest rate was based on the U.S. Treasury yields approximating the expected life of the award in effect at the time of grant. Expected volatilities were based on our historical volatility. We do not expect to pay or declare dividends in the foreseeable future. +78 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the changes in our SARs: +Year Ended December 31, +2013 +2012 +2011 +Number of +SARs +Weighted-Average +Exercise +Price +Average Remaining Contractual +Term (in years) +Aggregate Intrinsic +Value (in thousands) +Number of +SARs +Weighted-Average +Exercise +Price +Aggregate Intrinsic +Value (in thousands) +Number of +SARs +Weighted-Average +Exercise +Price +Aggregate Intrinsic +Value (in thousands) +Outstanding beginning of year, January 1, +118,832 +$ +30.80 +8.4 +$ +486 +50,471 +$ +31.61 +$ +341 +57,282 +$ +24.44 +$ +1,020 +Awarded +87,078 +37.18 +— +— +68,361 +30.19 +— +31,552 +43.95 +— +Exercised +(15,147 +) +30.06 +— +425 +— +— +— +(25,371 +) +24.44 +77 +Forfeited +— +— +— +— +— +— +— +(12,992 +) +43.95 +— +Outstanding at December 31, +190,763 +33.77 +8.2 +3,711 +118,832 +30.80 +486 +50,471 +31.61 +341 +Exercisable at December 31, +51,922 +29.97 +7.1 +1,207 +27,458 +28.84 +187 +10,636 +24.44 +114 +Total compensation cost related to SARs granted, net of estimated forfeitures, and not yet recognized in our consolidated statement of operations as of December 31, 2013 , was $1.7 million . The cost is expected to be recognized over a weighted-average period of 1.8 years. +Restricted Stock Awards +Time-Based Awards. The fair value of the time-based restricted shares is amortized ratably over the requisite service period, primarily three or four years. The time-based shares vest ratably on each annual anniversary following the grant date that a participant is continuously employed. +In January 2013 , the Compensation Committee awarded a total of 103,050 time-based restricted shares to our executive officers that vest ratably over the three year period ending on January 16, 2016. +The following table presents the changes in non-vested time-based awards during 2013 : +Shares +Weighted-Average +Grant-Date +Fair Value +Non-vested at December 31, 2012 +646,490 +$ +27.93 +Granted +311,051 +45.53 +Vested +(282,787 +) +27.57 +Forfeited +(22,973 +) +31.52 +Non-vested at December 31, 2013 +651,781 +36.36 +As of/Year Ended December 31, +2013 +2012 +2011 +(in thousands, except per share data) +Total intrinsic value of time-based awards vested +$ +13,640 +$ +5,950 +$ +9,030 +Total intrinsic value of time-based awards non-vested +34,688 +21,470 +18,531 +Market price per common share as of December 31, +53.22 +33.21 +35.11 +Weighted-average grant date fair value per share +45.53 +26.59 +33.71 +Total compensation cost related to non-vested time-based awards, net of estimated forfeitures, and not yet recognized in our consolidated statements of operations as of December 31, 2013 was $15.7 million . This cost is expected to be recognized over a weighted-average period of 2.0 years. +Market-Based Awards. The fair value of the market-based restricted shares is amortized ratably over the requisite service period, primarily three years. The market-based shares vest if the participant is continuously employed throughout the performance period and the market-based performance measure is achieved, with a maximum vesting period of five years. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. +79 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +In January 2013 , the Compensation Committee awarded a total of 41,570 market-based restricted shares to our executive officers. In addition to continuous employment, the vesting of these shares is contingent on the Company's total shareholder return ("TSR"), which is essentially the Company’s stock price change including any dividends, as compared to the TSR of a set group of 15 peer companies. The shares are measured over a three-year period ending on December 31, 2014 and can result in a payout between 0% and 200% of the total shares awarded. The weighted-average grant date fair value per market-based share for these awards granted was computed using the Monte Carlo pricing model using the following assumptions: +Year Ended December 31, +2013 +2012 +Expected term of award +3 years +3 years +Risk-free interest rate +0.4 +% +0.3 +% +Expected volatility +56.6 +% +65.3 +% +Weighted-average grant date fair value per share +$ +49.04 +$ +36.54 +The expected term of the awards was based on the requisite service period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant and extrapolated to approximate the life of the award. The expected volatility was based on our historical volatility. +The following table presents the change in non-vested market-based awards during 2013 : +Shares +Weighted-Average +Grant-Date +Fair Value per Share +Non-vested at December 31, 2012 +40,696 +$ +39.22 +Granted +41,570 +49.04 +Vested +(10,155 +) +47.28 +Non-vested at December 31, 2013 +72,111 +43.75 +As of/Year Ended December 31, +2013 +2012 +2011 +(in thousands, except per share data) +Total intrinsic value of market-based awards vested +$ +724 +$ +— +$ +366 +Total intrinsic value of market-based awards non-vested +3,838 +1,352 +1,513 +Market price per common share as of December 31, +53.22 +33.21 +35.11 +Weighted-average grant date fair value per share +49.04 +36.54 +58.53 +Total compensation cost related to non-vested market-based awards, net of estimated forfeitures, and not yet recognized in our consolidated statement of operations as of December 31, 2013 was $1.7 million . This cost is expected to be recognized over a weighted-average period of 1.8 years. +Treasury Share Purchases +In accordance with our stock-based compensation plans, employees and directors may surrender shares of the Company's common stock to pay tax withholding obligations upon the vesting and exercise of share-based awards. Shares acquired that had been issued pursuant to the 2004 Plan are retired, while those issued pursuant to the 2010 Plan are reissued to service awards. For shares that are retired, we first charge any excess of cost over the par value to APIC to the extent we have amounts in APIC, with any remaining excess cost charged to retained earnings. For shares reissued to service awards under the 2010 Plan, shares are recorded at cost and upon reissuance we reduce the carrying value of shares acquired and held pursuant to the 2010 Plan by the weighted-average cost per share with an offsetting charge to APIC. During the year ended December 31, 2013 , we acquired 84,642 shares pursuant to our stock-based compensation plans for payment of tax liabilities, of which 17,257 shares were retired, 67,334 shares were reissued and 51 shares are available for reissuance pursuant to our 2010 Plan. +80 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Shareholders’ Rights Agreement +In 2007, we entered into a rights agreement. The rights agreement is designed to improve the ability of our Board to protect the interest of our shareholders in the event of an unsolicited takeover attempt. Our Board declared a dividend of one right for each outstanding share of our common stock. The right dividend was paid to shareholders of record in September 2007 . A "distribution date," as defined in the rights agreement, can occur after any individual shareholder exceeds 15% ownership of our outstanding common stock. In certain circumstances, the right entitles each holder, other than an "acquiring person" (as defined in the agreement), to purchase shares of our common stock (or, in certain circumstances, cash, property or other securities) having a then-current value equal to two times the exercise price of the right (i.e., for the $240 exercise price, the rights holder receives $480 worth of common stock). The exercise price is subject to adjustment for various corporate actions which affect all shareholders, such as a stock split. The rights agreement and all rights will expire in September 2017 . +Preferred stock +We are authorized, pursuant to shareholder approval in 2008 , to issue 50,000,000 shares of preferred stock, par value $0.01, which may be issued in one or more series, with such rights, preferences, privileges and restrictions as shall be fixed by our Board from time to time. As of December 31, 2013 , no preferred shares had been issued. +NOTE 13 - EARNINGS PER SHARE +Basic earnings per share is computed by dividing net earnings by the weighted-average number of common shares outstanding for the period. Diluted earnings per share is similarly computed except that the denominator includes the effect, using the treasury stock method, of unvested restricted stock, outstanding SARs, stock options, convertible notes and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive. +The following table presents a reconciliation of the weighted-average diluted shares outstanding: +Year Ended December 31, +2013 +2012 +2011 +(in thousands) +Weighted-average common shares outstanding - basic +32,426 +27,677 +23,521 +Dilutive effect of: +Restricted stock +— +— +307 +SARs +— +— +40 +Non-employee director deferred compensation +— +— +3 +Weighted-average common shares and equivalents outstanding - diluted +32,426 +27,677 +23,871 +For 2013 and 2012 , we reported a net loss. As a result, our basic and diluted weighted-average common shares outstanding were the same as the effect of the common share equivalents was anti-dilutive. +The following table presents the weighted-average common share equivalents excluded from the calculation of diluted earnings per share due to their anti-dilutive effect: +Year Ended December 31, +2013 +2012 +2011 +(in thousands) +Weighted-average common share equivalents excluded from diluted earnings +per share due to their anti-dilutive effect: +Restricted stock +823 +694 +220 +SARs +72 +116 +22 +Stock options +7 +7 +9 +Non-employee director deferred compensation +4 +3 +— +Convertible notes +518 +— +— +Total anti-dilutive common share equivalents +1,424 +820 +251 +In November 2010, we issued our Convertible Notes, which give the holders the right to convert the aggregate principal amount into 2.7 million shares of our common stock at a conversion price of $42.40 per share. The Convertible Notes could be included in the dilutive earnings per share calculation using the treasury stock method if the average market share price exceeds the $42.40 conversion price during the +81 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +period presented. Shares issuable upon conversion of the Convertible Notes were excluded from the diluted earnings per share calculation for the year ended December 31, 2013 as the effect would be anti-dilutive to our earnings per share. Shares issuable upon conversion of the Convertible Notes were excluded from the diluted earnings per share calculation for the year ended December 31, 2012 and 2011 as the conversion price was greater than the average market price of our common stock during the period. +NOTE 14 - ASSETS HELD FOR SALE, DIVESTITURES AND DISCONTINUED OPERATIONS +The tables below set forth selected financial information related to net assets divested and operating results related to discontinued operations. Net assets held for sale represents the assets that were or are expected to be sold, net of liabilities, that were or are expected to be assumed by the purchaser. While the reclassification of revenues and expenses related to discontinued operations for prior periods had no impact upon previously reported net earnings, the consolidated statement of operations table presents the revenues and expenses that were reclassified from the specified consolidated statement of operations line items to discontinued operations. +The following table presents consolidated balance sheet data related to net assets held for sale: +Consolidated balance sheet +As of December 31, 2013 +(In thousands) +Assets +Properties and equipment, net +$ +2,785 +Liabilities +Asset retirement obligation +2,061 +Net Assets +$ +724 +The following table presents consolidated statement of operations data related to our discontinued operations: +Year Ended December 31, +Consolidated statements of operations - discontinued operations +2013 +2012 +2011 +(in thousands) +Revenues +Crude oil, natural gas and NGLs sales +$ +20,398 +$ +36,422 +$ +80,860 +Sales from natural gas marketing +2,825 +1,708 +2,949 +Well operations, pipeline income and other +890 +1,888 +2,542 +Total revenues +24,113 +40,018 +86,351 +Costs, expenses and other +Production costs +7,975 +22,453 +30,885 +Cost of natural gas marketing +2,673 +1,529 +2,634 +Impairment of crude oil and natural gas properties +3 +162,254 +22,858 +Depreciation, depletion and amortization +2,258 +48,101 +47,521 +Other +2,528 +2,084 +1,054 +(Gain) loss on sale of properties and equipment +2,330 +(19,920 +) +(3,854 +) +Total costs, expenses and other +17,767 +216,501 +101,098 +Income (loss) from discontinued operations +6,346 +(176,483 +) +(14,747 +) +Provision for income taxes +(2,175 +) +67,466 +5,620 +Income (loss) from discontinued operations, net of tax +$ +4,171 +$ +(109,017 +) +$ +(9,127 +) +Appalachian Basin. In October 2013, we executed a purchase and sale agreement for the sale of our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin crude oil and natural gas properties owned directly by us, as well as through our proportionate share of PDCM. The properties consisted of approximately 3,500 gross shallow producing wells, related facilities and associated leasehold acreage, limited to the Upper Devonian and shallower formations. Substantially all of the divestiture closed in December 2013 for aggregate consideration of approximately $20.6 million , of which our share of the proceeds was approximately $5.1 million , subject to certain post-closing adjustments. We received our proportionate share of cash proceeds of $0.9 million and recorded our proportionate share of a note receivable and account receivable from the buyer of $3.3 million and $0.8 million , respectively. The remaining assets and related liabilities were classified as held for sale in the consolidated balance sheet as of December 31, 2013. Concurrent with the closing of the transaction, our $6.7 million irrevocable standby letter of credit and an agreement for firm transportation services was released and novated to the buyer. We retained all zones, formations +82 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +and intervals below the Upper Devonian formation including the Marcellus Shale, Utica Shale and Huron Shale. The divestiture of these assets did not meet the requirements to be accounted for as discontinued operations. +Piceance Basin and NECO. In February 2013, we entered into a purchase and sale agreement pursuant to which we agreed to sell to Caerus our Piceance Basin, NECO and certain other non-core Colorado oil and gas properties, leasehold mineral interests and related assets. Additionally, certain firm transportation obligations and natural gas hedging positions were assumed by the buyer. In June 2013, this divestiture was completed with total consideration of approximately $177.6 million , with an additional $17.0 million paid to our non-affiliated investor partners in our affiliated partnerships. The sale resulted in a pre-tax loss of $2.3 million . The proceeds from the asset divestiture were used to pay down our revolving credit facility and to fund a portion of our 2013 capital budget. Following the sale to Caerus, we do not have significant continuing involvement in the operations of, or cash flows from, the Piceance Basin and NECO oil and gas properties. Accordingly, the results of operations related to these assets have been separately reported as discontinued operations in the consolidated statement of operations for all periods presented. The sale of our other non-core Colorado oil and gas properties did not meet the requirements to be accounted for as discontinued operations. +Permian Basin. During the fourth quarter of 2011, we completed the sale of our non-core Permian assets to unrelated third parties for a total of $13.2 million . Additionally, on December 20, 2011, we executed a purchase and sale agreement with COG, a wholly owned subsidiary of Concho Resources Inc., for the sale of our core Permian Basin assets for a sale price of $173.9 million , subject to certain post-closing adjustments. The effective date of the transaction was November 1, 2011. Following the sale to COG, we do not have significant continuing involvement in the operations of, or cash flows from, these assets; accordingly, the Permian assets were reclassified as held for sale as of December 31, 2011, and the results of operations related to those assets have been separately reported as discontinued operations in the 2012 and 2011 consolidated statements of operations. On February 28, 2012, the divestiture closed. After final post-closing adjustments, total proceeds received were $189.2 million , resulting in a pre-tax gain on sale of $19.9 million . +NOTE 15 - ACQUISITIONS +The following table presents the adjusted purchase price and the allocations thereof, based on our estimates of fair value, for the acquisition of crude oil and natural gas properties during 2012 and 2011 : +Year Ended December 31, +2012 +2011 +Merit +Seneca-Upshur +2003/2002-D Partnerships +2005 Partnerships +(in thousands) +Total acquisition cost +$ +304,643 +$ +69,618 +$ +29,960 +$ +43,015 +Recognized amounts of identifiable assets acquired and liabilities assumed: +Assets acquired: +Crude oil and natural gas properties - proved +$ +180,696 +$ +20,175 +$ +27,940 +$ +39,825 +Crude oil and natural gas properties - unproved +151,428 +49,100 +— +— +Other assets +3,631 +10,196 +3,455 +3,848 +Total assets acquired +335,755 +79,471 +31,395 +43,673 +Liabilities assumed: +Asset retirement obligation +14,833 +8,157 +497 +300 +Other accrued expenses +9,574 +— +— +— +Other liabilities +6,705 +1,696 +938 +358 +Total liabilities assumed +31,112 +9,853 +1,435 +658 +Total identifiable net assets acquired +$ +304,643 +$ +69,618 +$ +29,960 +$ +43,015 +The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows and a market-based weighted-average cost of capital rate. These inputs require significant judgments and estimates by management at the time of the valuation and are sensitive and subject to change. +83 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +2012 Acquisitions +Merit Acquisition. In June 2012 , we completed the acquisition of certain Wattenberg Field oil and natural gas properties, leasehold mineral interests and related assets located in Weld, Adams and Boulder Counties, Colorado from affiliates of Merit Energy. The aggregate purchase price of these properties was approximately $304.6 million . We financed the purchase with cash from the May 2012 offering of our common stock and a draw on our revolving credit facility. +This acquisition was accounted for under the acquisition method of accounting. Accordingly, we conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition were expensed as incurred. +Pro Forma Information. The results of operations for the Merit Acquisition have been included in our consolidated financial statements since the June 2012 closing date. The following unaudited pro forma financial information presents a summary of the consolidated results of operations for the years ended December 31, 2012 and December 31, 2011, assuming the Merit Acquisition had been completed as of January 1, 2011, including adjustments to reflect the values assigned to the net assets acquired. The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if the Merit Acquisition had been effective as of these dates, or of future results. +Year Ended December 31, +2012 +2011 +(in thousands, except per share amounts) +Total revenues +$ +370,488 +$ +438,204 +Total costs, expenses and other +521,178 +366,120 +Net income (loss) +$ +(119,343 +) +$ +45,688 +Earnings per share: +Basic +$ +(4.31 +) +$ +1.94 +Diluted +$ +(4.31 +) +$ +1.91 +2011 Acquisitions +Seneca-Upshur . In October 2011, PDCM acquired 100% of the membership interests of Seneca-Upshur for $139.2 million ( $69.6 million net to PDC), after post-closing adjustments, which was funded by capital contributions by PDCM's investing partners and a draw on PDCM's revolving credit facility. Substantially all of the acreage acquired is held by production, prospective for the Marcellus Shale and is in close proximity to PDCM's existing properties. PDCM received title defect payments during 2012 totaling $28.9 million , of which $14.5 million represents our share, the effect of which is reflected in the purchase price noted above. +2003/2002-D Partnerships . In October 2011, we acquired from non-affiliated investor partners the interests we did not already own in five of our affiliated partnerships: PDC 2002-D Limited Partnership, PDC 2003-A Limited Partnership, PDC 2003-B Limited Partnership and PDC 2003-C Limited Partnership (the "2002/2003 Partnerships"). We purchased the 2002/2003 Partnerships for an aggregate amount of $30 million , which was funded from our revolving credit facility. These purchases included the partnerships' working interests in wells located in the Wattenberg Field and Piceance Basin. +2005 Partnerships . In June 2011, we acquired from non-affiliated investor partners the interests we did not already own in three of our affiliated partnerships: PDC 2005-A Limited Partnership, PDC 2005-B Limited Partnership and Rockies Region Private Limited Partnership (the "2005 Partnerships"). We purchased the 2005 Partnerships for an aggregate amount of $43 million , which was funded from our revolving credit facility. These purchases included the partnerships' working interests wells located in the Wattenberg Field and the Piceance Basin. +Pro Forma Information . The results of operations for the Seneca-Upshur, 2002/2003 Partnerships and 2005 Partnerships acquisitions have been included in our consolidated financial statements from the respective dates of acquisition. Pro forma information is not presented as the pro forma results would not be materially different from the information presented in the accompanying consolidated statements of operations. +NOTE 16 - TRANSACTIONS WITH AFFILIATES +PDCM and Affiliated Partnerships. Our Gas Marketing segment markets the natural gas produced by PDCM and our affiliated partnerships in the Appalachia-Marcellus Shale. Our cost of natural gas marketing includes $18.1 million , $10.9 million and $9.5 million in 2013 , 2012 and 2011 , respectively, related to the marketing of natural gas on behalf of PDCM and $1.3 million , $0.5 million and $1.3 million , respectively, related to the marketing of natural gas on behalf of our affiliated partnerships. +84 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Amounts due from/to the affiliated partnerships have historically been primarily related to derivative positions and, to a lesser extent, unbilled well lease operating expenses, and costs resulting from audit and tax preparation services. Previously, we have entered into derivative instruments on behalf of our affiliated partnerships for their estimated production. In June 2013, all remaining derivative positions designated to our affiliated partnerships were liquidated prior to settlement. As a result, there were no amounts due from/to our affiliated partnerships related to derivative positions as of December 31, 2013 . +We provide certain well operating and administrative services for PDCM. Amounts billed to PDCM for these services were $14.5 million , $12.1 million and $10.4 million in 2013 , 2012 and 2011 , respectively. Our consolidated statements of operations include only our proportionate share of these billings. The following table presents the consolidated statement of operations line item in which our proportionate share is recorded and the amount for each of the periods presented. +Year Ended December 31, +Consolidated statement of operations line item +2013 +2012 +2011 +(in thousands) +Production costs +$ +4,097 +$ +3,945 +$ +3,441 +Exploration expense +502 +492 +430 +General and administrative expense +2,649 +1,630 +1,543 +Former Executive Officer. In June 2011, Richard W. McCullough resigned from his positions as our Chief Executive Officer and the Chairman of the Board, effective immediately. In connection with his resignation, in July 2011, Mr. McCullough and the Company executed a separation agreement, whereby Mr. McCullough received those benefits to which he was entitled pursuant to his employment agreement, including without limitation, separation compensation in the amount of $4.1 million , less required withholdings, his annual non-qualified deferred supplemental retirement benefit equal to $30,000 for each of the years 2012 through 2021 (not accelerated), less required withholdings, continued coverage under the Company’s group health plans at the Company’s cost for a period equal to the lesser of 18 months or such period ending as of the date Mr. McCullough is eligible to participate in another employer’s group health plan, immediate vesting of any unvested Company stock options, SARs and restricted stock and issuance of shares representing the vested portion of his 2009 performance share awards. Related to this separation agreement, the consolidated statement of operations for 2011 reflects a charge to general and administrative expense of $6.7 million . +NOTE 17 - BUSINESS SEGMENTS +We separate our operating activities into two segments: Oil and Gas Exploration and Production and Gas Marketing. All material inter-company accounts and transactions between segments have been eliminated. +Oil and Gas Exploration and Production. Our Oil and Gas Exploration and Production segment includes all of our crude oil and natural gas properties. The segment represents revenues and expenses from the production and sale of crude oil, natural gas and NGLs. Segment revenue includes crude oil, natural gas and NGLs sales, commodity price risk management, net, and well operation and pipeline income. Segment income (loss) consists of segment revenue less production cost, exploration expense, impairment of crude oil and natural gas properties, direct general and administrative expense and DD&A expense. Segment DD&A expense was $122.2 million , $94.1 million and $83.6 million in 2013 , 2012 and 2011 , respectively. +Gas Marketing. Our Gas Marketing segment purchases, aggregates and resells natural gas produced by us and others. Segment income (loss) primarily represents sales from natural gas marketing and direct interest income less costs of natural gas marketing and direct general and administrative expense. +Unallocated amounts. Unallocated income includes unallocated other revenue, less corporate general administrative expense, corporate DD&A expense, interest income and interest expense. Unallocated assets include assets utilized for corporate, general and administrative purposes, as well as assets not specifically included in our two business segments. +85 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following tables present our segment information: +2013 +2012 +2011 +(in thousands) +Year Ended December 31, +Segment revenues: +Oil and gas exploration and production +$ +341,527 +$ +275,234 +$ +273,819 +Gas marketing +69,787 +45,371 +63,470 +Total revenues +$ +411,314 +$ +320,605 +$ +337,289 +Segment income (loss) before income taxes: +Oil and gas exploration and production +$ +79,527 +$ +103,111 +$ +138,616 +Gas marketing +(298 +) +349 +639 +Unallocated +(120,498 +) +(137,856 +) +(104,891 +) +Income (loss) before income taxes +$ +(41,269 +) +$ +(34,396 +) +$ +34,364 +Expenditures for segment long-lived assets: +Oil and gas exploration and production +$ +403,227 +$ +656,443 +$ +479,027 +Unallocated +1,379 +3,509 +1,363 +Total +$ +404,606 +$ +659,952 +$ +480,390 +As of December 31, +Segment assets: +Oil and gas exploration and production +$ +1,934,466 +$ +1,723,011 +Gas marketing +20,342 +11,090 +Unallocated +67,610 +92,747 +Assets held for sale +2,785 +— +Total assets +$ +2,025,203 +$ +1,826,848 +86 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +SUPPLEMENTAL INFORMATION - UNAUDITED +CRUDE OIL AND NATURAL GAS INFORMATION - UNAUDITED +Net Proved Reserves +All of our crude oil, natural gas and NGLs reserves are located in the U.S. We utilize the services of independent petroleum engineers to estimate our crude oil, natural gas, condensate and NGL reserves. As of December 31, 2013 , 2012 and 2011 , all of our reserve estimates were based on reserve reports prepared by Ryder Scott. These reserve estimates have been prepared in compliance with professional standards and the reserves definitions prescribed by the SEC. +Proved reserves estimates may change, either positively or negatively, as additional information becomes available and as contractual, economic and political conditions change. Our net proved reserve estimates have been adjusted as necessary to reflect all contractual agreements, royalty obligations and interests owned by others at the time of the estimate. Proved developed reserves are the quantities of crude oil, natural gas and NGLs expected to be recovered through existing wells with existing equipment and operating methods. In some cases, proved undeveloped reserves may require substantial new investments in additional wells and related facilities. +The price used to estimate our reserves, by commodity, are presented below. +Price Used to Estimate Reserves +As of December 31, +Crude Oil +(per Bbl) +Natural Gas +(per Mcf) +NGLs +(per Bbl) +2013 +$ +82.18 +$ +3.22 +$ +29.92 +2012 +87.51 +2.35 +28.02 +2011 +88.94 +3.41 +39.59 +87 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +The following tables present the changes in our estimated quantities of proved reserves: +Crude Oil, Condensate (MBbls) +Natural Gas +(MMcf) +NGLs +(MBbls) +Total +(MBoe) +Proved Reserves: +Proved reserves, January 1, 2011 +23,236 +657,306 +10,649 +143,436 +Revisions of previous estimates +(1,904 +) +(161,654 +) +3,163 +(25,683 +) +Extensions, discoveries and other additions +17,092 +176,689 +5,633 +52,173 +Purchases of reserves +1,605 +32,761 +1,052 +8,117 +Dispositions +(435 +) +(2,070 +) +(94 +) +(874 +) +Production +(1,958 +) +(30,887 +) +(815 +) +(7,921 +) +Proved reserves, December 31, 2011 (1) +37,636 +672,145 +19,588 +169,248 +Revisions of previous estimates +(6,729 +) +(289,436 +) +(3,671 +) +(58,639 +) +Extensions, discoveries and other additions +27,482 +172,933 +11,637 +67,941 +Purchases of reserves +10,801 +87,212 +8,084 +33,420 +Dispositions +(7,854 +) +(6,406 +) +(1,970 +) +(10,891 +) +Production +(2,026 +) +(32,410 +) +(841 +) +(8,269 +) +Proved reserves, December 31, 2012 (2) +59,310 +604,038 +32,827 +192,810 +Revisions of previous estimates +(18,420 +) +(117,068 +) +(8,549 +) +(46,480 +) +Extensions, discoveries and other additions +55,759 +365,563 +25,249 +141,935 +Purchases of reserves +343 +2,894 +217 +1,043 +Dispositions +(252 +) +(94,927 +) +(30 +) +(16,104 +) +Production +(2,910 +) +(20,860 +) +(1,043 +) +(7,430 +) +Proved reserves, December 31, 2013 +93,830 +739,640 +48,671 +265,774 +Proved Developed Reserves, as of: +January 1, 2011 +8,287 +227,341 +4,013 +50,190 +December 31, 2011 (1) +16,910 +299,369 +11,753 +78,558 +December 31, 2012 (2) +20,412 +281,925 +14,353 +81,753 +December 31, 2013 +23,997 +220,387 +14,825 +75,553 +Proved Undeveloped Reserves, as of: +January 1, 2011 +14,949 +429,965 +6,636 +93,246 +December 31, 2011 (1) +20,726 +372,776 +7,835 +90,690 +December 31, 2012 (2) +38,898 +322,113 +18,474 +111,058 +December 31, 2013 +69,833 +519,253 +33,846 +190,221 +__________ +(1) +Includes estimated reserve data related to our Permian Basin assets, which were divested in February 2012. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional details related to the divestiture of our Permian Basin assets. Total proved reserves included 7,825 MBbls of crude oil, 6,242 MMcf of natural gas and 1,970 MBbls of NGLs, for an aggregate of 10,835 Mboe of crude oil equivalent, related to our Permian asset group. Total proved developed reserves related to those assets included 1,815 MBbls, 1,750 MMcf, 550 MBbls and 2,657 MBoe, respectively, and proved undeveloped reserves included 6,010 MBbls, 4,492 MMcf, 1,420 MBbls and 8,179 MBoe, respectively. +(2) +Includes estimated reserve data related to our Piceance and NECO assets, which were divested in June 2013. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional details related to the divestiture of our Piceance and NECO assets. Total proved reserves include 148 MBbls of crude oil and 83,656 MMcf of natural gas, for an aggregate of 14,091 MBoe of crude oil equivalent related to our Piceance and NECO assets. There were no proved undeveloped reserves attributable to the Piceance and NECO assets as of December 31, 2012. +88 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +Developed +Undeveloped +Total +(MBoe) +Beginning proved reserves, January 1, 2012 +78,558 +90,690 +169,248 +Undeveloped reserves converted to developed +7,655 +(7,655 +) +— +Revisions of previous estimates +(18,318 +) +(40,321 +) +(58,639 +) +Extensions, discoveries and other additions +11,298 +56,643 +67,941 +Purchases of reserves +13,542 +19,878 +33,420 +Dispositions +(2,713 +) +(8,178 +) +(10,891 +) +Production +(8,269 +) +— +(8,269 +) +Ending proved reserves, December 31, 2012 +81,753 +111,057 +192,810 +Undeveloped reserves converted to developed +3,212 +(3,212 +) +— +Revisions of previous estimates +(6,751 +) +(39,729 +) +(46,480 +) +Extensions, discoveries and other additions +19,830 +122,105 +141,935 +Purchases of reserves +1,043 +— +1,043 +Dispositions +(16,104 +) +— +(16,104 +) +Production +(7,430 +) +— +(7,430 +) +Ending proved reserves, December 31, 2013 +75,553 +190,221 +265,774 +2013 Activity. Overall, our proved reserves increased by 73 MMBoe as of December 31, 2013 as compared to December 31, 2012. In 2013, we recorded a downward revision of our previous estimate of proved reserves of approximately 46 MMBoe. The revision was primarily due to a decrease of approximately 55 MMBoe of which approximately 32 MMBoe is due to adjustments in previous PUD well spacing plans in the Wattenberg Field and the Marcellus Shale, which were offset by replacements in the extension category, approximately 9 MMBoe is due to expired leases, approximately 11 MMBoe is due to our shift from vertical to horizontal drilling in the Wattenberg Field and approximately 3 MMBoe is to remove Wattenberg Field PUDs that are no longer in our core drilling area. This was partially offset by an increase of 1 MMBoe due to higher gas pricing and lower operating costs in the vertical Wattenberg Field wells and horizontal Marcellus Shale wells, an increase of approximately 3 MMBoe due to non-acquisition interest adjustments, approximately 2 MMBoe due to asset performance and approximately 2 MMBoe due to production from wells that were either uneconomic, added or divested in the current year. Discoveries and extensions of approximately 142 MMBoe in 2013 are due to the addition of approximately 17 MMBoe of proved developed reserves from non-PUD drilling and the addition of approximately 125 MMBoe of new proved undeveloped reserves including 32 MMBoe due to adjustments in well spacing in the Wattenberg Field and the Marcellus Shale. Approximately 18 MMBoe was added in the Marcellus Shale, approximately 14 MMBoe was added in the Utica Shale and approximately 110 MMBoe was added in the Wattenberg Field, mostly related to the Niobrara and Codell formations. We acquired approximately 1 MMBoe of proved reserves due to an acquisition in the Appalachian-Marcellus Shale area and the acquisition of non-affiliated investor partner interests in shallow Upper Devonian wells. We divested a total of 16 MMBoe in 2013, primarily our Piceance Basin, NECO and shallow Upper Devonian (non-Marcellus Shale) assets. Based on the economic conditions on December 31, 2013, our approved development plan provides for the development of our remaining PUD reserves within five years of the date such reserves were initially recorded. Our 2013 drilling program focused on locations that were not included in proved undeveloped reserves in the December 31, 2012 reserve report due to increased well density testing in the Wattenberg Field. The success of this increased well density testing allowed us to add considerable PUD reserves in the 2013 reserve report. Because we will continue to drill both proven and non-proven downspaced Wattenberg Field locations in 2014, our PUD conversion rate is expected to be approximately 7.4% . The balance of the locations are scheduled to be drilled over the remaining four years with total PUD conversion rates of 22% in 2015, 27% in 2016, 24% in 2017 and 19% in 2018. This level of capital spending is consistent with the most recent years and our guidance for future activity. +2012 Activity. In 2012, we recorded a downward revision of our previous estimate of proved reserves of approximately 59 MMBoe. The revision was primarily due to a decrease of approximately 40 MMBoe due to lower gas pricing, mostly related to the Piceance Basin, approximately 1 MMBoe due to increased operating costs, approximately 8 MMBoe due to adjustments for geological reasons and approximately 13 MMBoe due to the removal of certain proved undeveloped reserves to comply with the SEC's five-year rule. This was partially offset by an increase of approximately 0.5 MMBoe due to non-acquisition interest adjustments and approximately 2 MMBoe due to asset performance. Discoveries and extensions of approximately 68 MMBoe in 2012 are due to the drilling of 44 gross horizontal wells and the addition of new proved undeveloped reserves. Approximately 10 MMBoe were added in the Marcellus Shale and approximately 59 MMBoe were added in the Wattenberg Field, mostly related to the Niobrara formation. We acquired approximately 33 MMBoe of proved reserves due to an acquisition in the Wattenberg Field. We divested a total of 11 MMBoe in 2012, primarily our core Permian Basin assets. Based on the economic conditions on December 31, 2012, our approved development plan provided for the development of our remaining PUD reserves within five years of the date such reserves were initially recorded. Based on our decision to drill predominantly horizontal wells in 2012, our drilling program focused on locations that were not included in proved undeveloped reserves in the December 2011 reserve report. By focusing on non-PUD drilling locations in 2012, we were able to add considerable PUD reserves in the 2012 reserve report. +2011 Activity. In 2011, we recorded a downward revision of our previous estimate of proved reserves of approximately 26 MMBoe. The revision was primarily due to a decrease of approximately 0.7 MMBoe due to lower gas pricing and approximately 29 MMBoe due to the removal of certain proved undeveloped reserves to comply with the SEC's five-year rule. This was partially offset by an increase of approximately +89 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +1 MMBoe due to increased efficiencies in operating costs, approximately 0.8 MMBoe due to non-acquisition interest adjustments and approximately 2 MMBoe due to asset performance. In addition, the “Revisions of previous estimates” line item includes a deduction in the “Undeveloped” column and an increase in the “Developed” column of approximately 21 MMBoe. These reserves were transferred from proved undeveloped to proved developed as a result of the Company's determination that costs related to a refracture became less significant as compared to the costs associated with drilling a new well. Discoveries and extensions of approximately 52 MMboe in 2012 are due to the drilling of 195 gross wells and the addition of new proved undeveloped reserves. Approximately 9 MMBoe were added in the Marcellus Shale, approximately 24 MMBoe in the Wattenberg Field, 13 MMBoe in the Piceance Basin and 7 MMBoe in the Permian Basin. We acquired approximately 8 MMboe of proved reserves, approximately 1 MMBoe through acquisitions in the Marcellus Shale, approximately 5 MMBoe in the Wattenberg Field and 2 MMBoe in the Piceance Basin due to the repurchase of the 2003/2002-D and 2005 Partnerships as well as the purchase of interests in some of our other existing properties. We divested a total of approximately 0.8 MMBoe in 2012 . This included the sale of 100% of our North Dakota assets, or 0.3 MMBoe, to an unrelated third-party and our non-core Permian Basin assets, or 0.5 MMBoe, to unrelated third parties. +Results of Operations for Crude Oil and Natural Gas Producing Activities +The results of operations for crude oil and natural gas producing activities are presented below. The results include activities related to both continuing and discontinued operations and exclude activities related to natural gas marketing and well operations and pipeline services. +Year Ended December 31, +2013 +2012 +2011 +(in thousands) +Revenue: +Crude oil, natural gas and NGLs sales +$ +379,796 +$ +274,783 +$ +304,157 +Commodity price risk management gain, net +(23,905 +) +32,339 +46,090 +355,891 +307,122 +350,247 +Expenses: +Production costs +81,365 +77,537 +75,717 +Exploration expense +7,071 +22,605 +6,289 +Impairment of proved crude oil and natural gas properties +53,438 +162,287 +25,159 +Depreciation, depletion, and amortization +124,202 +146,879 +128,458 +Accretion of asset retirement obligations +4,747 +4,060 +1,897 +(Gain) loss on sale of properties and equipment +3,722 +(24,273 +) +(4,050 +) +274,545 +389,095 +233,470 +Results of operations for crude oil and natural gas producing +activities before provision for income taxes +81,346 +(81,973 +) +116,777 +Provision for income taxes +(29,400 +) +31,163 +(36,785 +) +Results of operations for crude oil and natural gas producing activities, excluding corporate overhead and interest costs +$ +51,946 +$ +(50,810 +) +$ +79,992 +Production costs include those costs incurred to operate and maintain productive wells and related equipment, including costs such as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance, production and severance taxes and associated administrative expenses. DD&A expense includes those costs associated with capitalized acquisition, exploration and development costs, but does not include the depreciation applicable to support equipment. The provision for income taxes is computed using effective tax rates. +90 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +Costs Incurred in Crude Oil and Natural Gas Property Acquisition, Exploration and Development Activities +Costs incurred in crude oil and natural gas property acquisition, exploration and development are presented below. +Year Ended December 31, +2013 +2012 +2011 +(in thousands) +Acquisition of properties: (1) +Proved properties +$ +28,698 +$ +105,303 +$ +79,554 +Unproved properties +3,390 +276,225 +95,081 +Development costs (2) +332,250 +233,144 +301,008 +Exploration costs: (3) +Exploratory drilling +58,988 +18,803 +3,626 +Geological and geophysical +752 +1,925 +1,846 +Total costs incurred +$ +424,078 +$ +635,400 +$ +481,115 +__________ +(1) +Property acquisition costs represent costs incurred to purchase, lease or otherwise acquire a property. +(2) +Development costs represent costs incurred to gain access to and prepare development well locations for drilling, drill and equip development wells, recomplete wells and provide facilities to extract, treat, gather and store crude oil, natural gas and NGLs. Of these costs incurred for the years ended December 31, 2013 , 2012 and 2011 , $40.1 million , $62.0 million and $80.6 million , respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end. +(3) +Exploration costs - represents costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing crude oil, natural gas and NGLs. +Capitalized Costs Related to Crude Oil and Natural Gas Producing Activities +Aggregate capitalized costs related to crude oil and natural gas exploration and production activities with applicable accumulated DD&A are presented below: +As of December 31, +2013 +2012 +(in thousands) +Proved crude oil and natural gas properties +$ +1,781,681 +$ +2,075,924 +Unproved crude oil and natural gas properties +307,203 +319,327 +Uncompleted wells, equipment and facilities +51,773 +62,392 +Capitalized costs +2,140,657 +2,457,643 +Less accumulated DD&A +(529,607 +) +(905,458 +) +Capitalized costs, net +$ +1,611,050 +$ +1,552,185 +Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves +The standardized measure below has been prepared in accordance with U.S. GAAP. Future estimated cash flows were based on a 12-month average price calculated as the unweighted arithmetic average of the prices on the first day of each month, January through December, applied to our year-end estimated proved reserves. Prices for each of the three years were adjusted by field for Btu content, transportation and regional price differences; however, they were not adjusted to reflect the value of our commodity derivatives. Production and development costs were based on prices as of December 31 for each of the respective years presented. The amounts shown do not give effect to non-property related expenses, such as corporate general and administrative expenses, debt service or to depreciation, depletion and amortization expense. Production and development costs include those cash flows associated with the expected ultimate settlement of our asset retirement obligation. Future estimated income tax expense is computed by applying the statutory rate in effect at the end of each year to the projected future pre-tax net cash flows, less the tax basis of the properties and gives effect to permanent differences, tax credits and allowances related to the properties. +The following table presents information with respect to the standardized measure of discounted future net cash flows relating to proved reserves. Changes in the demand for crude oil, natural gas and NGLs, inflation and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of our proved reserves. +91 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +As of December 31, +2013 +2012 +2011 +(in thousands) +Future estimated cash flows +$ +11,550,917 +$ +7,529,292 +$ +6,415,255 +Future estimated production costs +(2,329,836 +) +(1,690,453 +) +(1,704,645 +) +Future estimated development costs +(2,778,148 +) +(1,852,177 +) +(1,474,137 +) +Future estimated income tax expense +(2,119,615 +) +(1,230,294 +) +(946,849 +) +Future net cash flows +4,323,318 +2,756,368 +2,289,624 +10% annual discount for estimated timing of cash flows +(2,541,155 +) +(1,587,871 +) +(1,348,415 +) +Standardized measure of discounted future estimated net cash flows +$ +1,782,163 +$ +1,168,497 +$ +941,209 +The following table presents the principal sources of change in the standardized measure of discounted future estimated net cash flows: +Year Ended December 31, +2013 +2012 +2011 +(in thousands) +Sales of crude oil, natural gas and NGLs production, net of production costs +$ +(286,021 +) +$ +(194,346 +) +$ +(226,227 +) +Net changes in prices and production costs (1) +89,527 +95,501 +383,293 +Extensions, discoveries, and improved recovery, less related costs (2) +1,529,006 +632,781 +467,347 +Sales of reserves (3) +(142,724 +) +(86,902 +) +(4,224 +) +Purchases of reserves (4) +10,610 +296,208 +64,761 +Development costs incurred during the period +46,366 +69,198 +94,941 +Revisions of previous quantity estimates (5) +(397,738 +) +(452,775 +) +(112,468 +) +Changes in estimated income taxes (6) +(381,369 +) +(131,256 +) +(204,377 +) +Net changes in future development costs +(40,707 +) +(3,979 +) +(29,827 +) +Accretion of discount +142,040 +124,105 +65,284 +Timing and other +44,676 +(121,247 +) +(45,712 +) +Total +$ +613,666 +$ +227,288 +$ +452,791 +__________ +(1) +Our weighted-average p rice, net of production costs per Boe, in our 2013 reserve report increased to $24.24 as compared to $20.70 in our 2012 reserve report. This is due to the divestiture of our Piceance, NECO and our shallow Upper Devonian (non-Marcellus Shale) reserves during 2013 which further increased our liquids as a percentage of proved reserves. Despite the decrease in price for each of our commodities for 2012 compared to 2011, our weighted-average price, net of production costs per Boe, in our 2012 reserve report increased to $20.70 from $19.14 resulting from our increase in liquids as a percentage of total proved reserves. +(2) +The 142% increase in 2013 as compared to 2012 is primarily due to the additions of PUDs in the Utica Shale and our continued focus on our Wattenberg drilling program. Our increased PUD count in Wattenberg is a result of successful downspacing tests in 2013 leading to a scheduled maximum rig count of seven rigs by 2016 as compared to a scheduled maximum rig count of five in the 2012 year-end reserve report. The 35% increase in 2012 as compared to 2011 reflects a continuation of our shifting focus from gas-rich projects to liquid-rich projects. At December 31, 2012, extensions, discoveries and other additions had increased to 68 MMBoe, a 30% increase, 52.2% of which was gas and 47.8% was liquids. Approximately 86% of the 35% increase was related to the additional volume of PUD reserves in the Wattenberg Field that were proved up by our 2012 drilling program. +(3) +The increase in sales of reserves in 2013 as compared to 2012 was due to the divestiture of our Piceance and NECO assets in June 2013 and our shallow Upper Devonian (non-Marcellus Shale) assets in December of 2013. The increase in sales of reserves in 2012 as compared to 2011 was due to the divestiture of our core Permian assets on February 28, 2012. +(4) +The decrease in purchases of reserves in 2013 as compared to 2012 was due to no material acquisitions having occurred in 2013. The increase in purchases of reserves in 2012 as compared to 2011 was due to the Merit Acquisition in the liquids-rich Wattenberg Field. +(5) +The change in revisions of our previous quantity estimates in 2013 as compared to 2012 was primarily due to adjustment in our drilling schedule. The change in revisions of our previous quantity estimates in 2012 as compared to 2011 was primarily due to lower natural gas pricing, a decrease in proved undeveloped reserves pursuant to the SEC five-year rule and adjustments due to our drilling schedule. +(6) +The change in estimated income taxes for each year as compared to the prior year is the direct result of the significant increase in discounted future net cash flows, as the projected deferred tax rate remained relatively unchanged at approximately 38.0% , 38.2% and 38.1% for the years ended December 31, 2013, 2012 and 2011, respectively. In addition, the Company continued to capitaliz e and amortize the majority of its yearly capital expenditures and there were no changes in the assumptions as to the tax deductibility of beginning unamortized capital, additional current year capital or future development capital. +The data presented should not be viewed as representing the expected cash flows from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the recent average prices and current costs utilized in the computation of reported +92 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein. +93 +PDC ENERGY, INC. +QUARTERLY FINANCIAL INFORMATION - UNAUDITED +Quarterly financial data for the years ended December 31, 2013 and 2012 is presented below. The sum of the quarters may not equal the total of the year's net income or loss per share due to changes in the weighted-average shares outstanding throughout the year. +2013 +Quarter Ended +March 31 +June 30 +September 30 +December 31 +Year Ended +(in thousands, except per share data) +Revenues: +Crude oil, natural gas and NGLs sales +$ +79,439 +$ +77,537 +$ +82,136 +$ +120,286 +$ +359,398 +Sales from natural gas marketing +13,670 +18,079 +16,946 +21,092 +69,787 +Commodity price risk management gain (loss), net +(22,355 +) +24,724 +(23,638 +) +(2,636 +) +(23,905 +) +Well operations, pipeline income and other +1,072 +965 +1,672 +2,325 +6,034 +Total revenues +71,826 +121,305 +77,116 +141,067 +411,314 +Costs, expenses and other: +Production costs +15,858 +16,176 +19,057 +22,299 +73,390 +Cost of natural gas marketing +13,736 +18,065 +17,127 +21,156 +70,084 +Exploration expense +1,689 +1,437 +2,030 +1,883 +7,039 +Impairment of crude oil and natural gas properties +46,459 +1,502 +4,472 +1,002 +53,435 +General and administrative expense +15,115 +15,783 +16,080 +16,991 +63,969 +Depreciation, depletion and amortization +27,949 +27,800 +30,870 +40,641 +127,260 +Accretion of asset retirement obligations +1,148 +1,172 +1,186 +1,080 +4,586 +(Gain) loss on sale of properties and equipment +(38 +) +(9 +) +(712 +) +2,151 +1,392 +Total costs, expenses and other +121,916 +81,926 +90,110 +107,203 +401,155 +Income (loss) from operations +(50,090 +) +39,379 +(12,994 +) +33,864 +10,159 +Interest expense +(13,357 +) +(13,089 +) +(12,509 +) +(12,943 +) +(51,898 +) +Interest income +— +3 +130 +337 +470 +Income (loss) from continuing operations before income taxes +(63,447 +) +26,293 +(25,373 +) +21,258 +(41,269 +) +Provision for income taxes +22,492 +(9,791 +) +10,155 +(8,059 +) +14,797 +Income (loss) from continuing operations +(40,955 +) +16,502 +(15,218 +) +13,199 +(26,472 +) +Income (loss) from discontinued operations, net of tax +1,537 +3,416 +(782 +) +— +4,171 +Net income (loss) +$ +(39,418 +) +$ +19,918 +$ +(16,000 +) +$ +13,199 +$ +(22,301 +) +Earnings per share: +Basic +Income (loss) from continuing operations +$ +(1.35 +) +$ +0.55 +$ +(0.46 +) +$ +0.37 +$ +(0.82 +) +Income (loss) from discontinued operations +0.05 +0.11 +(0.02 +) +— +0.13 +Net income (loss) +$ +(1.30 +) +$ +0.66 +$ +(0.48 +) +$ +0.37 +$ +(0.69 +) +Diluted +Income (loss) from continuing operations +$ +(1.35 +) +$ +0.53 +$ +(0.46 +) +$ +0.36 +$ +(0.82 +) +Income (loss) from discontinued operations +0.05 +0.11 +(0.02 +) +— +0.13 +Net income (loss) +$ +(1.30 +) +$ +0.64 +$ +(0.48 +) +$ +0.36 +$ +(0.69 +) +Weighted-average common shares outstanding: +Basic +30,270 +30,332 +33,413 +35,620 +32,426 +Diluted +30,270 +31,014 +33,413 +36,836 +32,426 +94 +PDC ENERGY, INC. +2012 +Quarter Ended +March 31 +June 30 +September 30 +December 31 +Year Ended +(in thousands, except per share data) +Revenues: +Crude oil, natural gas and NGLs sales +$ +66,955 +$ +51,342 +$ +52,291 +$ +67,773 +$ +238,361 +Sales from natural gas marketing +11,381 +8,613 +11,178 +14,199 +45,371 +Commodity price risk management gain (loss), net +11,501 +38,729 +(31,943 +) +14,052 +32,339 +Well operations, pipeline income and other +1,169 +1,056 +1,194 +1,115 +4,534 +Total revenues +91,006 +99,740 +32,720 +97,139 +320,605 +Costs, expenses and other: +Production costs +12,936 +12,373 +15,797 +13,594 +54,700 +Cost of natural gas marketing +11,091 +8,490 +11,260 +14,182 +45,023 +Exploration expense +1,872 +2,374 +1,773 +14,875 +20,894 +Impairment of crude oil and natural gas properties +588 +356 +388 +4,563 +5,895 +General and administrative expense +14,708 +14,378 +13,710 +16,019 +58,815 +Depreciation, depletion and amortization +27,912 +23,839 +22,121 +24,906 +98,778 +Accretion of asset retirement obligations +727 +732 +1,101 +1,127 +3,687 +Gain on sale of properties and equipment +(154 +) +(2,246 +) +(1,508 +) +(445 +) +(4,353 +) +Total costs, expenses and other +69,680 +60,296 +64,642 +88,821 +283,439 +Income (loss) from operations +21,326 +39,444 +(31,922 +) +8,318 +37,166 +Loss on extinguishment of debt +— +— +— +(23,283 +) +(23,283 +) +Interest expense +(10,444 +) +(10,053 +) +(11,360 +) +(16,430 +) +(48,287 +) +Interest income +2 +— +3 +3 +8 +Income (loss) from continuing operations before income taxes +10,884 +29,391 +(43,279 +) +(31,392 +) +(34,396 +) +Provision for income taxes +(4,120 +) +(10,213 +) +15,268 +11,766 +12,701 +Income (loss) from continuing operations +6,764 +19,178 +(28,011 +) +(19,626 +) +(21,695 +) +Income (loss) from discontinued operations, net of tax +9,071 +(6,907 +) +(4,632 +) +(106,549 +) +(109,017 +) +Net income (loss) +$ +15,835 +$ +12,271 +$ +(32,643 +) +$ +(126,175 +) +$ +(130,712 +) +Earnings per share: +Basic +Income (loss) from continuing operations +$ +0.29 +$ +0.72 +$ +(0.93 +) +$ +(0.65 +) +$ +(0.78 +) +Income (loss) from discontinued operations +0.38 +(0.26 +) +(0.15 +) +(3.52 +) +(3.94 +) +Net income (loss) attributable to shareholders +$ +0.67 +$ +0.46 +$ +(1.08 +) +$ +(4.17 +) +$ +(4.72 +) +Diluted +Income (loss) from continuing operations +$ +0.28 +$ +0.72 +$ +(0.93 +) +$ +(0.65 +) +$ +(0.78 +) +Income (loss) from discontinued operations +0.38 +(0.26 +) +(0.15 +) +(3.52 +) +(3.94 +) +Net income (loss) attributable to shareholders +$ +0.66 +$ +0.46 +$ +(1.08 +) +$ +(4.17 +) +$ +(4.72 +) +Weighted-average common shares outstanding +Basic +23,609 +26,597 +30,214 +30,233 +27,677 +Diluted +23,889 +26,728 +30,214 +30,233 +27,677 +95 +PDC ENERGY, INC. +FINANCIAL STATEMENT SCHEDULE +Schedule II -VALUATION AND QUALIFYING ACCOUNTS +Description +Beginning +Balance +January 1 +Deconsolidation/Purchase Price Adjustment for PDCM +Charged to +Costs and +Expenses +Deductions (1) +Ending +Balance +December 31 +(in thousands) +2013: +Allowance for doubtful accounts +$ +1,026 +$ +— +$ +423 +$ +188 +$ +1,261 +Valuation allowance for unproved crude oil and natural gas properties +8,036 +— +3,964 +6,400 +5,600 +2012: +Allowance for doubtful accounts +921 +— +258 +153 +1,026 +Valuation allowance for unproved crude oil and natural gas properties +12,204 +— +4,207 +8,375 +8,036 +2011: +Allowance for doubtful accounts +686 +121 +135 +21 +921 +Valuation allowance for unproved crude oil and natural gas properties +16,996 +260 +2,611 +7,143 +12,204 +___ ____________ +(1) +For allowance for doubtful accounts, deductions represent the write-off of accounts receivable deemed uncollectible. For valuation allowance for unproved crude oil and natural gas properties, deductions represent accumulated amortization of expired or abandoned unproved crude oil and natural gas properties, with a corresponding decrease to the historical cost of the associated asset. +96 +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 +As of December 31, 2013 , we carried out an evaluation under the supervision and with the participation of 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 pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e). Based on the results of this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2013 . +Changes in Internal Control over Financial Reporting +During the fourth quarter of 2013 , we made no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) that have materially affected or are reasonably likely to materially affect our internal control over financial reporting. +ITEM 9B. OTHER INFORMATION +None. +97 +PART III +ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2014 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 11. EXECUTIVE COMPENSATION +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2014 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2014 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2014 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2014 Annual Stockholders' meeting and is incorporated by reference in this report. +PART IV +ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULE +(a) +(1) +Exhibits: +See Exhibits Index on the following page. +98 +Exhibits Index +Incorporated by Reference +Exhibit Number +Exhibit Description +Form +SEC File Number +Exhibit +Filing Date +Filed Herewith +3.1 +Third Amended and Restated Articles of Incorporation of PDC Energy, Inc. (the "Company") +10-Q +000-07246 +3.1 +8/2/2012 +3.2 +By-laws of the Company. +10-Q +000-07246 +3.2 +8/2/2012 +4.1 +Rights Agreement by and between the Company and Transfer Online, Inc., as Rights Agent, dated as of September 11, 2007, including the forms of Rights Certificates and Summary of Stockholder Rights Plan attached thereto as Exhibits A and B. +8-K +000-07246 +4.1 +9/17/2007 +4.2 +Indenture, dated November 23, 2010, between the Company and The Bank of New York Mellon, including the form of 3.25% Convertible Senior Note due 2016. +8-K +000-07246 +4.1 +11/24/2010 +4.3 +Indenture, dated as of October 3, 2012, by and between the Company and U.S. Bank Trust National Association, as Trustee, including the form of 7.75% Senior Notes due 2022. +8-K +000-07246 +4.1 +10/3/2012 +10.1* +Indemnification Agreement with Non-Employee Directors. +8-K +000-07246 +10.1 +6/13/2012 +10.2* +The Company 401(k) and Profit Sharing Plan. +10-K +000-07246 +10.6 +2/24/2011 +10.3* +Amended and Restated Non-Employee Director Deferred Compensation Plan. +X +10.4* +2004 Long-Term Equity Compensation Plan amended and restated as of March 8, 2008 ("2004 Plan"). +10-K +000-07246 +10.26 +2/27/2009 +10.4.1* +Summary of 2010 Stock Appreciation Rights and Restricted Stock Awards under the 2004 Plan. +8-K +000-07246 +4/23/2010 +10.5* +Amended and Restated 2010 Long-Term Equity Compensation Plan, dated June 6, 2013 +10-Q +000-07246 +10.4 +8/1/2013 +10.5.1* +Form of 2010 Performance Share Agreement. +8-K +000-07246 +10.1 +3/17/2011 +10.5.2* +Form of 2011 Restricted Stock/Stock Appreciation Rights Agreement. +X +10.5.3* +Form of 2012 Performance Share Agreement. +8-K +000-07246 +10.1 +1/20/2012 +10.5.4* +Form of 2013 Performance Share Agreement. +10-K +000-07246 +10.9 +2/27/2013 +10.5.5* +Form of 2013 Restricted Stock/Stock Appreciation Rights Agreement. +10-K +000-07246 +10.10 +2/27/2013 +10.6* +Executive Severance Compensation Plan. +8-K +000-07246 +10.2 +9/25/2012 +10.7* +Employment Agreement with Gysle R. Shellum, Chief Financial Officer, dated as of April 19, 2010. +8-K +000-07246 +10.2 +4/23/2010 +10.8* +Employment Agreement with Daniel W. Amidon, General Counsel and Corporate Secretary, dated as of April 19, 2010. +8-K +000-07246 +10.3 +4/23/2010 +10.9* +Employment Agreement with Lance A. Lauck, Senior Vice President of Business Development, dated as of April 19, 2010. +8-K +000-07246 +10.4 +4/23/2010 +10.10* +Employment Agreement with Barton R. Brookman, Jr., Senior Vice President of Exploration and Production, dated as of April 19, 2010. +8-K +000-07246 +10.5 +4/23/2010 +10.11 +Contribution Agreement by and among PDC Mountaineer, LLC, as the Company, Petroleum Development Corporation, as the Contributor, and LR-Mountaineer Holdings, L.P., as the Investor, dated October 29, 2009. +8-K +000-07246 +2.1 +11/4/2009 +10.12 +Second Amended and Restated Limited Liability Company Agreement of PDC Mountaineer, LLC, dated December 23, 2013. +X +99 +Incorporated by Reference +Exhibit Number +Exhibit Description +Form +SEC File Number +Exhibit +Filing Date +Filed Herewith +10.13 +Third Amended and Restated Credit Agreement dated as of May 21, 2013, among PDC Energy, Inc. as Borrower, Riley Natural Gas Company, a Subsidiary of PDC Energy, Inc., as Guarantor, JP Morgan Chase Bank, N.A. as Administrative Agent, J.P. Morgan Securities LLC as Sole Bookrunner and Co-Lead Arranger, Wells Fargo Bank, N.A. as Syndication Agent, and Wells Fargo Securities, LLC as Co-Lead Arranger, and Certain Lenders. +8-K +000-07246 +10.1 +5/28/2013 +10.14 +Purchase and Sale Agreement by and among the Company, affiliated partnerships and certain affiliates of Caerus Oil and Gas LLC, dated February 4, 2013. +8-K +000-07246 +10.1 +5/1/2013 +10.14.1 +Amendment No. 1 to Purchase and Sale Agreement, dated as of May 30, 2013, by and among the Company, certain affiliates of the Company, Caerus Operating LLC, Caerus Washco LLC and Caerus Piceance LLC. +8-K +000-07246 +10.1 +6/3/2013 +12.1 +Computation of Ratio of Earnings to Fixed Charges. +X +14.1 +Code of Business Conduct and Ethics. +10-Q +000-07246 +14.1 +8/10/2009 +21.1 +Subsidiaries. +X +23.1 +Consent of PricewaterhouseCoopers LLP. +X +23.2 +Consent of Ryder Scott Company, L.P., Petroleum Consultants. +X +31.1 +Certification by Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. +X +31.2 +Certification by Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. +X +32.1** +Certifications by Chief Executive Officer and Chief Financial Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002. +99.1 +Report of Independent Petroleum Consultants - Ryder Scott Company, L.P. +X +101.INS +XBRL Instance Document +X +101.SCH +XBRL Taxonomy Extension Schema Document +X +101.CAL +XBRL Taxonomy Extension Calculation Linkbase Document +X +101.DEF +XBRL Taxonomy Extension Definition Linkbase Document +X +101.LAB +XBRL Taxonomy Extension Label Linkbase Document +X +101.PRE +XBRL Taxonomy Extension Presentation Linkbase Document +X +*Management contract or compensatory plan or arrangement. +** Furnished herewith. +† Confidential portions of this document have been omitted and are filed separately with the SEC pursuant to Exchange Act Rule 24b-2. +100 +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. +PDC ENERGY, INC. +By: /s/ James M. Trimble +James M. Trimble +Chief Executive Officer and President +February 20, 2014 +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/ James M. Trimble +Chief Executive Officer, President and Director +February 20, 2014 +James M. Trimble +(principal executive officer) +/s/ Gysle R. Shellum +Chief Financial Officer +February 20, 2014 +Gysle R. Shellum +(principal financial officer) +/s/ R. Scott Meyers +Chief Accounting Officer +February 20, 2014 +R. Scott Meyers +(principal accounting officer) +/s/ Jeffrey C. Swoveland +Chairman and Director +February 20, 2014 +Jeffrey C. Swoveland +/s/ Joseph E. Casabona +Director +February 20, 2014 +Joseph E. Casabona +/s/ Anthony J. Crisafio +Director +February 20, 2014 +Anthony J. Crisafio +/s/ Larry F. Mazza +Director +February 20, 2014 +Larry F. Mazza +/s/ David C. Parke +Director +February 20, 2014 +David C. Parke +/s/ Kimberly Luff Wakim +Director +February 20, 2014 +Kimberly Luff Wakim +101 +GLOSSARY OF UNITS OF MEASUREMENT AND INDUSTRY TERMS +UNITS OF MEASUREMENT +The following presents a list of units of measurement used throughout the document. +Bbl – One barrel of crude oil or NGL or 42 gallons of liquid volume. +Bcf – One billion cubic feet of natural gas volume. +Boe – One barrel of crude oil equivalent. +Btu – British thermal unit. +BBtu – One billion British thermal units. +MBoe – One thousand barrels of crude oil equivalent. +MBbls – One thousand barrels of crude oil. +Mcf – One thousand cubic feet of natural gas volume. +MMBoe – One million barrels of crude oil equivalent. +MMBtu – One million British thermal units. +MMcf – One million cubic feet of natural gas volume. +GLOSSARY OF INDUSTRY TERMS +The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report: +Behind-pipe reserves - Crude oil and natural gas reserves expected to be recovered from zones in existing wells, which will require additional completion work or future recompletion prior to the start of production. Generally, these are reserves in reservoirs above currently producing zones. +CIG - Colorado Interstate Gas. +Completion - Refers to the work performed and the installation of permanent equipment for the production of crude oil and natural gas from a recently drilled well. +Crude oil well - A well whose reserves are expected to produce less than 15 Mcf of gas per barrel of crude oil. +Delineation - A drilling technique carried out to gain a better understanding of the structure and extent of a deposit in order to decide whether or not to conduct further drilling activities. +Developed acreage - Acreage assignable to productive wells. +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 gas or dry natural gas - Natural gas is considered dry when its composition is over 90% pure methane. +Dry well or dry hole - A well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion as an oil or gas well. +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 gas in another reservoir. +Extensions and discoveries - As to any period, the increases to proved reserves from all sources other than the acquisition of proved properties or revisions of previous estimates. +Farm-out - Transfer of all or part of the operating rights from a working interest owner to an assignee, who assumes all or some of the burden of development in return for an interest in the property. The assignor usually retains an overriding royalty interest but may retain any type of interest. +Fracture or Fracturing - Procedure to stimulate production by forcing a mixture of fluid and proppant into the formation under high pressure. Fracturing creates artificial fractures in the reservoir rock to increase permeability and porosity, thereby allowing the release of trapped hydrocarbons. +Gross acres or wells - Refers to the total acres or wells in which we have a working interest. +Horizontal drilling - A drilling technique that permits the operator to drill a horizontal well shaft from the bottom of a vertical well and thereby to contact and intersect a larger portion of the producing horizon than conventional vertical drilling techniques and may, depending on the horizon, result in increased production rates and greater ultimate recoveries of hydrocarbons. +102 +Joint interest billing - Process of billing/invoicing the costs related to well drilling, completions and production operations among working interest partners. +Natural gas liquid(s) or NGL(s) - Hydrocarbons which can be extracted from wet natural gas and become liquid under various combinations of increasing pressure and lower temperature. NGLs include ethane, propane, butane, and other natural gasolines. +Net acres or wells - Refers to gross acres or wells we own multiplied, in each case, by our percentage working interest. References to net acres or wells include our proportionate share of PDCM's and our affiliated partnerships' net acres or wells. +Net production - Crude oil and natural gas production that we own, less royalties and production due to others. References to net production include our proportionate share of PDCM's and our affiliated partnerships' net production. +Non-operated - A project in which we are not the operator. +NYMEX - New York Mercantile Exchange. +Operator - The individual or company responsible for the exploration, development and/or production of an oil or gas well or lease. +Overriding royalty - An interest which is created out of the operating or working interest. Its term is coextensive with that of the operating interest. +Possible reserves - This term is defined in the SEC Regulation S-X Section 4-10(a) and refers to those reserves that are less certain to be recovered than probable reserves. When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability to exceed the sum of proved, probable and possible reserves. When probabilistic methods are used, there must be at least a 10 percent probability that the actual quantities recovered will equal or exceed the sum of proved, probable and possible estimates. +Present value of future net revenues or (PV-10) - The present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, of proved reserves calculated in accordance with Financial Accounting Standards Board guidelines, net of estimated production and future development costs, using pricing and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. PV-10 is pre-tax and therefore a non-U.S. GAAP financial measure. +Probable reserves - This term is defined in the SEC Regulation S-X Section 4-10(a) and refers to those reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. Similarly, when probabilistic methods are used, there must be at least a 50 percent probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. +Productive well - A well that is not a dry well or dry hole, as defined above, and includes wells that are mechanically capable of production. +Proved developed non-producing reserves - Reserves that consist of (i) proved reserves from wells which have been completed and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and/or (ii) proved reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the wells. +Proved developed producing reserves or PDPs - Proved reserves that can be expected to be recovered from currently producing zones under the continuation of present operating methods. +Proved developed reserves - The combination of proved developed producing and proved developed non-producing reserves. +Proved reserves - This term means "proved oil and gas reserves" as defined in SEC Regulation S-X Section 4-10(a) and refers to those quantities of crude oil and condensate, natural 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 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. +Proved undeveloped reserves or PUDs - Proved 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. +Recomplete or Recompletion - The modification of an existing well for the purpose of producing crude oil and natural gas from a different producing formation. +Refracture - A refracture occurs when we stimulate a well by fracturing a producing zone to increase its production as well as its PDP reserves. +103 +Reserves - Estimated remaining quantities of crude oil, natural gas, NGLs and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering crude oil, natural gas and NGLs or related substances to market, and all permits and financing required to implement the project. +Royalty - An interest in a crude oil and natural gas lease or mineral interest that gives the owner of the royalty the right to receive a portion of the production from the leased acreage or mineral interest (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner. +Section - A square tract of land one mile by one mile, containing 640 acres. +Spud - To begin drilling; the act of beginning a hole. Past tense: spudded . +Standardized measure of discounted future net cash flows or standardized measure - Future net cash flows discounted at a rate of 10%. Future net cash flows represent the estimated future revenues to be generated from the production of proved reserves determined in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, giving effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment and (ii) future income tax expense. +Stratigraphic test well - A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. +TCO - Columbia Gas Transmission. +Unconventional resource(s) - Crude oil and natural gas that cannot be produced at economic flow rates in economic volumes unless the well is stimulated by a large hydraulic fracture treatment, a horizontal wellbore, or by using multilateral wellbores or some other technique to expose more of the resources to the wellbore. +Undeveloped acreage - Leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and natural gas, regardless of whether such acreage contains proved reserves. +Wet gas or wet natural gas - Natural gas that contains a larger quantity of hydrocarbon liquids than dry natural gas, such as NGLs, condensate and crude oil. +Working interest - An interest in a crude oil and natural gas lease that gives the owner of the interest the right to drill and produce crude oil and natural gas on the leased acreage. It requires the owner to pay its share of the costs of drilling and production operations. +Workover - Major remedial operations on a producing well to restore, maintain or improve the well's production. +104 \ No newline at end of file diff --git a/raw/filings/0000077877/2013/0000077877-14-000013/filing_metadata.csv b/raw/filings/0000077877/2013/0000077877-14-000013/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..06e936b1d26ea4f6c63264c28db0a75c9d859f69 --- /dev/null +++ b/raw/filings/0000077877/2013/0000077877-14-000013/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 +0000077877,PDCE,"PDC ENERGY, INC.",10-K,2014-02-21,2013-12-31,2014-02-20T23:01:24.000Z,0000077877-14-000013,pdce-10kxfy13.htm,PDC ENERGY 2013 FORM 10-K,26746420,1,0,https://www.sec.gov/Archives/edgar/data/77877/000007787714000013/pdce-10kxfy13.htm,https://www.sec.gov/Archives/edgar/data/77877/000007787714000013/,2013,2013,1 diff --git a/raw/filings/0000077877/2013/0000077877-14-000013/item1.txt b/raw/filings/0000077877/2013/0000077877-14-000013/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2013/0000077877-14-000013/item13.txt b/raw/filings/0000077877/2013/0000077877-14-000013/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..20a7eea0612c7046d019816ce2b30b24a77f3246 --- /dev/null +++ b/raw/filings/0000077877/2013/0000077877-14-000013/item13.txt @@ -0,0 +1,2 @@ +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2014 Annual Stockholders' meeting and is incorporated by reference in this report. \ No newline at end of file diff --git a/raw/filings/0000077877/2013/0000077877-14-000013/item9a.txt b/raw/filings/0000077877/2013/0000077877-14-000013/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..0de2c6bc5277dc5c76552a354498ca704c984dfa --- /dev/null +++ b/raw/filings/0000077877/2013/0000077877-14-000013/item9a.txt @@ -0,0 +1,5 @@ +ITEM 9A. CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +As of December 31, 2013 , we carried out an evaluation under the supervision and with the participation of 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 pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e). Based on the results of this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2013 . +Changes in Internal Control over Financial Reporting +During the fourth quarter of 2013 , we made no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) that have materially affected or are reasonably likely to materially affect our internal control over financial reporting. \ No newline at end of file diff --git a/raw/filings/0000077877/2013/0000077877-14-000013/rp_note.txt b/raw/filings/0000077877/2013/0000077877-14-000013/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2013/0000077877-14-000013/rpt_disclosure.txt b/raw/filings/0000077877/2013/0000077877-14-000013/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..e3403060b655118179e7b76971157049fd91bf64 --- /dev/null +++ b/raw/filings/0000077877/2013/0000077877-14-000013/rpt_disclosure.txt @@ -0,0 +1,18 @@ +TRANSACTIONS WITH RELATED PERSONS +Related Transactions +From January 1, 2013 to the +present, there was no transaction or series of transactions, nor is there any currently proposed transaction involving an amount exceeding $120,000 in which the Company is a participant and/or in which any Director, executive officer, known holder +of more than five percent of the Company’s voting securities, or any member of the immediate family of any of the foregoing persons had or will have a direct or indirect material interest for which disclosure is required under SEC Rule S-K 404. +Policies and Procedures With Respect to Transactions with Related Persons +The Board has adopted a written policy for the review, approval and ratification of transactions that involve related +parties and potential conflicts of interest. The related party transaction policy applies to each Director and executive officer of the Company, any nominee for election as a Director, any security holder who is known to own more than five percent +of the Company’s voting securities, any immediate family member of any of the foregoing persons and any corporation, firm or association in which one or more of the Company’s Directors are directors or officers, or have a substantial +financial interest. +24 +Table of Contents +Under our related-party transaction policy, a related person transaction is +a transaction or arrangement involving a related person in which the Company is a participant or that would require disclosure in the Company’s filings with the SEC as a transaction with a related person. The related person must disclose to the +Audit Committee any potential related person transactions and must disclose all material facts with respect to such transaction and relationship. All related person transactions will be reviewed by the Audit Committee. In determining whether to +approve or ratify a transaction, the Audit Committee will consider the relevant facts and circumstances of the transaction, which may include factors such as the relationship of the related person with the Company, the materiality or significance of +the transaction to the Company and the business purpose and reasonableness of the transaction, whether the transaction is comparable to a transaction that could be available to the Company on an arms-length basis and the impact of the transaction on +the Company’s business and operations. \ No newline at end of file