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+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0000874499,GPOR,GULFPORT ENERGY CORP,10-K,2015-02-27,2014-12-31,2015-02-27T21:20:18.000Z,0001628280-15-001182,gpor-12312014x10k.htm,10-K,29851557,1,0,https://www.sec.gov/Archives/edgar/data/874499/000162828015001182/gpor-12312014x10k.htm,https://www.sec.gov/Archives/edgar/data/874499/000162828015001182/,2014,2014,1

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+ITEM 1. 
+BUSINESS 
+General 
+We are an independent oil and natural gas exploration and production company focused on the exploration, exploitation, acquisition and production of natural gas, natural gas liquids and crude oil in the United States. Our corporate strategy is to internally identify prospects, acquire lands encompassing those prospects and evaluate those prospects using subsurface geology and geophysical data and exploratory drilling. Using this strategy, we have developed an oil and natural gas portfolio of proved reserves, as well as development and exploratory drilling opportunities on high potential conventional and unconventional oil and natural gas prospects. Our principal properties are located in the Utica Shale primarily in Eastern Ohio and along the Louisiana Gulf Coast in the West Cote Blanche Bay, or WCBB, and Hackberry fields. In addition, we have producing properties in the Niobrara Formation of Northwestern Colorado and the Bakken Formation. We also hold a significant acreage position in the Alberta oil sands in Canada through our interest in Grizzly Oil Sands ULC, or Grizzly, and interests in entities that operate in Southeast Asia, including the Phu Horm gas field in Thailand. Until November 2014, we held an equity interest in Diamondback Energy, Inc., or Diamondback, a NASDAQ Global Select Market listed company to which we contributed our Permian Basin oil and natural gas interests in October 2012 immediately prior to Diamondback's initial public offering, or the Diamondback IPO. At December 31, 2014, we did not own any shares of Diamondback. We seek to achieve reserve growth and increase our cash flow through our annual drilling programs. 
+As of February 13, 2015, we held acquired leasehold interests in approximately 188,000 gross (184,000 net) acres in the Utica Shale primarily in Eastern Ohio, including approximately 8,200 net acres acquired from Rhino Exploration LLC in the first quarter of 2014. We spud our first well, the Wagner 1-28H, on our Utica Shale acreage in February 2012 and, as of December 31, 2014 , had spud 151 gross wells, 101 of which were completed and were producing. In 2014 , we spud 85 gross (67.2 net) wells, of which 36 were completed as producing wells, two were non-productive and, as of December 31, 2014, 41 were in various stages of completion and six were still being drilled. We commenced sales from 63 gross wells (47.4 net wells) in the Utica Shale during 2014. During 2015 (through February 13, 2015), we had spud five gross (four net) wells. As of February 13, 2015, three of these wells were in various stages of completion and two were still drilling. In addition, 110 gross (13.3 net) wells were drilled by other operators on our Utica Shale acreage during 2014. 
+We currently intend to drill 46 to 52 gross (28 to 32 net) horizontal wells, and commence sales from 49 to 53 gross (42 to 46 net) horizontal wells on our Utica Shale acreage in 2015 for an estimated aggregate cost of $400.0 million to $430.0 million. We currently anticipate 11 to 16 gross (four to six net) horizontal wells will be drilled, and sales commenced from 50 to 64 gross (seven to nine net) horizontal wells, by other operators on our Utica Shale acreage during 2015 for an estimated cost of $125.0 million to $140.0 million. 
+Aggregate net production from our Utica Shale acreage during the three months ended December 31, 2014 was approximately 32,513 net million cubic feet of natural gas equivalent, or MMcfe, or 353.4 MMcfe per day, of which 80% was from natural gas and 20% was from oil and natural gas liquids, or NGLs. During January 2015, our average daily net production from the Utica Shale was approximately 345.6 MMcfe, of which 79% was from natural gas and 21% was from oil and NGLs. 
+In 2014 , at our WCBB field, we recompleted 91 wells and spud 29 wells. Of the 29 new wells spud at WCBB in 2014 , 21 were completed as producing wells, five were non-productive and, at year end, three were waiting on completion. In the fourth quarter of 2014 , production at WCBB was approximately 1,810 MMcfe, or an average of 19.7 MMcfe per day, 100% of which was from oil. During January 2015, our average net daily production at WCBB was approximately 19.0 MMcfe, 100% of which was from oil. 
+In 2014 , at our East Hackberry field, we recompleted 68 wells and spud 15 wells. All of the 15 new wells spud at East Hackberry during 2014 were completed as producing wells. In the fourth quarter of 2014 , net production at East Hackberry was approximately 640 MMcfe, or an average of 7.0 MMcfe per day, of which 82% was from oil and 18% was from natural gas. During January 2015, our average net daily production at East Hackberry was approximately 10.1 MMcfe, of which 91% was from oil and 9% was from natural gas. 
+In 2014 , at our West Hackberry field, we recompleted two wells and spud one well which was productive. In the fourth quarter of 2014 , net production at West Hackberry was approximately 66.3 MMcfe, or an average of 720.4 Mcfe per day, of which 91% was from oil and 9% was from natural gas. During January 2015, our average net daily production at West Hackberry was approximately 589.2 Mcfe, of which 97% was from oil and 3% was from natural gas. 
+2 
+Table of Contents 
+Index to Financial Statements 
+We currently estimate our 2015 activities in our Southern Louisiana fields to be approximately $20.0 million to $25.0 million in aggregate for maintenance capital activities. 
+Effective as of April 1, 2010, we acquired our initial leasehold interests in the Niobrara Formation in Northwestern Colorado and, as of December 31, 2014 , we held leases for approximately 5,900 net acres. During the year ended December 31, 2014 , there were no wells spud on our Niobrara Formation acreage. In the fourth quarter of 2014 , net production from our Niobrara Formation acreage was approximately 27.4 MMcfe, or an average of 297.3 Mcfe per day, 100% of which was from oil. During January 2015, our average net daily production from our Niobrara Formation acreage was approximately 326.3 Mcfe, 100% of which was from oil. During 2015, we currently do not anticipate drilling any wells in the Niobrara Formation. 
+As of December 31, 2014 , we held approximately 864 net acres in the Bakken Formation of Western North Dakota and Eastern Montana with interests in 18 wells and overriding royalty interests in certain existing and future wells. In the fourth quarter of 2014 , our net production from this acreage was approximately 74.4 MMcfe, or an average of 808.8 Mcfe per day, of which 93% was from oil and natural gas liquids and 7% was from natural gas. During January 2015, our average daily net production from our Bakken Formation acreage was approximately 609.0 Mcfe, of which 87% was from oil and 13% was from natural gas. 
+As of December 31, 2014, we had sold all of our shares of common stock of Diamondback, a NASDAQ Global Select Market listed company to which we contributed our Permian Basin oil and gas interests in October 2012 immediately prior to the Diamondback IPO. See Notes 4 and 5 to our consolidated financial statements included elsewhere in this report for additional information regarding our prior investment in Diamondback. 
+We, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.9% interest in Grizzly. As of December 31, 2014 , Grizzly had approximately 830,000 net acres under lease in the Athabasca, Peace River and Cold Lake oil sands regions of Alberta, Canada. Grizzly has three oil sands projects in various stages of development. Grizzly commenced commercial production from its Algar Lake Phase 1 steam-assisted gravity drainage, or SAGD, oil sand project during the second quarter of 2014 and has received regulatory approval for up to 11,300 barrels per day of bitumen production. Grizzly produced approximately 1,400 barrels of bitumen per day at its Algar Lake SAGD project during the fourth quarter of 2014. Grizzly has announced that it expects bitumen production to reach its 6,000 barrels per day peak production rate by the fourth quarter of 2015. In the first quarter of 2012, Grizzly acquired the May River property comprising approximately 47,000 acres. An initial 12,000 barrel per day development application was filed with the regulatory authorities in the fourth quarter of 2013, covering the eastern portion of the May River lease. The development application continues to move through the regulatory process and is expected to be approved by mid-2015. In the first quarter of 2014, a 2-D seismic program covering approximately 83 kilometers was completed to more fully define the resource over the remaining lease beyond the development application area. At the Thickwood thermal project, a development application for a 12,000 barrel per day oil sands project was filed in the fourth quarter of 2012. Since then, the Alberta Energy Regulator, or AER, announced it is implementing a policy for future regulatory requirements for reservoir containment in shallow SAGD areas, which impacts the Thickwood application. Additional work to advance the Thickwood application will be required and is expected to be addressed once the May River development approval is received. Grizzly has also developed delineation drilling, seismic and regulatory work plans at its Cadotte, Peace River property. Grizzly is pursuing a rail marketing strategy to ensure consistent and flexible access to premium markets for its production, including its Windell truck to rail terminal located near Conklin, Alberta, which commenced transloading blended bitumen production from Algar Lake on to rail cars for delivery to the US Gulf Coast markets in the second quarter of 2014. 
+We own a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex II. Tatex II, a privately held entity, holds an 8.5% interest in APICO, LLC, or APICO, an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering approximately 243,000 acres which includes the Phu Horm Field. 
+We also own a 17.9% ownership interest in Tatex Thailand III, LLC, or Tatex III. Tatex III owns a concession covering approximately 245,000 acres in Southeast Asia. In 2009, Tatex III completed a 3-D seismic survey on this concession. Between 2010 and 2013, three wells were drilled on Tatex III's concession. Each of the wells lacked sufficient permeability to produce in commercial quantities. Tatex III plans to allow the concession to expire in 2015. 
+In an effort to facilitate the development of our Utica Shale and other domestic acreage, we have invested in entities that can provide services that are required to support our operations. In 2013, we participated in the formation of Stingray Energy Services LLC, or Stingray Energy, with an initial ownership interest of 50%. Stingray Energy provides rental tools for land-based oil and natural gas drilling, completion and workover activities as well as the transfer of fresh water to wellsites. In 2012, we participated in the formation of Stingray Pressure Pumping LLC, or Stingray Pressure, Stingray Cementing LLC, or 
+3 
+Table of Contents 
+Index to Financial Statements 
+Stingray Cementing, and Stingray Logistics LLC, or Stingray Logistics, with an initial ownership interest in each entity of 50%. These entities provide well completion and other well services. In 2012, we also participated in the formation of Blackhawk Midstream LLC, or Blackhawk, and Timber Wolf Terminals, LLC, or Timber Wolf, with an initial ownership interest of 50% in each entity. Blackhawk coordinates gathering, compression, processing and marketing activities in connection with the development of our Utica Shale acreage and Timber Wolf will operate a crude/condensate terminal and a sand transloading facility in Ohio. Also in 2012, we acquired a 22.5% equity interest in Windsor Midstream LLC, or Midstream, which owns a 28.4% equity interest in a gas processing plant in West Texas. In 2011 and 2012, we acquired an aggregate 40% equity interest in Bison Drilling and Field Services LLC, or Bison, which owns and operates drilling rigs and related equipment. Also in 2011, we acquired a 25% interest in Muskie Proppant LLC, or Muskie, which is engaged in the processing and sale of hydraulic fracturing grade sand. In 2014, we acquired a 25% equity interest in Sturgeon Acquisitions LLC, or Sturgeon. Sturgeon owns and operates sand mines that produce hydraulic fracturing grade sand. In the fourth quarter of 2014, we contributed our investments in Stingray Pressure, Stingray Logistics, Bison and Muskie to Mammoth Energy Partners LP, or Mammoth, in exchange for a 30.5% limited partner interest in this newly formed limited partnership. Mammoth has filed a registration statement on Form S-1 with the SEC in connection with a contemplated initial public offering, which it intends to pursue in 2015 subject to market conditions. See Note 5 to our consolidated financial statements included elsewhere in this report for additional information regarding these investments. 
+As of December 31, 2014 , we had 933.6 Bcfe of proved reserves with a present value of estimated future net revenues, discounted at 10%, or PV-10, of approximately $1.8 billion and associated standardized measure of discounted future net cash flows of approximately $1.4 billion , excluding reserves attributable to our interests in Grizzly, Tatex II and Tatex III. See "Item 2. Properties-Proved Oil and Natural Gas Reserves ” for our definition of PV-10, a non-GAAP financial measure, and a reconciliation of our standardized measure of discounted future net cash flows to PV-10. 
+Principal Oil and Natural Gas Properties 
+The following table presents certain information as of December 31, 2014 reflecting our net interest in our principal producing oil and natural gas properties in the Utica Shale primarily in Eastern Ohio, along the Louisiana Gulf Coast, in the Niobrara Formation in Northwestern Colorado and in the Bakken Formation in Western North Dakota and Eastern Montana. 
+Proved Reserves 
+Field 
+NRI/WI (1) 
+Productive 
+Wells (2) 
+Non-Productive 
+Wells 
+Developed 
+Acreage (3) 
+Gas 
+Oil 
+NGLs 
+Total 
+Percentages 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+MMcf 
+MBbls 
+MBbls 
+MMcfe 
+Utica Shale (4) 
+34.52/41.46 
+195 
+80.85 
+3 
+2.66 
+21,652 
+19,340 
+716,905 
+5,412 
+26,268 
+906,982 
+West Cote Blanche Bay Field (5) 
+80.108/100 
+123 
+123 
+185 
+185 
+5,668 
+5,668 
+1,318 
+2,968 
+— 
+19,127 
+E. Hackberry Field (6) 
+80.945/100 
+39 
+39 
+107 
+107 
+3,931 
+3,931 
+516 
+469 
+— 
+3,331 
+W. Hackberry Field 
+79.167/100 
+6 
+6 
+7 
+7 
+1,192 
+1,192 
+— 
+402 
+— 
+2,413 
+Niobrara Formation 
+39.83/47.85 
+6 
+3 
+— 
+— 
+3,502 
+1,751 
+135 
+124 
+— 
+878 
+Bakken Formation (4) 
+1.51/1.83 
+18 
+0.3 
+— 
+— 
+1,862 
+163 
+108 
+121 
+— 
+834 
+Overrides/Royalty Non-operated 
+Various 
+384 
+0.42 
+— 
+— 
+— 
+— 
+24 
+1 
+— 
+33 
+Total 
+771 
+252.57 
+302 
+301.66 
+37,807 
+32,045 
+719,006 
+9,497 
+26,268 
+933,598 
+(1) 
+Net Revenue Interest (NRI)/Working Interest (WI) for producing wells. 
+(2) 
+Includes one gross and net well at WCBB that is producing intermittently. 
+(3) 
+Developed acres are acres spaced or assigned to productive wells. Approximately 16% of our acreage is developed acreage and has been held by production. 
+(4) Includes NRI/WI from wells that have been drilled or in which we have elected to participate. Includes 94 gross (7.57 net) wells drilled by other operators on our acreage. 
+(5) 
+We have a 100% working interest (80.108% average NRI) from the surface to the base of the 13900 Sand which is located at 11,320 feet. Below the base of the 13900 Sand, we have a 40.40% non-operated working interest (29.95% NRI). 
+(6) 
+NRI shown is for producing wells. 
+4 
+Table of Contents 
+Index to Financial Statements 
+Utica Shale (primarily in Eastern Ohio) 
+Location and Land 
+As of December 31, 2014 , we held leasehold interests in approximately 185,000 gross (180,000 net) acres in the Utica Shale. 
+Area History 
+The Ohio Department of Natural Resources reported that in the Utica Shale in Ohio, as of February 7, 2015, there were 740 producing horizontal wells, 335 horizontal wells that had been drilled but were not yet completed or connected to a pipeline, 273 horizontal wells that were being drilled and an additional 451 horizontal wells that had been permitted. 
+Geology 
+The Utica Shale is located in the Appalachian Basin of the United States and Canada. The Utica Shale is a rock unit comprised of organic-rich calcareous black shale that was deposited about 440 million to 460 million years ago during the Late Ordovician period. It overlies the Trenton Limestone and is located a few thousand feet below the Marcellus Shale. 
+Recently, the application of horizontal drilling, combined with multi-staged hydraulic fracturing to create permeable flow paths from shale units into wellbores, has resulted in increased drilling activity and production in the Devonian-age Marcellus Shale and the Ordovician-age Utica Shale in the Appalachian Basin states of Pennsylvania, West Virginia, Southern New York and Eastern Ohio. This proven technology has potential for application in other shale units which extend across much of the Appalachian Basin region. 
+The Utica Shale is estimated to be thicker and more geographically extensive than the Marcellus Shale. The source rock portion of the Utica Shale underlies portions of Kentucky, Maryland, New York, Ohio, Pennsylvania, Tennessee, West Virginia and Virginia in the United States and is also present beneath parts of Lake Ontario, Lake Erie and Ontario, Canada. Throughout this area, the Utica Shale ranges in thickness from less than 100 feet to over 500 feet. There is a general thinning from east to west. 
+The Utica Shale is also significantly deeper than the Marcellus Shale. In some parts of Pennsylvania, the Utica Shale is estimated to be over two miles below sea level and up to 7,000 feet below the Marcellus Shale. However, the depth of the Utica Shale decreases to the west into Ohio and to the northwest under the Great Lakes and into Canada to less than 2,000 feet below sea level. 
+The Utica Shale is estimated to have higher carbonate and lower clay mineral content than the Marcellus Shale. The difference in mineralogy generally produces a different response to hydraulic fracturing treatments. Operators in the Utica play continue to refine completions techniques to optimize productivity. 
+Facilities 
+There are standard land oil and gas processing facilities in the Utica Shale. Our facilities located at well site pads include storage tank batteries, oil/gas/water separation equipment, vapor recovery units, line heaters, compression emission control devices and applicable metering. 
+Recent and Future Activities 
+We spud our first well, the Wagner 1-28H, on our Utica Shale acreage in February 2012 and, as of December 31, 2014 , had spud 151 gross wells, 101 of which were completed and were producing. In 2014, we spud 85 gross (67.2 net) wells, of which 36 were completed and are productive, two were non-productive and, as of December 31, 2014, 41 were in various stages of completion and six were still being drilled. During 2015 (through February 13, 2015), we had spud five gross (four net) wells during 2015 of which three were in various stages of completion and two were still drilling. In addition, 110 gross (13.3 net) wells were drilled by other operators on our Utica Shale acreage during 2014. 
+We currently intend to drill 46 to 52 gross (28 to 32 net) horizontal wells, and commence sales from 49 to 53 gross (42 to 46 net) horizontal wells, on our Utica Shale acreage in 2015 and anticipate 11 to 16 gross (four to six net) horizontal wells will be drilled, and sales commenced from 50 to 64 gross (seven to nine net) horizontal wells, by other operators on our Utica Shale 
+5 
+Table of Contents 
+Index to Financial Statements 
+acreage during 2015. As of February 25, 2015, we had four operated horizontal rigs drilling in the play, but plan to release one of these rigs by the end of the first quarter of 2015. 
+Production Status 
+Aggregate net production from the Utica Shale during the three months ended December 31, 2014 was approximately 32,513 MMcfe, or 353.4 MMcfe per day, of which 80% was from natural gas and 20% was from oil and NGLs. During January 2015, our average daily net production from the Utica Shale was approximately 345.6 MMcfe, of which 79% was from natural gas and 21% was from oil and NGLs. The slight decrease in January 2015 production was the result of adverse winter weather conditions, partially offset by our 2014 drilling activities. 
+West Cote Blanche Bay Field 
+Location and Land 
+The WCBB field is located approximately five miles off the coast of Louisiana in a shallow bay with water depths averaging eight to ten feet. We own a 100% working interest (80.108% net revenue interest, or NRI), and are the operator, in depths above the base of the 13900 Sand which is located at 11,320 feet. In addition, we own a 40.40% non-operated working interest (29.95% NRI) in depths below the base of the 13900 Sand, which is operated by Chevron Corporation. Our leasehold interests at WCBB contain 5,668 gross acres. 
+Area History and Production 
+Texaco, now Chevron Corporation, drilled the discovery well in this field in 1940 based on a seismic and gravitational anomaly. WCBB was subsequently developed on an even 160-acre pattern for much of the remainder of the decade. Developmental drilling continued and reached its peak in the 1970s when over 300 wells were drilled in the field. Of the 1,077 wells drilled as of December 31, 2014 , 973 were completed as producing wells. From the date of our acquisition of WCBB in 1997 through December 31, 2014 , we drilled 265 new wells, 233 of which were productive, for an 88% success rate. As of December 31, 2014 , estimated field cumulative gross production was 196.8 MMBOE and 237.0 Bcf of gas. Of the 1,077 wells drilled in WCBB as of December 31, 2014 , 122 were producing, 185 were shut-in, one was producing intermittently, one was waiting on completion and six were being used as salt water disposal wells. The other 762 wells have been plugged and abandoned. 
+In 1991, Texaco conducted a 70 square mile 3-D seismic survey with 1,100 shot points per mile that processed out 100 fold. In 1993, an undershoot survey around the crest and production facilities was completed. We own the rights to the seismic data. In December 1999, we completed the reprocessing of the seismic data and our technical staff developed prospects from the data. The reprocessed data has enabled us to identify prospects in areas of the field that would have otherwise remained obscure. During the first half of 2005, we again reprocessed the seismic data using advanced seismic data processing. 
+Geology 
+WCBB overlies one of the largest salt dome structures on the Gulf Coast. The field is characterized by a piercement salt dome, which created traps from the Pleistocene through the Miocene formations. The relative movements affected deposition and created a complex system of fault traps. The compensating fault sets generally trend northwest to southeast and are intersected by sets having a major radial component. Later-stage movement caused extension over the dome and a large graben system (a downthrown area bounded by normal faults) was formed. 
+There are over 100 distinct sandstone reservoirs recognized throughout most of the field, and nearly 200 major and minor discrete intervals have been tested. Within the 1,077 wells that had been drilled in the field as of December 31, 2014 , over 4,000 potential zones have been penetrated. These sands are highly porous and permeable reservoirs primarily with a strong water drive. 
+WCBB is a structurally and stratigraphically complex field. All of the proved undeveloped, or PUD, locations at WCBB are adjacent to faults and abut at least one fault. Our drilling programs are designed to penetrate each PUD trap with a new wellbore in a structurally optimum position, usually very close to the fault seal. The majority of these wells have been, and new wells drilled in connection with our drilling programs will be, directionally drilled using steering tools and downhole motors. The tolerance for error in getting near the fault is low, so the complex faulting does introduce the risk of crossing the fault before encountering the zone of interest, which could result in part or all of the zone being absent in the borehole. This, in turn, 
+6 
+Table of Contents 
+Index to Financial Statements 
+can result in lower than expected or no reserves for that zone. The new wellbores eliminate the mechanical risk associated with trying to produce the zone from an old existing wellbore, while the wellbore locations are selected in an effort to more efficiently drain each reservoir. The vast majority of the PUD targets are up-dip offsets to wells that produced from a sub-optimal position within a particular zone. 
+Facilities 
+We own and operate a production facility at WCBB that includes four production tank batteries, eight natural gas compressors, a storage barge facility, a dock, a dehydration unit and a salt water disposal system. 
+Recent and Future Activity 
+In 2014, we recompleted 91 gross and net wells and spud 29 gross and net wells at WCBB. Of the 29 new wells spud at WCBB in 2014, 21 were completed as producers, five were non-productive and, at year end, three were waiting on completion. As of February 13, 2015, we had recompleted seven wells during 2015 in our WCBB field. Of the 29 wells drilled in 2014, 22 were considered deep wells. The 21 productive wells, with total depths ranging from 2,500 to 10,501 feet, have approximately 894 feet of aggregate apparent net pay. 
+Production Status 
+In the fourth quarter of 2014, our production at WCBB was approximately 1,810 net MMcfe, or an average of 19.7 MMcfe per day, 100% of which was from oil. During January 2015, our average net daily production at WCBB was approximately 19.0 MMcfe, 100% of which was from oil. The slight decrease in average net daily production in January 2015 was due to normal production declines. 
+East Hackberry Field 
+Location and Land 
+The East Hackberry field in Louisiana is located along the western shore and the land surrounding Lake Calcasieu, 15 miles inland from the Gulf of Mexico. We own a 100% working interest (approximately 80.945% average NRI) in certain producing oil and natural gas properties situated in the East Hackberry field. As of December 31, 2014 , we held beneficial interests in approximately 4,512 acres, including the Erwin Heirs Block, which is located on land, and the adjacent State Lease 50 Block, which is located primarily in the shallow waters of Lake Calcasieu. We licensed approximately 54 square miles of 3-D seismic data covering a portion of the area and have received a processed version of the seismic data. 
+Area History and Production 
+The East Hackberry field was discovered in 1926 by Gulf Oil Company, now Chevron Corporation, by a gravitational anomaly survey. The massive shallow salt stock presented an easily recognizable gravity anomaly indicating a productive field. Initial production began in 1927 and has continued to the present. The estimated cumulative oil and condensate production through 2014 was over 4,037 MBOE and 331.8 Bcf of casinghead gas production. A total of 269 wells have been drilled on our portion of the field. As of December 31, 2014 , 39 wells had daily production, 107 were shut-in and three had been converted to salt water disposal wells. The remaining 120 wells had been plugged and abandoned. 
+Geology 
+The Hackberry field is a major salt intrusive feature, elliptical in shape as opposed to a classic “dome,” divided into east and west field entities by a saddle. Structurally, our East Hackberry acreage is located on the eastern end of the Hackberry salt ridge. There are over 30 pay zones at this field. The salt intrusion formed a series of structurally complex and steeply dipping fault blocks in the Lower Miocene and Oligocene age rocks. These fault blocks serve as traps for hydrocarbon accumulation. Our wells currently produce from perforations found between 5,100 and 12,200 feet. 
+Facilities 
+We have a field office that serves both the East and West Hackberry fields. In addition, we own and operate three production facilities at East Hackberry that include two land based tank batteries, a production barge, five natural gas compressors, dehydration units and salt water disposal systems. 
+7 
+Table of Contents 
+Index to Financial Statements 
+Recent and Future Activity 
+During 2014 at East Hackberry, we recompleted 68 gross and net wells and drilled 15 gross and net land wells. All of the 15 wells drilled during 2014 were completed as producing wells. As of February 13, 2015, we had recompleted 11 wells during 2015 in our East Hackberry field. 
+Production Status 
+In the fourth quarter of 2014, our net production at East Hackberry was approximately 640 MMcfe, or an average of 7.0 MMcfe per day, 82% of which was from oil and 18% of which was from natural gas. During January 2015, our average net daily production at East Hackberry was approximately 10.1 MMcfe, of which 91% was from oil and 9% was from natural gas. The increase in production in 2015 is a result of our 2014 drilling and recompletion activities. 
+West Hackberry Field 
+Location and Land 
+The West Hackberry field is located on land and is five miles west of Lake Calcasieu in Cameron Parish, Louisiana, approximately 85 miles west of Lafayette and 15 miles inland from the Gulf of Mexico. We own a 100% working interest (approximately 79.167% NRI) in 1,192 acres within the West Hackberry field. Our leases at West Hackberry are located within two miles of one of the United States Department of Energy's Strategic Petroleum Reserves. 
+Area History 
+The first discovery well at West Hackberry was drilled in 1938 and the field was developed by Superior Oil Company, now ExxonMobil Corporation, between 1938 and 1988. The estimated cumulative oil and condensate production through 2014 was 426 MBOE and 140 Bcf of natural gas. As of December 31, 2014, 41 wells had been drilled on our portion of West Hackberry. As of December 31, 2014, six of such wells were producing, seven were shut-in and one had been converted to a saltwater disposal well. The remaining 27 wells have been plugged and abandoned. 
+Geology 
+Structurally, our West Hackberry acreage is located on the western end of the Hackberry salt ridge. There are over 30 pay zones at this field. West Hackberry consists of a series of fault-bounded traps in the Oligocene-age Vincent and Keough sands associated with the Hackberry Salt Ridge. Recoveries from these thick, porous, water-drive reservoirs have resulted in per well cumulative production of almost 700 MBOE. 
+Recent and Future Activity 
+During 2014 at West Hackberry, we recompleted two gross and net wells and drilled one gross and net well which was productive. As of February13, 2015, no new wells had been drilled in our West Hackberry field. 
+Production Status 
+In the fourth quarter of 2014, our net production at West Hackberry was approximately 66.3 MMcfe, or an average of 720.4 Mcfe per day, of which 91% was from oil and 9% was from natural gas. During January 2015, our average net daily production at West Hackberry was approximately 589.2 Mcfe, of which 97% was from oil and 3% was from natural gas. 
+Facilities 
+We own and operate a production facility at West Hackberry that includes a land based tank battery and salt water disposal system. 
+8 
+Table of Contents 
+Index to Financial Statements 
+Niobrara Formation (Northwestern Colorado) 
+Location and Land 
+Effective as of April 1, 2010, we acquired leasehold interests in the Niobrara Formation in Northwestern Colorado and, as of December 31, 2014, we held leases for approximately 5,900 net acres. In 2014, no wells were spud on our Niobrara Formation acreage. 
+Area History 
+The Niobrara Formation is a shale oil rock formation located in Colorado, Northwest Kansas, Southwest Nebraska, and Southeast Wyoming. Oil and natural gas can be found at depths of 3,000 to 14,000 feet and is drilled both vertically and horizontally. The Upper Cretaceous Niobrara Formation has emerged as another potential crude oil resource play in various basins throughout the northern Rocky Mountain region. As with most resource plays, the Niobrara Formation has a history of producing through conventional technology with some of the earliest production dating back to the early 1900s. Natural fracturing has played a key role in producing the Niobrara Formation historically due to the low porosity and low permeability of the formation. Because of this, conventional production has been very localized and limited in area extent. We believe the Niobrara Formation can be produced on a more widespread basis using today's horizontal multi-stage fracture stimulation technology where the Niobrara Formation is thermally mature. 
+Geology 
+The Niobrara Formation oil play in Northwestern Colorado is located between the Piceance Basin to the south and the Sand Wash Basin to the north. Rocks mainly consist of interbedded organic-rich shales, calcareous shales and marlstones. It is the fractured marlstone intervals locally known as the Buck Peak, Tow Creek and Wolf Mountain benches that account for the majority of the area's production. These fractured carbonate reservoirs are associated with anticlinal, synclinal and monoclinal folds, and fault zones. This proven oil accumulation is considered to be continuous in nature and lightly explored. Source rocks are predominantly oil prone and thermally mature with respect to oil generation. The producing intervals are geologically equivalent to the Niobrara Formation reservoirs of the DJ and Powder River Basins, which are currently emerging as a major crude resource play. 
+Production Status 
+In the fourth quarter of 2014, our net production from our Niobrara Formation acreage was approximately 27.4 MMcfe, or an average of 297.3 Mcfe per day, 100% of which was from oil. During January 2015, our average daily net production from our Niobrara Formation acreage was approximately 326.3 Mcfe, 100% of which was from oil. 
+Facilities 
+There are typical land oil and gas processing facilities in the Niobrara Formation. Our facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units. 
+Recent and Future Activity 
+We have completed a 60 square mile 3-D seismic survey over our Craig Dome prospect and have received a processed version of the seismic. We do not anticipate drilling any wells in the Niobrara Formation during 2015. 
+Bakken Formation 
+Location and Land 
+The Bakken Formation is located in the Williston Basin areas of Western North Dakota and Eastern Montana. As of December 31, 2014 , we held approximately 864 net acres, interests in 18 wells and an overriding royalty interests in certain existing and future wells. 
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+Index to Financial Statements 
+Production Status 
+In the fourth quarter of 2014, our net production from our Bakken Formation acreage was approximately 74.4 MMcfe, or an average of 808.8 Mcfe per day, of which 93% was from oil and NGLs and 7% was from natural gas. During January 2015, our average net daily production from this acreage was approximately 609.0 Mcfe, of which 87% was from oil and 13% was from natural gas. 
+Facilities 
+There are typical land, oil and gas processing facilities in the Williston Basin. The facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units. 
+Recent and Future Activities 
+Two gross (.01 net) wells were drilled on our Bakken Formation acreage in 2014. As of February 13, 2015, no new wells had been drilled on our Bakken Formation acreage in 2015. 
+Additional Properties 
+Louisiana . In addition to our interests in the WCBB, East Hackberry and West Hackberry fields, we also own working interests and overriding royalty interest in various fields in Louisiana, Texas and Oklahoma as described in the following table as of December 31, 2014: 
+Field 
+State 
+Parish/County 
+Acreage Working 
+Interest 
+Overriding Royalty 
+Interests 
+Producing 
+Wells 
+Non-Producing 
+Wells 
+Deer Island 
+Louisiana 
+Terrebonne 
+3.125 
+% 
+— 
+1 
+— 
+Napoleonville 
+Louisiana 
+Assumption 
+— 
+2.5 
+% 
+3 
+— 
+Crest 
+Texas 
+Ochiltree 
+2 
+% 
+— 
+1 
+— 
+Eagle City South 
+Oklahoma 
+Dewey 
+1.04 
+% 
+— 
+1 
+— 
+Fay South 
+Oklahoma 
+Blaine 
+0.301 
+% 
+— 
+1 
+— 
+Squaw Cheek 
+Oklahoma 
+Blaine 
+0.694 
+% 
+— 
+1 
+— 
+Our Equity Investments 
+Grizzly Oil Sands . We, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.9% interest in Grizzly. As of December 31, 2014 , Grizzly had approximately 830,000 net acres under lease in the Athabasca, Peace River and Cold Lake oil sands regions of Alberta, Canada. Grizzly has three oil sands projects in various stages of development. Grizzly commenced commercial production from its Algar Lake Phase 1 steam-assisted gravity drainage, or SAGD, oil sand project during the second quarter of 2014 and has received regulatory approval for up to 11,300 barrels per day of bitumen production. Grizzly produced approximately 1,400 barrels of bitumen per day at its Algar Lake SAGD project during the fourth quarter of 2014. Grizzly has announced that it expects bitumen production to reach its 6,000 barrels per day peak production rate by the fourth quarter of 2015. In the first quarter of 2012, Grizzly acquired the May River property comprising approximately 47,000 acres. An initial 12,000 barrel per day development application was filed with the regulatory authorities in the fourth quarter of 2013, covering the eastern portion of the May River lease. The development application continues to move through the regulatory process and is expected to be approved by mid-2015. In the first quarter of 2014, a 2-D seismic program covering approximately 83 kilometers was completed to more fully define the resource over the remaining lease beyond the development application area. At the Thickwood thermal project, a development application for a 12,000 barrel per day oil sands project was filed in the fourth quarter of 2012. Since then, the Alberta Energy Regulator, or AER, announced it is implementing a policy for future regulatory requirements for reservoir containment in shallow SAGD areas, which impacts the Thickwood application. Additional work to advance the Thickwood application will be required and is expected to be addressed once the May River development approval is received. Grizzly has also developed delineation drilling, seismic and regulatory work plans at its Cadotte, Peace River property. Grizzly is pursuing a rail marketing strategy to ensure consistent and flexible access to premium markets for its production, including its Windell truck to rail terminal located near Conklin, Alberta, which commenced transloading blended bitumen production from Algar Lake on to rail cars for delivery to the US Gulf Coast markets in the second quarter of 2014. 
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+Thailand . We own a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex II. Tatex II, a privately held entity, holds an 8.5% interest in APICO, an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering approximately 243,000 acres which includes the Phu Horm Field. Our investment is accounted for on the equity method. Tatex II accounts for its investment in APICO using the cost method. In December 2006, first gas sales were achieved at the Phu Horm field located in northeast Thailand. Phu Horm's initial gross production was approximately 60 million cubic feet per day. For 2014, net gas production was approximately 105 MMcf per day and condensate production was 415 barrels per day. Hess Corporation, or Hess, operates the field with a 35% interest. Other interest owners include APICO (35% interest), PTT Exploration and Production Public Company Limited (20% interest) and ExxonMobil (10% interest). Our gross working interest (through Tatex II as a member of APICO) in the Phu Horm field is 0.7%. Since our ownership in the Phu Horm field is indirect and Tatex II's investment in APICO is accounted for by the cost method, these reserves are not included in our year-end reserve information. 
+We own a 17.9% ownership interest in Tatex Thailand III, LLC, or Tatex III. Tatex III owns a concession covering approximately 245,000 acres in Southeast Asia. In 2009, Tatex III completed a 3-D seismic survey on this concession. Between 2010 and 2013, three wells were drilled on this concession. Each of the wells lacked sufficient permeability to produce in commercial quantities. Tatex III plans to allow the concession to expire in 2015. 
+Other Investments . In an effort to facilitate the development of our Utica Shale and other domestic acreage, we have invested in entities that can provide services that are required to support our operations. In 2013, we participated in the formation of Stingray Energy with an initial ownership interest of 50%. Stingray Energy provides rental tools for land-based oil and natural gas drilling, completion and workover activities as well as the transfer of fresh water to wellsites. In 2012, we participated in the formation of Stingray Pressure, Stingray Cementing, and Stingray Logistics, with an initial ownership interest in each entity of 50%. These entities provide well completion and other well services. In 2012, we also participated in the formation of Blackhawk and Timber Wolf, with an initial ownership interest of 50% in each entity. Blackhawk coordinates gathering, compression, processing and marketing activities in connection with the development of our Utica Shale acreage and Timber Wolf will operate a crude/condensate terminal and a sand transloading facility in Ohio. Also in 2012, we acquired a 22.5% equity interest in Midstream which owns a 28.4% equity interest in a gas processing plant in West Texas. In 2011 and 2012, we acquired an aggregate 40% equity interest in Bison, which owns and operates drilling rigs and related equipment. Also in 2011, we acquired a 25% interest in Muskie, which is engaged in the processing and sale of hydraulic fracturing grade sand. In 2014, we acquired a 25% equity interest in Sturgeon. Sturgeon owns and operates sand mines that produce hydraulic fracturing grade sand. In the fourth quarter of 2014, we contributed our investments in Stingray Pressure, Stingray Logistics, Bison and Muskie to Mammoth in exchange for a 30.5% limited partner interest in this newly formed limited partnership. Mammoth has filed a registration statement on Form S-1 with the SEC in connection with a contemplated initial public offering which it intends to pursue in 2015 subject to market conditions. See Note 5 to our consolidated financial statements included elsewhere in this report for additional information regarding these other investments. 
+Competition 
+The oil and natural gas industry is intensely competitive, and we compete 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 midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These competitors may be better positioned to take advantage of industry opportunities and to withstand changes affecting the industry, such as fluctuations in oil and natural gas prices and production, the availability of alternative energy sources and the application of government regulation. In addition, oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the availability or price of oil and natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas. 
+Marketing and Customers 
+The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control of our management, including but not limited to the demand for oil and natural gas and the level of domestic production and imports of oil, the proximity and capacity of gas pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of gas sold in interstate commerce. The oil and natural gas we produce in Louisiana is sold to purchasers who service the areas where our wells are located. We sell the majority of our Southern Louisiana oil to Shell Trading Company, or Shell. Shell takes custody of the oil at the outlet from our oil storage barge. Our production from WCBB is being sold in accordance with the Shell posted price for West Texas/New Mexico Intermediate crude plus or minus Platt's trade month average P+ value, plus or minus the Platt's HLS/WTI differential 
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+less transportation charges. Shell is the purchaser of our Utica Shale oil and pays us WTI less a differential. MarkWest Utica currently markets our Utica Shale NGLs and remits to us a weighted average selling price less a marketing fee. We have NAESBs in place with various purchasers for our Utica Shale natural gas production. In 2014, our Utica Shale natural gas and natural gas liquids were sold under monthly, seasonal and long term contracts and, as needed, through daily trades. The majority of purchases are transacted at the tailgate of the plants with available pricing based on Platts Gas Daily - Appalachian - Dominion South Point (Dominion Eastern and Dominion Transmission) or Texas Eastern M2 Zone when sold in the Utica Basin. To maintain flow assurance and price stability, and as discussed under "- Transportation and Takeaway Capacity," we have entered into agreements to transport a portion of our natural gas production out of the Utica Basin. These agreements have pricing based on the appropriate delivery point less transportation charges and fuel. 
+During the year ended December 31, 2014 , we sold approximately 99% of our oil production to Shell, 100% of our natural gas liquids production to MarkWest Utica and 40%, 32% and 19% of our natural gas production to BP, DTE Energy Trading, Inc. and Hess, respectively. During the year ended December 31, 2013, we sold approximately 99% of our oil production to Shell, 100% of our natural gas liquids production to MarkWest Utica and 32%, 31% and 17% of our natural gas production to Sequent Energy Management, L.P., Hess and Interstate Gas Supply, Inc., respectively. During the year ended December 31, 2012, we sold approximately 92% and 8% of our oil production to Shell and Diamondback O&G LLC (a wholly-owned subsidiary of Diamondback formerly known as Windsor Permian LLC), or Diamondback O&G, respectively, 91% of our natural gas liquids production to Diamondback O&G and 41%, 18% and 16% of our natural gas production to Noble Americas Gas, Hess and Chevron, respectively. 
+As of December 31, 2014, we had approximately 218,000 MMBtu per day of firm sales contracted with third parties. Of these sales, 33,000 MMBtu per day, 5,000 MMBtu per day, 30,000 MMBtu per day, 50,000 MMBtu per day, 50,000 MMBtu per day and 50,000 MMBtu per day expire in 2015, 2016, 2017, 2018, 2019 and 2022, respectively. 
+Transportation and Takeaway Capacity 
+In Ohio, as of December 31, 2014, we had entered into firm transportation contracts for 2015, 2016 and 2017 for an aggregate of approximately 619,000 MMBtu per day, 719,000 MMBtu per day and 719,000 MMBtu per day, respectively, and currently have agreements in place to transport and/or sell approximately 787,000 MMBtu per day of our gross Utica Shale gas production by year-end 2015. We continuously monitor the need to secure additional firm transportation contracts for incremental volumes from our Utica Shale acreage but expect additional contracts to be limited in 2015. Our primary long-haul firm transportation commitments include the following: 
+• 
+194,000 MMBtu per day of firm capacity on ANR Pipeline Company facilities, which began in 2014 and allows us to reach the Michigan, Chicago and Wisconsin natural gas markets, 
+• 
+200,000 MMBtu per day of firm capacity on Tennessee Gas Pipeline facilities beginning in April 2015 allowing access to Gulf Coast delivery points, 
+• 
+175,000 MMBtu per day of firm capacity on Rockies Express Pipeline facilities expected to begin in mid-2015 allowing additional connectivity to Gulf Coast and Midwest markets, 
+• 
+50,000 MMBtu per day of firm capacity on Texas Gas Transmission facilities expected to begin in 2016 allowing additional access to Gulf Coast delivery points, and 
+• 
+100,000 MMBtu per day of firm capacity on Energy Transfer’s Rover Pipeline facilities beginning in late 2016/early 2017 allowing additional access to both Midwest and Gulf Coast delivery points. 
+Under firm transportation contracts, we are obligated to deliver minimum daily volumes or pay fees for any deficiencies in deliveries. We continue to actively identify and evaluate additional takeaway capacity to facilitate production growth in our Utica Basin position. 
+Regulation 
+Regulation of Gas and Oil Production 
+Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the oil and natural gas industry is 
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+Index to Financial Statements 
+under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability. 
+We own interests in producing oil and natural gas properties located in the Utica Shale primarily in Eastern Ohio, along the Louisiana Gulf Coast and in the Niobrara Formation in Northwestern Colorado and the Bakken Formation in Western North Dakota and Eastern Montana. The states in which our fields are located regulate the production and sale of oil and natural gas, including requirements for obtaining drilling permits, the method of developing fields and the spacing and operation of wells. In addition, regulations governing conservation matters aimed at preventing the waste of oil and natural gas resources could affect the rate of production and may include maximum daily production allowables for wells on a market demand or conservation basis. 
+Environmental Regulation 
+Our oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. Numerous governmental agencies, such as the U.S. Environmental Protection Agency, or the EPA, issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing earthen pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or relate to our owned or operated facilities. The strict and joint and several liability nature of such laws and regulations could impose liability upon us regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. This trend, however, may not continue in the future. 
+Waste Handling . The Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent requirements of non-hazardous waste provisions. However, we cannot assure you that the EPA or state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses. 
+Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes. 
+Remediation of Hazardous Substances . The Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as CERCLA or the “Superfund” law, and analogous state laws, generally imposes strict and joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or 
+13 
+Table of Contents 
+Index to Financial Statements 
+operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” may be subject to strict and joint and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous substances” have been released. 
+Water Discharges . The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” the Safe Drinking Water Act, the Oil Pollution Act, or OPA, and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. These laws and regulations also prohibit certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. In addition, on October 20, 2011, the EPA announced a schedule to develop pre-treatment standards for wastewater discharges produced by natural gas extraction from shale formations. The EPA stated that it will gather data, consult with the stakeholders, including ongoing consultation with the industry, and solicit public comment on a proposed rule for shale gas in early 2015. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. 
+The OPA is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters. 
+Noncompliance with the Clean Water Act or the OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws. 
+Air Emissions . The federal Clean Air Act, as amended, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, on August 16, 2012, the EPA published final regulations under the federal Clean Air Act that establish new emission controls for oil and natural gas production and processing operations, which regulations are discussed in more detail below under the caption “ -Regulation of Hydraulic Fracturing .” These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects. 
+Climate Change . In December 2009, the EPA issued an Endangerment Finding that determined that emissions of carbon dioxide, methane and other greenhouse gasses, or GHGs, present an endangerment to public health and the environment because, according to the EPA, emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that 
+14 
+Table of Contents 
+Index to Financial Statements 
+would restrict emissions of GHGs under existing provisions of the federal Clean Air Act, including rules that regulate emissions of GHGs from certain large stationary sources of emissions such as power plants or industrial facilities. In response to its endangerment finding, the EPA adopted two sets of rules regarding possible future regulation of GHG emissions under the Clean Air Act. The motor vehicle rule, which became effective in January 2011, purports to limit emissions of GHGs from motor vehicles. The EPA adopted the stationary source rule (or the “tailoring rule”) in May 2010, and it also became effective in January 2011. The tailoring rule established new GHG emissions thresholds that determine when stationary sources must obtain permits under the Prevention of Significant Deterioration, or PSD, and Title V programs of the Clean Air Act. On June 23, 2014, in Utility Air Regulatory Group v. EPA , the Supreme Court held that stationary sources could not become subject to PSD or Title V permitting solely by reason of their GHG emissions. The Court ruled, however, that the EPA may require installation of best available control technology for GHG emissions at sources otherwise subject to the PSD and Title V programs. On December 19, 2014, the EPA issued two memoranda providing initial guidance on GHG permitting requirements in response to the Court’s decision in Utility Air Regulatory Group v. EPA . In its preliminary guidance, the EPA indicated that it will undertake a rulemaking action no later than December 31, 2015 to rescind any PSD permits issued under the portions of the tailoring rule that were vacated by the Court. In the interim, the EPA issued a narrowly crafted “no action assurance” indicating it will exercise its enforcement discretion not to pursue enforcement of the terms and conditions relating to GHGs in an EPA-issued PSD permit, and for related terms and conditions in a Title V permit. In November 2010, the EPA expanded its existing GHG reporting rule to include onshore and offshore oil and natural gas production and onshore processing, transmission, storage and distribution facilities, which may include certain of our facilities, beginning in 2012 for emissions occurring in 2011. 
+The EPA has continued to adopt GHG regulations applicable to other industries, such as the September 2013 proposed GHG rule that, if finalized, would set New Source Performance Standards, which we refer to as the NSP standards, for new coal-fired and natural-gas fired power plants. As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility. In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Although the U.S. Congress has not adopted such legislation at this time, it may do so in the future and many states continue to pursue regulations to reduce greenhouse gas emissions. 
+Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect the oil and natural gas industry. Currently, while we are subject to certain federal GHG monitoring and reporting requirements, our operations are not adversely impacted by existing federal, state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business. 
+In addition, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornados and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations. 
+Endangered Species Act 
+Environmental laws such as the Endangered Species Act, as amended, or the ESA, may impact exploration, development and production activities on public or private lands. The ESA provides broad protection for species of fish, wildlife and plants that are listed as threatened or endangered in the U.S., and prohibits taking of endangered species. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. Federal agencies are required to insure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed species or modify their critical habitat. While some of our facilities may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. The U.S. Fish and Wildlife Service may identify, however, previously unidentified endangered or threatened species or may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species, which could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas. 
+Occupational Safety and Health Act 
+15 
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+Index to Financial Statements 
+We are also subject to the requirements of OSHA and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements. 
+Regulation of Hydraulic Fracturing 
+Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. We use hydraulic fracturing extensively in the development of our Utica Shale acreage. The federal Safe Drinking Water Act, or SDWA, regulates the underground injection of substances through the Underground Injection Control, or UIC, program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions. The EPA, however, has in the past taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program, specifically as “Class II” UIC wells. In addition, on May 9, 2014, the EPA issued an Advance Notice of Proposed Rulemaking seeking comment on the development of regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. The public comment period ended on September 19, 2014. Also, the EPA is updating chloride water quality criteria for the protection of aquatic life under the Clean Water Act, which criteria are used by states for establishing acceptable discharge limits. The EPA is expected to release draft criteria in early 2016. Moreover, the EPA announced in 2011 that it was launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards in early 2015 that such wastewater must meet before being transported to a treatment plant. As part of these studies, the EPA has requested that certain companies provide them with information concerning the chemicals used in the hydraulic fracturing process. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise. 
+Legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. 
+On August 16, 2012, the EPA approved final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes NSP standards to address emissions of sulfur dioxide and volatile organic compounds, or VOCs, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule seeks to achieve a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. The EPA intends to issue revised rules that will likely be responsive to some of these requests. For example, on September 23, 2013, the EPA published an amendment extending compliance dates for certain storage vessels. Also, on December 19, 2014, the EPA released final updates and clarifications to the NSP standards. In addition, on January 14, 2015, the EPA announced a series of steps it plans to take to address methane and smog-forming VOC emissions from the oil and gas industry. At this point, we cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty. In addition, the U.S. Department of the Interior, or DOI, published a revised proposed rule on May 24, 2013, that would update existing regulation for hydraulic fracturing activities on federal lands, including requirements for disclosure, well bore integrity and handling of flowback water. The DOI announced its intent to finalize the rule in 2014, however, the final rule remains pending. 
+In addition, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. These ongoing or proposed studies, depending on their degree of pursuit and whether any meaningful results are obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities. The EPA is currently evaluating the potential impacts of hydraulic fracturing on drinking water resources, with results of the study anticipated to be available in March 2015. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. The U.S. Department of Energy has conducted an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods. Additionally, certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the Securities and Exchange Commission, or SEC, to investigate the natural gas industry and any possible misleading of investors or the public 
+16 
+Table of Contents 
+Index to Financial Statements 
+regarding the economic feasibility of pursuing natural gas deposits in shale formations by means of hydraulic fracturing, and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. 
+Some states and local jurisdictions in which we operate or hold oil and natural gas interests have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, in June 2012, Ohio’s Governor signed legislation mandating chemical disclosure for hydraulic fracturing fluids, pre-drilling testing of water samples within 1,500 feet of a proposed horizontal well, and increased well operator liability insurance requirements. In addition, in April 2014, Ohio’s Department of Natural Resources announced new permit conditions for drilling near faults or areas of past seismic activity. The Texas Railroad Commission, or RRC, and Louisiana Department of Natural Resources adopted rules and regulations requiring that well operators disclose the list of chemical ingredients subject to the requirements of federal Occupational Safety and Health Act (OSHA) to state regulators and on a public internet website. Additionally, on October 28, 2014, the RRC adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water and hydraulic fracturing flowback fluid to conduct seismic activity searches utilizing the U.S. Geological Survey. These searches are intended to determine the potential of earthquakes within a circular area of 100 square miles around a proposed new disposal well. The disposal well rule amendments, which became effective in Texas on November 17, 2014, also clarify the RRC’s authority to modify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismic activity. Also, in May 2013, the RRC adopted new rules, which became effective in January 2014, governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. Effective August 27, 2011, Montana adopted hydraulic fracturing disclosure regulations under which well operators must provide information in drilling permit applications on the estimated volume and types of materials to be used in the proposed hydraulic fracturing activities. Upon completion of the well, well operators must provide the Montana Board of Oil and Gas Conservation with the volume and type of chemicals used, including the additive type, chemical ingredient names, and Chemical Abstracts Service, or CAS, number, subject to certain trade secret protections. On April 1, 2012, the North Dakota Industrial Commission enacted regulations requiring hydraulic fracturing well operators to disclose the hydraulic fluid composition, including the trade name, supplier, ingredients, CAS Number, and the maximum ingredient concentrations of all additives in the hydraulic fracturing fluid. Colorado enacted rules requiring similar disclosures on January 30, 2012. Also, in 2013 and 2014, Colorado approved regulations that require well operators to test groundwater quality before and after drilling and to install emission controls to capture 95 percent of VOC and methane emissions. In addition, on May 16, 2013, the DOI issued a revised proposed rule that seeks to require companies operating on federal and Indian lands to (i) publicly disclose the chemicals used in the hydraulic fracturing process; (ii) confirm its wells meet certain construction standards and (iii) establish site plans to manage flowback water. 
+There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal, state or local level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal, state or local laws governing hydraulic fracturing. 
+Other Regulation of the Oil and Natural Gas Industry 
+The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production. 
+17 
+Table of Contents 
+Index to Financial Statements 
+The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation and sale for resale of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission, or FERC. Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. FERC's regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas. 
+Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. We cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of condensate and oil and natural gas liquids are not currently regulated and are made at market prices. 
+Drilling and Production . Our operations are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The states and some counties and municipalities in which we operate also regulate one or more of the following: 
+• 
+the location of wells; 
+• 
+the method of drilling and casing wells; 
+• 
+the timing of construction or drilling activities, including seasonal wildlife closures; 
+• 
+the rates of production or “allowables”; 
+• 
+the surface use and restoration of properties upon which wells are drilled; 
+• 
+the plugging and abandoning of wells; and 
+• 
+notice to, and consultation with, surface owners and other third parties. 
+State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. 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 requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or to limit the number of locations we can drill. 
+Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements. 
+Natural Gas Sales and Transportation . Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production. Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. 
+18 
+Table of Contents 
+Index to Financial Statements 
+FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and release of our natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC's initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities. 
+Under FERC’s current regulatory regime, transmission services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of transporting gas to point-of-sale locations. 
+Oil Sales and Transportation . Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future. 
+Our crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors. 
+Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines' published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors. 
+State Regulation . The states in which we operate regulate the drilling for, and the production and gathering of, oil and natural gas, including through requirements relating to the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may also regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill. 
+The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us. 
+Operational Hazards and Insurance 
+The oil and natural gas business involves a variety of operating risks, including the risk of fire, explosions, blow outs, pipe failures and, in some cases, abnormally high pressure formations which could lead to environmental hazards such as oil spills, natural gas leaks and the discharge of toxic gases. If any of these should occur, we could incur legal defense costs and could be required to pay amounts due to injury, loss of life, damage or destruction to property, natural resources and equipment, pollution or environmental damage, regulatory investigation and penalties and suspension of operations. 
+In accordance with what we believe to be industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We insure some, but not all, of our properties for operational and hurricane 
+19 
+Table of Contents 
+Index to Financial Statements 
+related events. We currently have insurance policies that include coverage for general liability, physical damage to our oil and natural gas properties, operational control of certain wells, oil pollution, third party liability, workers compensation and employers' liability and other coverage. Our insurance coverage includes deductibles that must be met prior to recovery. Additionally, our insurance is subject to exclusion and limitations, and there is no assurance that such coverage will fully or adequately protect us against liability from all potential consequences, damages and losses. Any of these events could cause a significant disruption to our business. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows. 
+Currently, we have general liability insurance coverage with an annual aggregate limit of up to $21.0 million which includes sudden and accidental pollution for the effects of onshore and offshore pollution on third parties arising from our operations as well as $10.0 million of gradual pollution insurance coverage. For our offshore WCBB properties, we also have a $38.0 million property physical damage policy which insures against most operational perils, such as explosions, fire, vandalism, theft, hail and windstorms, provided, however, that this policy is limited to $12.5 million for damages arising as a result of a named windstorm. In the event of a loss under this policy, we have up to $12.6 million of business interruption coverage available after a 90 day waiting period. All of our insurance coverage includes deductibles of up to $500,000 per occurrence ($1.25 million in the case of a named windstorm) that must be met prior to recovery. Additionally, our insurance is subject to customary exclusions and limitations. We reevaluate the purchase of insurance, policy terms and limits annually each May. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable and we may elect to maintain minimal or no insurance coverage. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. The occurrence of a significant event, not fully insured against, could have a material adverse effect on our financial condition and results of operations. 
+We carry control of well insurance for all of our Utica Shale wells and several Southern Louisiana wells. We also require all of our third party vendors to sign master service agreements in which they agree to indemnify us for injuries and deaths of the service provider's employees as well as contractors and subcontractors hired by the service provider. 
+We have prepared and have in place spill prevention control and countermeasure plans for each of our principal facilities in response to federal and state requirements. The plans are reviewed annually and updated as necessary. As required by applicable regulations, our facilities are built with secondary containment systems to capture potential releases. We also own additional spill kits with oil booms and absorbent pads that are readily available, if needed. In addition, we have emergency response companies on retainer. These companies specialize in the clean up of hydrocarbons as a result of spills, blow-outs and natural disasters, and are on call to us 24 hours a day, seven days a week when their services are needed. We pay these companies a retainer plus additional amounts when they provide us with clean up services. Our aggregate payments for the retainer and clean up services during 2014 and 2013 were approximately $0.2 million and $0.7 million, respectively. While these companies have been able to meet our service needs when required from time to time in the past, it is possible that the ability of one or more of them to provide services to us in the future, if and when needed, could be hindered or delayed in the event of a widespread disaster. However, in light of the areas in which we operate and the nature of our production, we believe other companies would be available to us in the event our primary remediation companies are unable to perform. To supplement our planning and operation activities in Ohio, we also actively manage an incident response planning program and coordinate with applicable state agency personnel on spills and releases. We also participate in Ohio's Emergency Planning and Community Right to Know Act (EPCRA) program, which includes reporting of various materials used or stored on-site as well as notification to state and local emergency response centers, such as local fire departments, for emergency planning purposes. 
+Headquarters and Other Facilities 
+We own an approximately 28,500 square foot office building in Oklahoma City, Oklahoma that serves as our corporate headquarters. Additionally, we lease approximately 25,200 square feet of office space in other buildings in Oklahoma City. We also own an approximately 12,500 square foot building in Lafayette, Louisiana. This building contains approximately 6,200 square feet of finished office area and 6,300 square feet of clear span warehouse area. We also lease approximately 3,700 square feet in a building in Lafayette that we use as our Louisiana headquarters. We own an approximately 5,700 square foot office building in St. Clairsville, Ohio that serves as our Ohio headquarters. In addition, we lease approximately 4,275 square feet of office space in St. Clairsville, Ohio. Each of these properties is suitable and adequate for its use. 
+20 
+Table of Contents 
+Index to Financial Statements 
+Employees 
+At December 31, 2014 , we had 203 employees. An unrelated Louisiana well servicing company provides all necessary field personnel needed to operate the WCBB and the Hackberry fields. 
+Availability of Company Reports 
+Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on the Investor Relations page of our website at www.gulfportenergy.com as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. Information contained on our website, or on other websites that may be linked to our website, is not incorporated by reference into this annual report on Form 10-K and should not be considered part of this report or any other filing that we make with the SEC.

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+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+For information concerning Item 13-Certain Relationships and Related Transactions, and Director Independence, see our definitive proxy statement, which will be filed with the Securities and Exchange Commission with 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference).

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+ITEM 9A. 
+CONTROLS AND PROCEDURES 
+Evaluation of Disclosure Control and Procedures . Under the direction of our Chief Executive Officer and President and our Chief Financial Officer, we have established disclosure controls and procedures that are designed to ensure that information required to be disclosed by us 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's rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and President and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures. 
+As of December 31, 2014 , an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and President and our Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and President and our Chief Financial Officer have concluded that, as of December 31, 2014 , our disclosure controls and procedures are effective. 
+Changes in Internal Control over Financial Reporting . There have not been any changes in our internal control over financial reporting that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting. 
+68 
+Table of Contents 
+Index to Financial Statements 
+Management's Report on Internal Control Over Financial Reporting 
+Management is responsible for the fair presentation of the consolidated financial statements of Gulfport Energy Corporation. Management is also responsible for establishing and maintaining a system of adequate internal controls over financial reporting as defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. These internal controls are designed to provide reasonable assurance that the reported financial information is presented fairly, that disclosures are adequate and that the judgments inherent in the preparation of financial statements are reasonable. There are inherent limitations in the effectiveness of any system of internal control, including the possibility of human error and overriding of controls. Consequently, an effective internal control system can only provide reasonable, not absolute, assurance with respect to reporting financial information. 
+Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in the 2013 Internal Control-Integrated Framework , management did not identify any material weaknesses in our internal control over financial reporting and concluded that our internal control over financial reporting was effective as of December 31, 2014 . 
+Grant Thornton LLP, the independent registered public accounting firm that audited our financial statements for the year ended December 31, 2014 included with this Annual Report on Form 10-K, has also audited our internal control over financial reporting as of December 31, 2014 , as stated in their accompanying report. 
+/s/ Michael G. Moore 
+/s/ Aaron Gaydosik 
+Name: 
+Michael G. Moore 
+Name: 
+Aaron Gaydosik 
+Title: 
+Chief Executive Officer and President 
+Title: 
+Chief Financial Officer 
+69 
+Table of Contents 
+Index to Financial Statements 
+Report of Independent Registered Public Accounting Firm 
+Board of Directors and Stockholders 
+Gulfport Energy Corporation: 
+We have audited the internal control over financial reporting of Gulfport Energy Corporation and Subsidiaries (the “Company”) as of December 31, 2014 , based on criteria established in the 2013 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, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. 
+We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014 , based on criteria established in the 2013 Internal Control-Integrated Framework issued by COSO. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of the Company as of and for the year ended December 31, 2014 and our report dated February 27, 2015 expressed an unqualified opinion on those financial statements. 
+/s/ GRANT THORNTON LLP 
+Oklahoma City, Oklahoma 
+February 27, 2015 
+70 
+Table of Contents 
+Index to Financial Statements

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+Certain Relationships and Related Transactions 
+Review and Approval of Related Party Transactions 
+The audit committee, as provided in its charter, reviews and approves related party transactions. The Company does not have a formal set of standards to be
+substantively applied to each transaction reviewed by the audit committee. Instead of a formalized policy, related party transactions are reviewed and judgment is applied to determine whether such transactions are in the best interests of the
+Company. Further, the Company’s Code of Business Conduct and Ethics governs various compliance areas, including conflicts of interest and fair dealings, which are considered in the process of the review and approval of related party
+transactions. 
+The Company’s policy is that all of its employees and directors, as well as their family members, must avoid any activity that is or
+has the appearance of conflicting with the Company’s business interest. This policy is included in the Company’s Code of Business Conduct and Ethics posted on its website. Each director and executive officer is instructed to always inform
+the designated compliance officer when confronted with any situation that may be perceived as a conflict of interest. Only the board of directors or a committee consisting solely of independent directors may grant waivers of the provisions of the
+Code of Business Conduct and Ethics for the Company’s executive officers and directors. In addition, at least annually, each director and executive officer completes a detailed questionnaire specifying any business relationship that may give
+rise to a conflict of interest. 
+Further, under the audit committee charter, the audit committee is responsible for reviewing and monitoring compliance
+with our Code of Business Conduct and Ethics and recommending any warranted changes to the board of directors. In addition, the board of directors and, pursuant to its written charter, the audit committee, reviews and approves all relationships and
+transactions in which the Company and its directors, director nominees and executive officers and their immediate family members, as well as holders of more than 5% of any class of our voting securities and their family members, have a direct or
+indirect material interest. The board of directors and the audit committee approve only those transactions that, in light of known circumstances, are consistent, or are not inconsistent with, the Company’s best interests, as they determine in
+the good faith exercise of their discretion.

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raw/filings/0000874499/2015/0001628280-16-011417/item13.txt

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+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+For information concerning Item 13-Certain Relationships and Related Transactions, and Director Independence, see our definitive proxy statement, which will be filed with the Securities and Exchange Commission with 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference).

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+ITEM 9A. 
+CONTROLS AND PROCEDURES 
+Evaluation of Disclosure Control and Procedures . Under the direction of our Chief Executive Officer and President and our Chief Accounting Officer, we have established disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, 
+72 
+Table of Contents 
+Index to Financial Statements 
+summarized and reported within the time periods specified in the SEC's rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and President and our Chief Accounting Officer, as appropriate to allow timely decisions regarding required disclosures. 
+As of December 31, 2015 , an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and President and our Chief Accounting Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and President and our Chief Accounting Officer have concluded that, as of December 31, 2015 , our disclosure controls and procedures are effective. 
+Changes in Internal Control over Financial Reporting . There have not been any changes in our internal control over financial reporting that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting. 
+Management's Report on Internal Control Over Financial Reporting 
+Management is responsible for the fair presentation of the consolidated financial statements of Gulfport Energy Corporation. Management is also responsible for establishing and maintaining a system of adequate internal controls over financial reporting as defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. These internal controls are designed to provide reasonable assurance that the reported financial information is presented fairly, that disclosures are adequate and that the judgments inherent in the preparation of financial statements are reasonable. There are inherent limitations in the effectiveness of any system of internal control, including the possibility of human error and overriding of controls. Consequently, an effective internal control system can only provide reasonable, not absolute, assurance with respect to reporting financial information. 
+Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in the 2013 Internal Control-Integrated Framework , management did not identify any material weaknesses in our internal control over financial reporting and concluded that our internal control over financial reporting was effective as of December 31, 2015 . 
+Grant Thornton LLP, the independent registered public accounting firm that audited our financial statements for the year ended December 31, 2015 included with this Annual Report on Form 10-K, has also audited our internal control over financial reporting as of December 31, 2015 , as stated in their accompanying report. 
+/s/ Michael G. Moore 
+/s/ Keri Crowell 
+Name: 
+Michael G. Moore 
+Name: 
+Keri Crowell 
+Title: 
+Chief Executive Officer and President 
+Title: 
+Chief Accounting Officer 
+73 
+Table of Contents 
+Index to Financial Statements 
+Report of Independent Registered Public Accounting Firm 
+Board of Directors and Stockholders 
+Gulfport Energy Corporation: 
+We have audited the internal control over financial reporting of Gulfport Energy Corporation and subsidiaries (the “Company”) as of December 31, 2015 , based on criteria established in the 2013 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, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. 
+We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015 , based on criteria established in the 2013 Internal Control-Integrated Framework issued by COSO. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of the Company as of and for the year ended December 31, 2015 and our report dated February 19, 2016 expressed an unqualified opinion on those financial statements. 
+/s/ GRANT THORNTON LLP 
+Oklahoma City, Oklahoma 
+February 19, 2016 
+74 
+Table of Contents 
+Index to Financial Statements

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+and approves related party transactions. 
+• Appoints, determines compensation, evaluates and terminates our independent
+auditors. 
+• Pre-approves audit and permissible non-audit services to be performed by the
+independent auditors. 
+• Prepares the report required by the Securities and Exchange Commission, or
+the SEC, for the inclusion in our annual proxy statement. 
+• Reviews and reassesses the adequacy of the audit committee charter on a
+periodic basis. 
+• Inform our independent auditors of the audit committee’s understanding
+of significant relationships and transactions with related parties and review and discuss with our independent auditors the auditors’ evaluation of our identification of, accounting for and disclosure of our relationships and transactions with
+related parties, including any significant matters arising from the audit regarding our relationships and transactions with related parties. 
+Four (4) 
+8 
+Table of Contents 
+Committee 
+Members 
+Principal Functions 
+Number of 
+Meetings in 
+2015 
+Compensation 
+Scott E. Streller* 
+Craig Groeschel 
+David L. Houston 
+C. Doug Johnson 
+• Oversees and administers our executive compensation
+policies, plans and practices and evaluates their impact on risk and risk management. 
+• Assists the board of directors in discharging its responsibilities relating
+to the compensation of our executives, including our chief executive officer, and other key employees. 
+• Administers our equity-based compensation plans, including the grants of
+stock options, restricted stock awards and other equity awards under such plans. 
+• Reviews, approves and administers our cash-based incentive bonus plans,
+including the establishment of performance criteria, targets and awards under our 2014 Executive Annual Incentive Compensation Plan. 
+• Makes recommendations to the board with respect to incentive
+compensation. 
+• Where appropriate or required, makes recommendations to our stockholders
+with respect to incentive compensation and equity-based plans. 
+• Conducts annual performance evaluation of the committee. 
+• Reviews
+disclosure related to executive compensation in our proxy statement and prepares an annual compensation committee report. 
+• Reviews and considers the stockholders’ advisory vote on executive
+compensation and the frequency of holding such advisory vote. 
+• Reviews and reassesses the adequacy of the compensation committee
+charter. 
+Six (6) 
+Nominating and Corporate Governance 
+Ben T. Morris* 
+Donald L. Dillingham+ 
+David L. Houston 
+Scott E. Streller 
+• Assists the board of directors in developing criteria for,
+identifying and evaluating individuals qualified to serve as members of our board of directors. 
+• Selects and recommends director candidates to the board of directors to be
+submitted for election at the Annual Meeting and to fill any vacancies on the board of directors. 
+• Periodically reviews and makes recommendations regarding the composition and
+size of the board of directors and each of its committees. 
+Three (3) 
+9 
+Table of Contents 
+Committee 
+Members 
+Principal Functions 
+Number of 
+Meetings in 
+2015 
+• Reviews and recommends to the board of directors
+appropriate corporate governance policies and procedures for the Company. 
+• Conducts an annual assessment of the qualifications and performance of
+the board of directors. 
+• Annually reviews and reports to the board of directors on the
+performance of management. 
+• Reviews and reassesses the adequacy of the nominating committee
+charter. 
+* 
+Committee Chairperson. 
++ 
+Mr. Dillingham informed us that he did not intend to stand for re-election at the Annual Meeting. 
+Do
+the committees have written charters? 
+Yes. The charters for our audit committee, compensation committee and nominating committee can be found on our
+website at www.gulfportenergy.com under the “Corporate Governance” caption. You may also obtain copies of these charters, as well as our Code of Business Conduct and Ethics, which is described below, by writing to our Assistant
+Corporate Secretary, Paul K. Heerwagen IV, at Gulfport Energy Corporation, 14313 N. May Avenue, Suite 100, Oklahoma City, Oklahoma 73134.

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+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0000874499,GPOR,GULFPORT ENERGY CORP,10-K,2017-02-15,2016-12-31,2017-02-14T23:36:38.000Z,0001628280-17-001359,gpor-12312016x10k.htm,10-K,20579931,1,0,https://www.sec.gov/Archives/edgar/data/874499/000162828017001359/gpor-12312016x10k.htm,https://www.sec.gov/Archives/edgar/data/874499/000162828017001359/,2016,2016,1

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+ITEM 1. 
+BUSINESS 
+General 
+We are an independent oil and natural gas exploration and production company focused on the exploration, exploitation, acquisition and production of natural gas, natural gas liquids and crude oil in the United States. Our principal properties are located in the Utica Shale primarily in Eastern Ohio and along the Louisiana Gulf Coast in the West Cote Blanche Bay, or WCBB, and Hackberry fields. In December 2016, we entered into a definitive agreement to purchase oil and natural gas assets including 46,400 net surface acres with multiple producing zones, including the Woodford and Springer formations, in Grady, Stephens, and Garvin counties, Oklahoma, (see " - Our Pending Acquisition " below) which we expect to complete in February 2017. In addition, we have an interest in producing properties in the Niobrara Formation of Northwestern Colorado and the Bakken Formation. We also hold a significant acreage position in the Alberta oil sands in Canada through our interest in Grizzly Oil Sands ULC, or Grizzly, and an interest in an entity that operates in the Phu Horm gas field in Thailand. We also hold an approximate 24.2% equity interest in Mammoth Energy Services, Inc., or Mammoth Energy, an oil field services company listed on the NASDAQ Global Select Market, to which we contributed our membership interest in Mammoth Partners LLC (previously, Mammoth Energy Partners LP) in connection with Mammoth Energy’s initial public offering completed on October 19, 2016. We seek to achieve reserve growth and increase our cash flow through our annual drilling programs. 
+As of February 10, 2017 , we held leasehold interests in approximately 232,000 gross (213,000 net) acres in the Utica Shale primarily in Eastern Ohio. We spud our first well, the Wagner 1-28H, on our Utica Shale acreage in February 2012 and, as of December 31, 2016 , had spud 268 gross wells, 219 of which were completed and were producing. In 2016 , we spud 50 gross (43.5 net) wells, of which 16 were completed as producing wells, two were non-productive, and as of December 31, 2016 , 26 were in various stages of completion and six were still being drilled. We commenced sales from 54 gross wells (40.2 net wells) in the Utica Shale during 2016 . During 2017 (through February 10, 2017 ), we spud ten gross (9.2 net) wells. As of February 10, 2017 , four of these wells were waiting on completion and the other six were still drilling. In addition, other operators drilled 35 gross (6.9 net) wells and commenced sales from 25 gross (6.3 net) wells on our Utica Shale acreage in 2016 . 
+We currently intend to drill 87 to 97 gross (67 to 74 net) horizontal wells, and commence sales from 72 to 80 gross (61 to 67 net) horizontal wells on our Utica Shale acreage in 2017 . We currently anticipate 30 to 34 gross (10 to 11 net) horizontal wells will be drilled, and sales commenced from 42 to 46 gross (nine to 10 net) horizontal wells, by other operators on our Utica Shale acreage. We currently expect our anticipated operated and non-operated activity during 2017 to cost us $645.0 million to $690.0 million. 
+Aggregate net production from our Utica Shale acreage during the three months ended December 31, 2016 was approximately 70,653 net million cubic feet of natural gas equivalent, or MMcfe, or 768.0 MMcfe per day, of which 89% was from natural gas and 11% was from oil and natural gas liquids, or NGLs. 
+In 2016 , at our WCBB field, we recompleted 54 gross and net wells and spud no new wells. In the fourth quarter of 2016 , production at WCBB was approximately 1,272 MMcfe, or an average of 13.8 MMcfe per day, of which 99% was from oil and 1% was from natural gas. 
+In 2016 , at our East Hackberry field, we recompleted 23 gross and net wells and spud no new wells. In the fourth quarter of 2016 , net production at East Hackberry was approximately 334 MMcfe, or an average of 3.6 MMcfe per day, of which 97% was from oil and 3% was from natural gas. 
+In 2016 , at our West Hackberry field, we had no recompletions and spud no new wells. In the fourth quarter of 2016 , net production at West Hackberry was approximately 45 MMcfe, or an average of 492.8 thousand cubic feet of natural gas equivalent, or Mcfe, per day, of which 99% was from oil and 1% was from natural gas. 
+We currently estimate our 2017 activities in our Southern Louisiana fields to be approximately $30.0 million to $35.0 million in aggregate to drill 12 to 15 gross and net wells and perform recompletion activities. 
+As of December 31, 2016 , we held leasehold interests in approximately 4,000 net acres in the Niobrara Formation in Northwestern Colorado. During the year ended December 31, 2016 , there were no wells spud on our Niobrara Formation acreage. In the fourth quarter of 2016 , net production from our Niobrara Formation acreage was approximately 26 MMcfe, or 
+2 
+Table of Contents 
+Index to Financial Statements 
+an average of 277.8 Mcfe per day, 100% of which was from oil. During 2017 , we currently do not anticipate drilling any wells in the Niobrara Formation. 
+As of December 31, 2016 , we held leasehold interests in approximately 778 net acres in the Bakken Formation of Western North Dakota and Eastern Montana, interests in 18 wells and overriding royalty interests in certain existing and future wells. In the fourth quarter of 2016 , our net production from this acreage was approximately 71 MMcfe, or an average of 773.5 Mcfe per day, of which 80% was from oil, 16% was from natural gas and 4% was from natural gas liquids. 
+We, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.9% interest in Grizzly. As of December 31, 2016 , Grizzly had approximately 830,000 net acres under lease in the Athabasca, Peace River and Cold Lake oil sands regions of Alberta, Canada. For additional information regarding Grizzly, see "- Our Equity Investments–Grizzly Oil Sands " below. 
+We own a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex II. Tatex II, a privately held entity, holds an 8.5% interest in APICO, LLC, or APICO, an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering approximately 180,000 acres which includes the Phu Horm Field. For additional information regarding Tatex II and our other activities in Southeast Asia, see "- Our Equity Investments–Thailand " below. 
+In an effort to facilitate the development of our Utica Shale and other domestic acreage, we have invested in entities that can provide services that are required to support our operations. For additional information regarding these entities, see "- Our Equity Investments–Other Investments " below. 
+As of December 31, 2016 , we had 2.3 Tcfe of proved reserves with a present value of estimated future net revenues, discounted at 10%, or PV-10, of approximately $696.0 million and associated standardized measure of discounted future net cash flows of approximately $688.0 million , excluding reserves attributable to our interests in Grizzly, Tatex II and Tatex III. See Item 2. " Properties-Proved Oil and Natural Gas Reserves ” for our definition of PV-10 (a non-GAAP financial measure) and a reconciliation of our standardized measure of discounted future net cash flows (the most directly comparable GAAP measure) to PV-10. 
+Principal Oil and Natural Gas Properties 
+The following table presents certain information as of December 31, 2016 reflecting our net interest in our principal producing oil and natural gas properties in the Utica Shale primarily in Eastern Ohio, along the Louisiana Gulf Coast, in the Niobrara Formation in Northwestern Colorado and in the Bakken Formation in Western North Dakota and Eastern Montana. 
+Proved Reserves 
+Field 
+NRI/WI (1) 
+Productive 
+Wells 
+Non-Productive 
+Wells 
+Developed 
+Acreage (2) 
+Gas 
+Oil 
+NGLs 
+Total 
+Percentages 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+MMcf 
+MBbls 
+MBbls 
+MMcfe 
+Utica Shale (3) 
+40.33/49.28 
+393 
+193.84 
+5 
+4.23 
+48,523 
+41,081 
+2,165,739 
+2,798 
+20,126 
+2,303,282 
+West Cote Blanche Bay Field (4) 
+80.108/100 
+116 
+116 
+145 
+145 
+5,668 
+5,668 
+865 
+2,039 
+— 
+13,096 
+E. Hackberry Field (5) 
+82.04/100 
+25 
+25 
+119 
+119 
+2,910 
+2,910 
+210 
+356 
+— 
+2,349 
+W. Hackberry Field 
+80.357/100 
+7 
+7 
+6 
+6 
+726 
+726 
+— 
+72 
+— 
+433 
+Niobrara Formation 
+34.52/48.61 
+3 
+1.46 
+1 
+0.41 
+2,100 
+1,050 
+89 
+157 
+— 
+1,029 
+Bakken Formation 
+1.51/1.83 
+18 
+0.3 
+— 
+— 
+386 
+77 
+153 
+123 
+1 
+899 
+Overrides/Royalty Non-operated 
+Various 
+583 
+0.77 
+— 
+— 
+— 
+— 
+12 
+1 
+— 
+20 
+Total 
+1,145 
+344.37 
+276 
+274.64 
+60,313 
+51,512 
+2,167,068 
+5,546 
+20,127 
+2,321,108 
+(1) 
+Net Revenue Interest (NRI)/Working Interest (WI) for producing wells. 
+(2) 
+Developed acres are acres spaced or assigned to productive wells. Approximately 23% of our acreage is developed acreage and has been held by production. 
+(3) 
+Includes NRI/WI from wells that have been drilled or in which we have elected to participate. Includes 174 gross (22.25 net) wells drilled by other operators on our acreage. 
+3 
+Table of Contents 
+Index to Financial Statements 
+(4) 
+We have a 100% working interest (80.108% average NRI) from the surface to the base of the 13900 Sand which is located at 11,320 feet. Below the base of the 13900 Sand, we have a 40.40% non-operated working interest (29.95% NRI). 
+(5) 
+NRI shown is for producing wells. 
+Utica Shale (primarily in Eastern Ohio) 
+Location and Land 
+As of December 31, 2016 , we held leasehold interests in approximately 232,000 gross (213,000 net) acres in the Utica Shale. 
+Area History 
+The Ohio Department of Natural Resources reported that in the Utica Shale in Ohio, as of December 31, 2016, there were 1,472 producing horizontal wells, 256 horizontal wells that had been drilled but were not yet completed or connected to a pipeline, 19 horizontal wells that were being drilled and an additional 460 horizontal wells that had been permitted. 
+Geology 
+The Utica Shale is located in the Appalachian Basin of the United States and Canada. The Utica Shale is a rock unit comprised of organic-rich calcareous black shale that was deposited about 440 million to 460 million years ago during the Late Ordovician period. It overlies the Trenton Limestone and is located a few thousand feet below the Marcellus Shale. 
+Recently, the application of horizontal drilling, combined with multi-staged hydraulic fracturing to create permeable flow paths from shale units into wellbores, has resulted in increased drilling activity and production in the Devonian-age Marcellus Shale and the Ordovician-age Utica Shale in the Appalachian Basin states of Pennsylvania, West Virginia, Southern New York and Eastern Ohio. This proven technology has potential for application in other shale units which extend across much of the Appalachian Basin region. 
+The Utica Shale is estimated to be thicker and more geographically extensive than the Marcellus Shale. The source rock portion of the Utica Shale underlies portions of Kentucky, Maryland, New York, Ohio, Pennsylvania, Tennessee, West Virginia and Virginia in the United States and is also present beneath parts of Lake Ontario, Lake Erie and Ontario, Canada. Throughout this area, the Utica Shale ranges in thickness from less than 100 feet to over 500 feet. There is a general thinning from east to west. 
+The Utica Shale is also significantly deeper than the Marcellus Shale. In some parts of Pennsylvania, the Utica Shale is estimated to be over two miles below sea level and up to 7,000 feet below the Marcellus Shale. However, the depth of the Utica Shale decreases to the west into Ohio and to the northwest under the Great Lakes and into Canada to less than 2,000 feet below sea level. 
+The Utica Shale is estimated to have higher carbonate and lower clay mineral content than the Marcellus Shale. The difference in mineralogy generally produces a different response to hydraulic fracturing treatments. Operators in the Utica play continue to refine completions techniques to optimize productivity. 
+Facilities 
+There are standard land oil and natural gas processing facilities in the Utica Shale. Our facilities located at well site pads include storage tank batteries, oil/gas/water separation equipment, vapor recovery units, line heaters, compression emission control devices and applicable metering. 
+Recent and Future Activities 
+We spud our first well, the Wagner 1-28H, on our Utica Shale acreage in February 2012 and, as of December 31, 2016 , had spud 268 gross wells, 219 of which were completed and were producing. In 2016 , we spud 50 gross (43.5 net) wells, of which 16 were completed as producing wells and two were non-productive, and as of December 31, 2016 , 26 were in various stages of completion and six were still being drilled. We commenced sales from 54 gross wells (40.2 net wells) in the Utica Shale during 2016 . During 2017 (through February 10, 2017 ), we spud ten gross (9.2 net) wells. As of February 10, 2017 , four of these 
+4 
+Table of Contents 
+Index to Financial Statements 
+wells were waiting on completion and the other six were still drilling. In addition, other operators drilled 35 gross (6.9 net) wells and commenced sales from 25 gross (6.3 net) wells on our Utica Shale acreage in 2016 . 
+We currently intend to drill 87 to 97 gross (67 to 74 net) horizontal wells, and commence sales from 72 to 80 gross (61 to 67 net) horizontal wells, on our Utica Shale acreage in 2017 . We currently anticipate 30 to 34 gross (10 to 11 net) horizontal wells will be drilled, and sales commenced from 42 to 46 gross (nine to 10 net) horizontal wells, by other operators on our Utica Shale acreage during 2017 . We currently anticipate our 2017 capital expenditures to be $645.0 million to $690.0 million related to our operated and non-operated Utica Shale activities. As of February 10, 2017 , we had six operated horizontal rigs drilling in the play. 
+Production Status 
+Aggregate net production from our Utica Shale acreage during the three months ended December 31, 2016 was approximately 70,653 net million cubic feet of natural gas equivalent, or MMcfe, or 768.0 MMcfe per day, of which 89% was from natural gas and 11% was from oil and natural gas liquids. 
+West Cote Blanche Bay Field 
+Location and Land 
+The WCBB field is located approximately five miles off the coast of Louisiana in a shallow bay with water depths averaging eight to ten feet. We own a 100% working interest (80.108% net revenue interest, or NRI), and are the operator, in depths above the base of the 13900 Sand which is located at 11,320 feet. In addition, we own a 40.40% non-operated working interest (29.95% NRI) in depths below the base of the 13900 Sand, which is operated by Chevron Corporation. Our leasehold interests at WCBB contain 5,668 gross acres. 
+Area History and Production 
+Texaco, now Chevron Corporation, drilled the discovery well in this field in 1940 based on a seismic and gravitational anomaly. WCBB was subsequently developed on an even 160-acre pattern for much of the remainder of the decade. Developmental drilling continued and reached its peak in the 1970s when over 300 wells were drilled in the field. Of the 1,077 wells drilled as of December 31, 2016 , 973 were completed as producing wells. From the date of our acquisition of WCBB in 1997 through December 31, 2016 , we drilled 265 new wells, 233 of which were productive, for an 88% success rate. As of December 31, 2016 , estimated field cumulative gross production was 199 MMBO and 237.2 Bcf of gas. Of the 1,077 wells drilled in WCBB as of December 31, 2016 , 116 were producing, 145 were shut-in, and six were being used as salt water disposal wells. The other 810 wells have been plugged and abandoned. 
+Geology 
+WCBB overlies one of the largest salt dome structures on the Gulf Coast. The field is characterized by a piercement salt dome, which created traps from the Pleistocene through the Miocene formations. The relative movements affected deposition and created a complex system of fault traps. The compensating fault sets generally trend northwest to southeast and are intersected by sets having a major radial component. Later-stage movement caused extension over the dome and a large graben system (a downthrown area bounded by normal faults) was formed. 
+There are over 100 distinct sandstone reservoirs recognized throughout most of the field, and nearly 200 major and minor discrete intervals have been tested. Within the 1,077 wells that had been drilled in the field as of December 31, 2016 , over 4,000 potential zones have been penetrated. These sands are highly porous and permeable reservoirs primarily with a strong water drive. 
+WCBB is a structurally and stratigraphically complex field. All of the proved undeveloped, or PUD, locations at WCBB are adjacent to faults and abut at least one fault. Our drilling programs are designed to penetrate each PUD trap with a new wellbore in a structurally optimum position, usually very close to the fault seal. The majority of these wells have been, and new wells drilled in connection with our drilling programs will be, directionally drilled using steering tools and downhole motors. The tolerance for error in getting near the fault is low, so the complex faulting does introduce the risk of crossing the fault before encountering the zone of interest, which could result in part or all of the zone being absent in the borehole. This, in turn, can result in lower than expected or no reserves for that zone. The new wellbores eliminate the mechanical risk associated with trying to produce the zone from an old existing wellbore, while the wellbore locations are selected in an effort to more 
+5 
+Table of Contents 
+Index to Financial Statements 
+efficiently drain each reservoir. The vast majority of the PUD targets are up-dip offsets to wells that produced from a sub-optimal position within a particular zone. 
+Facilities 
+We own and operate a production facility at WCBB that includes four production tank batteries, seven natural gas compressors, a storage barge facility, a dock, a dehydration unit and a salt water disposal system. 
+Recent Activity 
+In 2016 , at our WCBB field, we recompleted 54 gross and net wells and spud no new wells. As of February 10, 2017 , we had recompleted 14 gross and net wells during 2017 in our WCBB field. 
+Production Status 
+In the fourth quarter of 2016 , our net production at WCBB was approximately 1,272 MMcfe, or an average of 13.8 MMcfe per day, of which 99% was from oil and 1% was from natural gas. 
+East Hackberry Field 
+Location and Land 
+The East Hackberry field in Louisiana is located along the western shore and the land surrounding Lake Calcasieu, 15 miles inland from the Gulf of Mexico. We own a 100% working interest (approximately 82.04% average NRI) in certain producing oil and natural gas properties situated in the East Hackberry field. As of December 31, 2016 , we held beneficial interests in approximately 4,116 acres, including the Erwin Heirs Block, which is located on land, and the adjacent State Lease 50 Block, which is located primarily in the shallow waters of Lake Calcasieu. 
+Area History and Production 
+The East Hackberry field was discovered in 1926 by Gulf Oil Company, now Chevron Corporation, by a gravitational anomaly survey. The massive shallow salt stock presented an easily recognizable gravity anomaly indicating a productive field. Initial production began in 1927 and has continued to the present. The estimated cumulative oil and condensate production through 2016 was over 4,758 MBO and 332 Bcf of casinghead gas production. A total of 269 wells have been drilled on our portion of the field. As of December 31, 2016 , 25 wells had daily production, 119 were shut-in and three had been converted to salt water disposal wells. The remaining 122 wells had been plugged and abandoned. 
+Geology 
+The Hackberry field is a major salt intrusive feature, elliptical in shape as opposed to a classic “dome,” divided into east and west field entities by a saddle. Structurally, our East Hackberry acreage is located on the eastern end of the Hackberry salt ridge. There are over 30 pay zones at this field. The salt intrusion formed a series of structurally complex and steeply dipping fault blocks in the Lower Miocene and Oligocene age rocks. These fault blocks serve as traps for hydrocarbon accumulation. Our wells currently produce from perforations found between 5,100 and 12,200 feet. 
+Facilities 
+We have a field office that serves both the East and West Hackberry fields. In addition, we own and operate three production facilities at East Hackberry that include two land based tank batteries, a production barge, three natural gas compressors, dehydration units and salt water disposal systems. 
+Recent Activity 
+During 2016 at East Hackberry, we recompleted 23 gross and net wells and spud no new wells. As of February 10, 2017 , we had recompleted two gross and net wells during 2017 in our East Hackberry field. 
+6 
+Table of Contents 
+Index to Financial Statements 
+Production Status 
+In the fourth quarter of 2016 , our net production at East Hackberry was approximately 334 MMcfe, or an average of 3.6 MMcfe per day, of which 97% was from oil and 3% was from natural gas. 
+West Hackberry Field 
+Location and Land 
+The West Hackberry field is located on land and is five miles west of Lake Calcasieu in Cameron Parish, Louisiana, approximately 85 miles west of Lafayette and 15 miles inland from the Gulf of Mexico. We own a 100% working interest (approximately 80.00% NRI) in 1,032 acres within the West Hackberry field. Our leases at West Hackberry are located within two miles of one of the United States Department of Energy's Strategic Petroleum Reserves. 
+Area History 
+The first discovery well at West Hackberry was drilled in 1938 and the field was developed by Superior Oil Company, now ExxonMobil Corporation, between 1938 and 1988. The estimated cumulative oil and condensate production through 2016 was 493 MBO and 140 Bcf of natural gas. As of December 31, 2016 , 41 wells had been drilled on our portion of West Hackberry. As of December 31, 2016 , seven of such wells were producing, six were shut-in and one had been converted to a saltwater disposal well. The remaining 27 wells have been plugged and abandoned. 
+Geology 
+Structurally, our West Hackberry acreage is located on the western end of the Hackberry salt ridge. There are over 30 pay zones at this field. West Hackberry consists of a series of fault-bounded traps in the Oligocene-age Vincent and Keough sands associated with the Hackberry Salt Ridge. Recoveries from these thick, porous, water-drive reservoirs have resulted in per well cumulative production of almost 700 MBOE. 
+Recent Activity 
+During 2016 at West Hackberry, we had no recompletions and spud no new wells. 
+Production Status 
+In the fourth quarter of 2016 , our net production at West Hackberry was approximately 45 MMcfe, or an average of 492.8 Mcfe per day, of which 99% was from oil and 1% was from natural gas. 
+Facilities 
+We own and operate a production facility at West Hackberry that includes a land based tank battery and salt water disposal system. 
+Niobrara Formation (Northwestern Colorado) 
+Location and Land 
+Effective as of April 1, 2010, we acquired leasehold interests in the Niobrara Formation in Northwestern Colorado and, as of December 31, 2016 , we held leases for approximately 4,000 net acres. In 2016 , no wells were spud on our Niobrara Formation acreage. 
+Area History 
+The Niobrara Formation is a shale oil rock formation located in Colorado, Northwest Kansas, Southwest Nebraska, and Southeast Wyoming. Oil and natural gas can be found at depths of 3,000 to 14,000 feet and is drilled both vertically and horizontally. The Upper Cretaceous Niobrara Formation has emerged as another potential crude oil resource play in various basins throughout the northern Rocky Mountain region. As with most resource plays, the Niobrara Formation has a history of producing through conventional technology with some of the earliest production dating back to the early 1900s. Natural 
+7 
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+Index to Financial Statements 
+fracturing has played a key role in producing the Niobrara Formation historically due to the low porosity and low permeability of the formation. Because of this, conventional production has been very localized and limited in area extent. We believe the Niobrara Formation can be produced on a more widespread basis using today's horizontal multi-stage fracture stimulation technology where the Niobrara Formation is thermally mature. 
+Geology 
+The Niobrara Formation oil play in Northwestern Colorado is located between the Piceance Basin to the south and the Sand Wash Basin to the north. Rocks mainly consist of interbedded organic-rich shales, calcareous shales and marlstones. It is the fractured marlstone intervals locally known as the Buck Peak, Tow Creek and Wolf Mountain benches that account for the majority of the area's production. These fractured carbonate reservoirs are associated with anticlinal, synclinal and monoclinal folds, and fault zones. This proven oil accumulation is considered to be continuous in nature and lightly explored. Source rocks are predominantly oil prone and thermally mature with respect to oil generation. The producing intervals are geologically equivalent to the Niobrara Formation reservoirs of the DJ and Powder River Basins, which are currently emerging as a major crude resource play. 
+Production Status 
+In the fourth quarter of 2016 , net production from our Niobrara Formation acreage was approximately 26 MMcfe, or an average of 277.8 Mcfe per day, 100% of which was from oil. 
+Facilities 
+There are typical land oil and natural gas processing facilities in the Niobrara Formation. Our facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units. 
+Recent Activity 
+There were no new wells drilled on our Niobrara Formation acreage in 2016 . We do not anticipate drilling any wells in the Niobrara Formation during 2017 . 
+Bakken Formation 
+Location and Land 
+The Bakken Formation is located in the Williston Basin areas of Western North Dakota and Eastern Montana. As of December 31, 2016 , we held approximately 778 net acres, interests in 18 wells and overriding royalty interests in certain existing and future wells. 
+Production Status 
+In the fourth quarter of 2016 , our net production from this acreage was approximately 71 MMcfe, or an average of 773.5 Mcfe per day, of which 80% was from oil, 16% was from natural gas and 4% was from natural gas liquids. 
+Facilities 
+There are typical land, oil and natural gas processing facilities in the Williston Basin. The facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units. 
+Recent Activities 
+There were no new wells drilled on our Bakken Formation acreage in 2016 . We do not anticipate drilling any wells in the Bakken Formation during 2017 . 
+8 
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+Index to Financial Statements 
+Additional Properties 
+Louisiana . In addition to our interests in the WCBB, East Hackberry and West Hackberry fields, we also own working interests and overriding royalty interest in various fields in Louisiana, Texas and Oklahoma as described in the following table as of December 31, 2016 : 
+Field 
+State 
+Parish/County 
+Acreage Working 
+Interest 
+Overriding Royalty 
+Interests 
+Producing 
+Wells 
+Non-Producing 
+Wells 
+Deer Island 
+Louisiana 
+Terrebonne 
+3.125 
+% 
+— 
+1 
+— 
+Napoleonville 
+Louisiana 
+Assumption 
+— 
+2.5 
+% 
+3 
+— 
+Crest 
+Texas 
+Ochiltree 
+2 
+% 
+— 
+1 
+— 
+Eagle City South 
+Oklahoma 
+Dewey 
+1.04 
+% 
+— 
+1 
+— 
+Fay South 
+Oklahoma 
+Blaine 
+0.301 
+% 
+— 
+1 
+— 
+Squaw Cheek 
+Oklahoma 
+Blaine 
+0.13 
+% 
+— 
+1 
+— 
+Watonga Chickasha Trend 
+Oklahoma 
+Canadian 
+0.052 
+% 
+— 
+1 
+— 
+Green River Basin 
+Colorado 
+Moffat 
+0.0686 
+% 
+— 
+1 
+— 
+Our Pending Acquisition 
+We have entered into a purchase agreement, dated as of December 13, 2016, with Vitruvian II Woodford, LLC, an unrelated third-party seller, referred to herein as the Seller or Vitruvian, to acquire certain assets of the Seller for a total purchase price consisting of $1.35 billion in cash and approximately 23.9 million in shares of our common stock, subject to certain adjustments, which we refer to herein as the Pending Acquisition. The assets subject to the Pending Acquisition include 46,400 net surface acres, with multiple producing zones including the Woodford and Springer formations, in Grady, Stephens and Garvin Counties, Oklahoma. Given the potential for numerous producing intervals across this acreage, we have identified approximately 1,750 gross drilling locations, comprised of only Woodford and Springer zones with significant upside potential through infill drilling and additional prospective zones present on the acreage. The properties subject to the Pending Acquisition are located primarily in the over-pressured liquids-rich to dry gas windows of the SCOOP play and include approximately 183 MMcfe per day of net production for October 2016, based on information provided by the Seller. The Pending Acquisition also includes 48 producing horizontal wells and an additional interest in over 150 non-operated horizontal wells. Four rigs are currently operating on the acreage and we intend to maintain a four-rig cadence in the play during 2017. Based on the estimates prepared by the Seller as of September 30, 2016 and audited by Netherland, Sewell & Associates, Inc., or NSAI, the estimated proved reserves attributable to the acreage subject to the Pending Acquisition are approximately 1.1 Tcfe. These estimates are internal estimates prepared by the Seller, and we may revise such estimates following the completion of the Pending Acquisition. We do not currently hold any leasehold interests or have any operations in the SCOOP play. The Pending Acquisition is expected to provide basin diversification to our operations. We intend to fund the cash portion of the purchase price of the Pending Acquisition with the net proceeds from the December 2016 common stock and senior note offerings and cash on hand. We anticipate completing the Pending Acquisition in February 2017. However, the Pending Acquisition remains subject to completion of due diligence and satisfaction or waiver of other closing conditions. There can be no assurance that the Pending Acquisition will be completed or that we will acquire all or any portion of the acreage subject to the Pending Acquisition. See Item 1A. " Risk Factors - Risks Relating to the Pending Acquisition ." 
+Our Equity Investments 
+Grizzly Oil Sands . We, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.9% interest in Grizzly. As of December 31, 2016 , Grizzly had approximately 830,000 net acres under lease in the Athabasca, Peace River and Cold Lake oil sands regions of Alberta, Canada. Grizzly has three oil sands projects in various stages of development. Grizzly commenced commercial production from its Algar Lake Phase 1 steam-assisted gravity drainage, or SAGD, oil sand project during the second quarter of 2014 and has received regulatory approval for up to 11,300 barrels per day of bitumen production. Grizzly produced approximately 900 barrels of bitumen per day at its Algar Lake SAGD project during the first quarter of 2015. In April 2015, Grizzly determined to cease bitumen production at its Algar Lake facility due to the level of commodity prices. Grizzly continues to monitor market conditions as it assesses future plans for the facility. We reviewed our investment in Grizzly as of September 30, 2015 and December 31, 2015 , and again at March 31, 2016 , for impairment based on FASB ASC 323-Investments: Equity Method and Joint Ventures, or FASB ASC 323, due to certain qualitative factors and engaged an independent third party to assist management in determining fair value calculations of its investment. As a result of the calculated fair values and other qualitative factors, we concluded that an other than temporary impairment was required under 
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+Index to Financial Statements 
+FASB ASC 323, resulting in an aggregate impairment loss of $101.6 million for the year ended December 31, 2015 and $23.1 million for the for the year ended December 31, 2016 . As of and during the period ended December 31, 2016 , commodity prices had increased as compared to the quarter ended March 31, 2016 , and there were no impairment indicators that required further evaluation for impairment. If commodity prices decline again in the future, further impairment of our investment in Grizzly may result. In the first quarter of 2012, Grizzly acquired the May River property comprising approximately 47,000 acres. An initial 12,000 barrel per day development application was filed with the regulatory authorities in the fourth quarter of 2013, covering the eastern portion of the May River lease. The development application continues to move through the regulatory process and is expected to be approved in the first half of 2017. In the first quarter of 2014, a 2-D seismic program covering approximately 83 kilometers was completed to more fully define the resource over the remaining lease beyond the development application area. At the Thickwood thermal project, a development application for a 12,000 barrel per day oil sands project was filed in the fourth quarter of 2012. Since then, the Alberta Energy Regulator, or AER, announced it is implementing a policy for future regulatory requirements for reservoir containment in shallow SAGD areas, which impacts the Thickwood application. Additional work to advance the Thickwood application will be required and is expected to be addressed once the May River development approval is received. In December 2015, Grizzly suspended the review of the Thickwood application by the AER. The Thickwood application will be resubmitted once the regulations have been updated. Grizzly has also developed delineation drilling, seismic and regulatory work plans at its Cadotte, Peace River property. Grizzly continues to pursue a rail marketing strategy to ensure consistent and flexible access to premium markets for its production, including its Windell truck to rail terminal located near Conklin, Alberta, which commenced transloading blended bitumen production from Algar Lake on to rail cars for delivery to the US Gulf Coast markets in the second quarter of 2014. 
+Thailand . We own a 23.5% ownership interest in Tatex II. Tatex II, a privately held entity, holds an 8.5% interest in APICO, an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering approximately 180,000 acres which includes the Phu Horm Field. Our investment is accounted for on the equity method. Tatex II accounts for its investment in APICO using the cost method. In December 2006, first gas sales were achieved at the Phu Horm field located in northeast Thailand. Phu Horm's initial gross production was approximately 60 MMcf per day. For 2016, net gas production was approximately 118 MMcf per day and condensate production was 435 barrels per day. PTT Exploration and Production Public Company Limited operates the field with a 55% interest. Other interest owners include APICO (35% interest) and ExxonMobil (10% interest). Our gross working interest (through Tatex II as a member of APICO) in the Phu Horm field is 0.7%. Since our ownership in the Phu Horm field is indirect and Tatex II's investment in APICO is accounted for by the cost method, these reserves are not included in our year-end reserve information. 
+Other Investments . In an effort to facilitate the development of our Utica Shale and other domestic acreage, we have invested in entities that can provide services that are required to support our operations. In 2012, we participated in the formation of Stingray Pressure Pumping LLC, or Stingray Pressure, and Stingray Logistics LLC, or Stingray Logistics, with an initial ownership interest in each entity of 50%. These entities provide well completion and other well services. In 2011 and 2012, we acquired an aggregate 40% equity interest in Bison Drilling and Field Services LLC, or Bison, which owns and operates drilling rigs and related equipment. Also in 2011, we acquired a 25% interest in Muskie Proppant LLC, or Muskie, which is engaged in the processing and sale of hydraulic fracturing grade sand. In the fourth quarter of 2014, we contributed our investments in Stingray Pressure, Stingray Logistics, Bison and Muskie to Mammoth Energy Partners LP, or Mammoth, in exchange for a 30.5% limited partner interest in this newly formed limited partnership. On October 19, 2016, Mammoth Energy Services, Inc., or Mammoth Energy, which is the parent company of Mammoth, completed its initial public offering, or the IPO, of 7,750,000 shares of its common stock at a public offering price of $15.00 per share, of which 7,500,000 shares were sold by Mammoth Energy and 250,000 shares were sold by certain selling stockholders, including 76,250 shares sold by us for which we received net proceeds of $1.1 million. Prior to the completion of the IPO, we were issued 9,150,000 shares of Mammoth Energy common stock in return for the contribution of our 30.5% interest in Mammoth Energy Partners LLC (as the sucessor to Mammoth). We intend to use the net proceeds for the sale of our Mammoth Energy shares in the IPO for general corporate purposes. As of December 31, 2016 , we owned an approximate 24.2% interest in Mammoth Energy. 
+In 2013, we participated in the formation of Stingray Energy Services LLC, or Stingray Energy, with an initial ownership interest of 50%. Stingray Energy provides rental tools for land-based oil and natural gas drilling, completion and workover activities as well as the transfer of fresh water to wellsites. In 2012, we participated in the formation of Stingray Cementing LLC, or Stingray Cementing, with an initial ownership of 50%. Stingray Cementing provides well completion and other well services. In 2012, we also participated in the formation of Blackhawk Midstream LLC, or Blackhawk, and Timber Wolf Terminals LLC, or Timber Wolf, with an initial ownership interest of 50% in each entity. Blackhawk coordinates gathering, compression, processing and marketing activities in connection with the development of our Utica Shale acreage and Timber Wolf will operate a crude/condensate terminal and a sand transloading facility in Ohio. Also in 2012, we acquired a 22.5% equity interest in Windsor Midstream LLC, or Midstream, which owned a 28.4% equity interest in a gas processing plant in 
+10 
+Table of Contents 
+Index to Financial Statements 
+West Texas. In 2014, we acquired a 25% equity interest in Sturgeon Acquisitions LLC, or Sturgeon. Sturgeon owns an entity that operates sand mines that produce hydraulic fracturing grade sand. 
+In February 2016, we, through our wholly owned subsidiary Gulfport Midstream Holdings, LLC, or Midstream Holdings, entered into an agreement with Rice Midstream Holdings LLC, or Rice, a subsidiary of Rice Energy Inc., to develop natural gas gathering assets in eastern Belmont County and Monroe County, Ohio, which we refer to as the dedicated areas. We own a 25% interest in the newly formed entity called Strike Force Midstream LLC, or Strike Force, and Rice acts as operator and owns the remaining 75% interest in Strike Force. Construction of the gathering assets, which is underway, is providing gathering services for an increasing number of Gulfport operated wells and connectivity of existing dry gas gathering systems and interchangeability of natural gas across our firm portfolio. The first phase of the project has been completed: a lateral that connects two existing dry gas gathering systems on which we currently flow the majority of our dry gas volumes. First flow commenced through this lateral on February 1, 2016. 
+See Note 4 to our consolidated financial statements included elsewhere in this report for additional information regarding these other investments. 
+Competition 
+The oil and natural gas industry is intensely competitive, and we compete 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 midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These competitors may be better positioned to take advantage of industry opportunities and to withstand changes affecting the industry, such as fluctuations in oil and natural gas prices and production, the availability of alternative energy sources and the application of government regulation. In addition, oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the availability or price of oil and natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas. 
+Marketing and Customers 
+The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control of our management, including but not limited to the demand for oil and natural gas and the level of domestic production and imports of oil, the proximity and capacity of gas pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of gas sold in interstate commerce. The oil and natural gas we produce in Louisiana is sold to purchasers who service the areas where our wells are located. We sell the majority of our Southern Louisiana oil to Shell Trading Company, or Shell. Shell takes custody of the oil at the outlet from our oil storage barge. The majority of this production is being sold under a West Texas Intermediate crude price HLS/LLS differential less transportation costs. The majority of our Utica Shale oil is sold to Marathon Petroleum Corporation, or Marathon. The purchaser takes custody at the MarkWest Utica EMG, or MarkWest, owned and operated condensate stabilizer located near Cadiz, Ohio. Our Utica Shale NGLs are currently purchased by MarkWest which remits to us a weighted average selling price of products sold to various markets. Our Utica Shale natural gas production is sold to various purchasers through established NAESBs with the counterparties. The majority of our gas is sold to BP Energy Company, or BP. In 2016, our Utica Shale natural gas and natural gas liquids were sold under monthly, seasonal and long term contracts and, as needed, through daily transactions. The majority of our production is delivered at the tailgate of the plants or at central delivery points with market pricing based on Platts Gas Daily - Appalachian - Dominion South Point (Dominion Eastern and Dominion Transmission) or Texas Eastern M2 Zone when sold in the Utica Basin. To maintain flow assurance and price stability, and as discussed under "– Transportation and Takeaway Capacity ," we have entered into agreements to transport a portion of our natural gas production out of the Utica Basin. These agreements have pricing based on the appropriate delivery point less transportation charges and fuel. 
+During the year ended December 31, 2016 , we sold approximately 68% and 10% of our natural gas production to BP and DTE Energy Trading, Inc., or DTE, respectively, 72% and 24% of our oil production to Shell and Marathon, respectively, and 74% and 23% of our natural gas liquids production to MarkWest and Antero Resources, or Antero, respectively. During the year ended December 31, 2015 , we sold approximately 79% and 14% of our natural gas production to BP and DTE, respectively, 90% and 10% of our oil production to Shell and Marathon, respectively, and 76% and 24% of our natural gas liquids production to MarkWest and Antero, respectively. During the year ended December 31, 2014 , we sold approximately 40% , 32% and 19% of our natural gas production to BP, DTE, and Hess, respectively, 99% of our oil production to Shell, 100% of our natural gas liquids production to MarkWest. 
+11 
+Table of Contents 
+Index to Financial Statements 
+As of December 31, 2016, we had an average of approximately 516,000 MMBtu per day of firm sales contracted with third parties for 2017. We had an average of approximately 257,000 MMBtu per day, 226,000 MMBtu per day, 223,000 MMBtu per day, 126,000 MMBtu per day and 31,000 MMBtu contracted with third parties for 2018, 2019, 2020, 2021 and thereafter, respectively. 
+Transportation and Takeaway Capacity 
+In Ohio, as of December 31, 2016, we had entered into firm transportation contracts to deliver approximately 775,000 MMBtu to 1,125,000 MMBtu per day for 2017. For 2018 through 2020, we had entered into firm transportation contracts to deliver approximately 1,125,000 MMBtu per day. We continuously monitor the need to secure additional firm transportation contracts for incremental volumes from our Utica Shale acreage but expect additional long term contracts to be limited in 2017. Our primary long-haul firm transportation commitments include the following: 
+• 
+520,000 MMBtu per day of firm capacity on Dominion East Ohio, which began in 2014 and allows us to reach additional connectivity to Gulf Coast and Midwest natural gas markets; 
+• 
+250,000 MMBtu per day of firm capacity on Dominion Transmission, which began in 2015 and allows us to reach additional connectivity to Midwest natural gas markets; 
+• 
+194,000 MMBtu per day of firm capacity on ANR Pipeline Company facilities, which began in 2014 and allows us to reach the Michigan, Chicago and Wisconsin natural gas markets; 
+• 
+200,000 MMBtu per day of firm capacity on Tennessee Gas Pipeline facilities, which began in 2015 and allows us to reach Gulf Coast delivery points; 
+• 
+275,000 MMBtu per day of firm capacity on Rockies Express Pipeline facilities, which began in 2015 and allows us to reach additional connectivity to Gulf Coast and Midwest markets; 
+• 
+50,000 MMBtu per day of firm capacity on Rockies Express Pipeline facilities, which went into partial service in December 2016 and full service in January 2017, allowing additional connectivity to Gulf Coast and Midwest markets; 
+• 
+20,000 MMBtu per day of firm capacity on Natural Gas Pipeline facilities which began in 2015 and allows us to reach Midwest markets; 
+• 
+50,000 MMBtu per day of firm capacity on Texas Gas Transmission facilities which began in 2016 allowing additional access to Gulf Coast delivery points; 
+• 
+54,000 MMBtu per day of firm capacity on Texas Gas Transmission facilities expected to begin in 2017 allowing additional access to Gulf Coast delivery points; 
+• 
+100,000 MMBtu per day of firm capacity on Texas Eastern Transmission facilities expected to begin in 2017 allowing additional access to Midwest delivery points; 
+• 
+150,000 MMBtu per day of firm capacity on Energy Transfer’s Rover Pipeline facilities expected to begin in 2017 allowing additional access to Canadian, Midwest and Gulf Coast delivery points; and 
+• 
+100,000 MMBtu per day of firm capacity on Columbia Gulf Transmission facilities expected to begin in late 2017 allowing additional access to Gulf Coast delivery points. 
+Under firm transportation contracts, we are obligated to deliver minimum daily volumes or pay fees for any deficiencies in deliveries. We continue to actively identify and evaluate additional takeaway capacity to facilitate production growth in our Utica Basin position. 
+Regulation 
+12 
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+Index to Financial Statements 
+Regulation of Oil and Natural Gas Production 
+Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability. 
+We own interests in producing oil and natural gas properties located in the Utica Shale primarily in Eastern Ohio, along the Louisiana Gulf Coast and in the Niobrara Formation in Northwestern Colorado and the Bakken Formation in Western North Dakota and Eastern Montana. The states in which our fields are located regulate the production and sale of oil and natural gas, including requirements for obtaining drilling permits, the method of developing fields and the spacing and operation of wells. In addition, regulations governing conservation matters aimed at preventing the waste of oil and natural gas resources could affect the rate of production and may include maximum daily production allowables for wells on a market demand or conservation basis. 
+Environmental Regulation 
+Our oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. Numerous governmental agencies, such as the U.S. Environmental Protection Agency, or the EPA, issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically or seismically sensitive areas, and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing earthen pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or related to our owned or operated facilities. Liability under such laws and regulations is often strict (i.e., no showing of “fault” is required) and can be joint and several. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. This trend, however, may not continue in the future. 
+Waste Handling . The Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent not-hazardous waste requirements. Moreover, the EPA or state or local governments may adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Also, in December 2016, the EPA agreed in a consent decree to review its regulation of oil and gas waste. It has until March 2019 to determine whether any revisions are necessary. Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses. 
+Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes, as presently classified, to be 
+13 
+Table of Contents 
+Index to Financial Statements 
+significant, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes. 
+Remediation of Hazardous Substances . The Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as CERCLA or the “Superfund” law, and analogous state laws, generally impose liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” are subject to strict liability that, in some circumstances, may be joint and several, for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous substances” have been released. 
+Water Discharges . The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” the Safe Drinking Water Act, the Oil Pollution Act, or OPA, and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. Spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. In addition, on June 28, 2016, EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants, which regulations are discussed in more detail below under the caption “ -Regulation of Hydraulic Fracturing .” Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. 
+The OPA is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict liability that, in some circumstances, may be joint and several for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters. 
+Noncompliance with the Clean Water Act or the OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws. 
+Air Emissions . The federal Clean Air Act, as amended, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, on August 16, 2012, the EPA published final regulations under the federal Clean Air Act that establish new emission controls for oil and natural gas production and processing operations, which regulations are discussed in more detail below under the caption “ -Regulation of Hydraulic Fracturing .” Also, on May 12, 2016, the EPA issued a final rule regarding the criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements. These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory 
+14 
+Table of Contents 
+Index to Financial Statements 
+agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects. 
+Climate Change . In December 2009, the EPA issued an Endangerment Finding that determined that emissions of carbon dioxide, methane and other greenhouse gases, or GHGs, present an endangerment to public health and the environment because, according to the EPA, emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. In May 2010, the EPA adopted regulations establishing new GHG emissions thresholds that determine when stationary sources must obtain permits under the Prevention of Significant Deterioration, or PSD, and Title V programs of the Clean Air Act. On June 23, 2014, in Utility Air Regulatory Group v. EPA , the Supreme Court held that stationary sources could not become subject to PSD or Title V permitting solely by reason of their GHG emissions. The Court ruled, however, that the EPA may require installation of best available control technology for GHG emissions at sources otherwise subject to the PSD and Title V programs. On August 26, 2016, the EPA proposed changes needed to bring EPA’s air permitting regulations in line with the Supreme Court’s decision on GHG permitting. The proposed rule was published in the Federal Register on October 3, 2016 and the public comment period closed on December 2, 2016. 
+The EPA also adopted a GHG reporting rule in September 2009 authorizing the collection of GHG data from large emission sources across a range of industry sectors. In November 2010, the EPA expanded the GHG reporting rule to include onshore and offshore oil and natural gas production and onshore processing, transmission, storage and distribution facilities, which may include certain of our facilities, beginning in 2012 for emissions occurring in 2011. In October 2015, the EPA amended the GHG reporting rule to add the reporting of GHG emissions from gathering and boosting systems, completions and workovers of oil wells using hydraulic fracturing, and blowdowns of natural gas transmission pipelines. 
+The EPA has continued to adopt GHG regulations applicable to other industries, such as its August 2015 adoption of three separate, but related, actions to address carbon dioxide pollution from power plants, including final Carbon Pollution Standards for new, modified and reconstructed power plants, a final Clean Power Plan to cut carbon dioxide pollution from existing power plants, and a proposed federal plan to implement the Clean Power Plan emission guidelines. Upon publication of the Clean Power Plan on October 23, 2015, more than two dozen States as well as industry and labor groups challenged the Clean Power Plan in the D.C. Circuit Court of Appeals. On February 9, 2016, the Supreme Court stayed the implementation of the Clean Power Plan while legal challenges to the rule proceed. As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility. In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Although the U.S. Congress has not adopted such legislation at this time, it may do so in the future and many states continue to pursue regulations to reduce greenhouse gas emissions. 
+In December 2015, the United States participated in the 21st Conference of the Parties, or COP-21, of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global temperature, and to conserve and enhance sinks and reservoirs of GHGs. The Agreement went into effect on November 4, 2016. The Agreement establishes a framework for the parties to cooperate and report actions to reduce GHG emissions. Also, on June 29, 2016, the leaders of the United States, Canada and Mexico announced an Action Plan to, among other things, boost clean energy, improve energy efficiency, and reduce greenhouse gas emissions. The Action Plan specifically calls for a reduction in methane emissions from the oil and gas sector by 40 to 45 percent by 2025. 
+Restrictions on emissions of methane or carbon dioxide that may be imposed could adversely affect the oil and natural gas industry. Currently, while we are subject to certain federal GHG monitoring and reporting requirements, our operations are not adversely impacted by existing federal, state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business. It also remains unclear whether and how the results of the 2016 U.S. election could impact the regulation of GHG emissions at the federal and state level. 
+In addition, claims have been made against certain energy companies alleging that GHG emissions from oil and natural gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals may seek to enforce environmental laws and regulations against us and could allege personal injury or property damages. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition. 
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+Index to Financial Statements 
+Moreover, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornados and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations. 
+Endangered Species Act 
+Environmental laws such as the Endangered Species Act, or the ESA and analogous state statutes, may impact exploration, development and production activities on public or private lands. The ESA provides broad protection for species of fish, wildlife and plants that are listed as threatened or endangered in the U.S., and restricts activities that may adversely affect listed species or their habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. Federal agencies are required to insure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed species or modify their critical habitat. While some of our facilities may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. The U.S. Fish and Wildlife Service may identify, however, previously unidentified endangered or threatened species or may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species, which could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas. 
+Occupational Safety and Health Act 
+We are also subject to the requirements of the Occupational Safety and Health Act, or OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements. 
+Regulation of Hydraulic Fracturing 
+Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. We use hydraulic fracturing extensively in the development of our Utica Shale acreage. The federal Safe Drinking Water Act, or SDWA, regulates the underground injection of substances through the Underground Injection Control, or UIC, program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions. However, legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection,” to require federal permitting and regulatory control of hydraulic fracturing, and to require disclosure of the chemical constituents of the fluids used in the fracturing process. Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program, specifically as “Class II” UIC wells. 
+In addition, the EPA plans to develop a Notice of Proposed Rulemaking by June 2018, which would describe a proposed mechanism - regulatory, voluntary, or a combination of both - to collect data on hydraulic fracturing chemical substances and mixtures. Also, on June 28, 2016, EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants. The EPA is also conducting a study of private wastewater treatment facilities (also known as centralized waste treatment, or CWT, facilities) accepting oil and gas extraction wastewater. The EPA is collecting data and information related to the extent to which CWT facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of CWT facilities, and the environmental impacts of discharges from CWT facilities. 
+On August 16, 2012, the EPA published final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes NSP standards to address emissions of sulfur dioxide and volatile organic compounds, or VOCs, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule seeks to achieve a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules also 
+16 
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+Index to Financial Statements 
+establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. In response, the EPA has issued, and will likely continue to issue, revised rules responsive to some of the requests for reconsideration. In particular, on May 12, 2016, the EPA amended its regulations to impose new standards for methane and VOC emissions for certain new, modified and reconstructed equipment, processes and activities across the oil and natural gas sector. On the same day, the EPA finalized a plan to implement its minor new source review program on Indian lands for oil and natural gas production, and it issued for public comment an information request that will require companies to provide extensive information instrumental for the development of regulations to reduce methane emissions from existing oil and gas sources. These standards, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or mandate the use of specific equipment or technologies to control emissions. 
+In addition, on March 26, 2015, the Bureau of Land Management, or BLM, published a final rule governing hydraulic fracturing on federal and Indian lands. The rule requires public disclosure of chemicals used in hydraulic fracturing, implementation of a casing and cementing program, management of recovered fluids, and submission to the BLM of detailed information about the proposed operation, including wellbore geology, the location of faults and fractures, and the depths of all usable water. On June 21, 2016, the United States District Court for Wyoming set aside the rule, holding that the BLM lacked Congressional authority to promulgate the rule. The BLM has appealed the decision to the Tenth Circuit Court of Appeals. Also, on November 15, 2016, the BLM finalized a rule to reduce the flaring, venting and leaking of methane from oil and gas operations on federal and Indian lands. The rule requires operators to use currently available technologies and equipment to reduce flaring, periodically inspect their operations for leaks, and replace outdated equipment that vents large quantities of gas into the air. The rule also clarifies when operators owe the government royalties for flared gas. State and industry groups have challenged this rule in federal court, asserting that the BLM lacks authority to prescribe air quality regulations. Congress is currently considering whether to repeal the rule pursuant to the Congressional Review Act. 
+Furthermore, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. On December 13, 2016, the EPA released a study examining the potential for hydraulic fracturing activities to impact drinking water resources, finding that, under some circumstances, the use of water in hydraulic fracturing activities can impact drinking water resources. Also, on February 6, 2015, the EPA released a report with findings and recommendations related to public concern about induced seismic activity from disposal wells. The report recommends strategies for managing and minimizing the potential for significant injection-induced seismic events. Other governmental agencies, including the U.S. Department of Energy, the U.S. Geological Survey, and the U.S. Government Accountability Office, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing, and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business. 
+Some states and local jurisdictions in which we operate or hold oil and natural gas interests have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids. If new or more stringent state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells. 
+There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal, state or local level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal, state or local laws governing hydraulic fracturing. 
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+Index to Financial Statements 
+Other Regulation of the Oil and Natural Gas Industry 
+The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production. 
+The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, natural gas storage and various other matters, primarily by the Federal Energy Regulatory Commission, or FERC. Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. FERC's regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas. 
+Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. We cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of condensate and natural gas liquids are not currently regulated and are made at market prices. 
+Drilling and Production . Our operations are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The states and some counties and municipalities in which we operate also regulate one or more of the following: 
+• 
+the location of wells; 
+• 
+the method of drilling and casing wells; 
+• 
+the timing of construction or drilling activities, including seasonal wildlife closures; 
+• 
+the rates of production or “allowables”; 
+• 
+the surface use and restoration of properties upon which wells are drilled; 
+• 
+the plugging and abandoning of wells; and 
+• 
+notice to, and consultation with, surface owners and other third parties. 
+State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. 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 requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or to limit the number of locations we can drill. 
+Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, 
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+decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements. 
+Natural Gas Sales and Transportation . Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production. Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. 
+FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and release of our natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC's initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities. 
+Under FERC’s current regulatory regime, transmission services are provided on an open-access, non-discriminatory basis at cost-based rates or at negotiated rates. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of transporting gas to point-of-sale locations. 
+Oil Sales and Transportation . Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future. 
+Our crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors. 
+Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines' published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors. 
+State Regulation . The states in which we operate regulate the drilling for, and the production and gathering of, oil and natural gas, including through requirements relating to the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may also regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill. 
+In July 2015, the Ohio Department of Natural Resources, or the ODNR, enacted a comprehensive set of rules to regulate the construction of well pads. Under these new rules, operators must submit detailed horizontal well pad site plans certified by a professional engineer for review by the ODNR Division of Oil and Gas Resources Management prior to the construction of a 
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+Index to Financial Statements 
+well pad. These rules will result in increased construction costs for operators. Furthermore, pursuant to new rules approved in August 2016, operators must immediately notify ODNR regarding certain oil or gas releases. 
+The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us. 
+Operational Hazards and Insurance 
+The oil and natural gas business involves a variety of operating risks, including the risk of fire, explosions, blow outs, pipe failures and, in some cases, abnormally high pressure formations which could lead to environmental hazards such as oil spills, natural gas leaks and the discharge of toxic gases. If any of these should occur, we could incur legal defense costs and could be required to pay amounts due to injury, loss of life, damage or destruction to property, natural resources and equipment, pollution or environmental damage, regulatory investigation and penalties and suspension of operations. 
+In accordance with what we believe to be industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We insure some, but not all, of our properties for operational and hurricane related events. We currently have insurance policies that include coverage for general liability, physical damage to our oil and natural gas properties, operational control of certain wells, oil pollution, third party liability, workers compensation and employers' liability and other coverage. Our insurance coverage includes deductibles that must be met prior to recovery. Additionally, our insurance is subject to exclusion and limitations, and there is no assurance that such coverage will fully or adequately protect us against liability from all potential consequences, damages and losses. Any of these events could cause a significant disruption to our business. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows. 
+Currently, we have general liability insurance coverage with an annual aggregate limit of up to $25.0 million which includes sudden and accidental pollution for the effects of onshore and offshore pollution on third parties arising from our operations as well as $10.0 million of gradual pollution insurance coverage. For our offshore WCBB properties, we also have a $40.0 million property physical damage policy which insures against most operational perils, such as explosions, fire, vandalism, theft, hail and windstorms, provided, however, that this policy is limited to $12.5 million for damages arising as a result of a named windstorm. All of our insurance coverage includes deductibles of up to $250,000 per occurrence ($1.25 million in the case of a named windstorm) that must be met prior to recovery. Additionally, our insurance is subject to customary exclusions and limitations. We reevaluate the purchase of insurance, policy terms and limits annually. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable and we may elect to maintain minimal or no insurance coverage. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. The occurrence of a significant event, not fully insured against, could have a material adverse effect on our financial condition and results of operations. 
+We carry control of well insurance for all of our Utica Shale wells and several Southern Louisiana wells. We also require all of our third party vendors to sign master service agreements in which they agree to indemnify us for injuries and deaths of the service provider's employees as well as contractors and subcontractors hired by the service provider. 
+We have prepared and have in place spill prevention control and countermeasure plans for each of our principal facilities in response to federal and state requirements. The plans are reviewed annually and updated as necessary. As required by applicable regulations, our facilities are built with secondary containment systems to capture potential releases. We also own additional spill kits with oil booms and absorbent pads that are readily available, if needed. In addition, we have emergency response companies on retainer. These companies specialize in the clean up of hydrocarbons as a result of spills, blow-outs and natural disasters, and are on call to us 24 hours a day, seven days a week when their services are needed. We pay these companies a retainer plus additional amounts when they provide us with clean up services. Our aggregate payments for the retainer and clean up services during each of 2016 and 2015 were approximately $0.1 million. While these companies have been able to meet our service needs when required from time to time in the past, it is possible that the ability of one or more of them to provide services to us in the future, if and when needed, could be hindered or delayed in the event of a widespread disaster. However, in light of the areas in which we operate and the nature of our production, we believe other companies would be available to us in the event our primary remediation companies are unable to perform. To supplement our planning and operation activities in Ohio, we also actively manage an incident response planning program and coordinate with applicable 
+20 
+Table of Contents 
+Index to Financial Statements 
+state agency personnel on spills and releases through Ohio's Incident Notification Hotline. We also participate in Ohio's Emergency Planning and Community Right to Know Act (EPCRA) program, which includes reporting of various materials used or stored on-site as well as notification to state and local emergency response centers, such as local fire departments, for emergency planning purposes. 
+Headquarters and Other Facilities 
+Construction of our new corporate headquarters in Oklahoma City, Oklahoma was completed in December of 2016. The building has approximately 120,000 square feet of office space and allows us to consolidate all of our employees in one location in Oklahoma City. We also own an approximately 28,500 square foot office building in Oklahoma City, Oklahoma that served as our previous corporate headquarters. We have received various offers to purchase or lease this building, which we are evaluating. 
+We also own an approximately 12,500 square foot building in Lafayette, Louisiana. This building contains approximately 6,200 square feet of finished office area and 6,300 square feet of clear span warehouse area. We lease approximately 3,700 square feet in a building in Lafayette that we use as our Louisiana headquarters. In 2016, we purchased an approximately 12,300 square feet building located in St. Clairsville, Ohio to serve as our headquarters for our Ohio operations. Each of these properties is suitable and adequate for its use. 
+Employees 
+At December 31, 2016 , we had 241 employees. 
+Availability of Company Reports 
+Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on the Investor Relations page of our website at www.gulfportenergy.com as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. Information contained on our website, or on other websites that may be linked to our website, is not incorporated by reference into this annual report on Form 10-K and should not be considered part of this report or any other filing that we make with the SEC.

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+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+For information concerning Item 13-Certain Relationships and Related Transactions, and Director Independence, see our definitive proxy statement, which will be filed with the Securities and Exchange Commission with 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference).

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+ITEM 9A. 
+CONTROLS AND PROCEDURES 
+Evaluation of Disclosure Control and Procedures . Under the direction of our Chief Executive Officer and President and our Chief Financial Officer, we have established disclosure controls and procedures that are designed to ensure that information required to be disclosed by us 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's rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and President and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures. 
+As of December 31, 2016 , an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and President and our Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and President and our Chief Financial Officer have concluded that, as of December 31, 2016 , our disclosure controls and procedures are effective. 
+Changes in Internal Control over Financial Reporting . There have not been any changes in our internal control over financial reporting that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting. 
+Management's Report on Internal Control Over Financial Reporting 
+Management is responsible for the fair presentation of the consolidated financial statements of Gulfport Energy Corporation. Management is also responsible for establishing and maintaining a system of adequate internal controls over financial reporting as defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. These internal controls are designed to provide reasonable assurance that the reported financial information is presented fairly, that disclosures are adequate and that the judgments inherent in the preparation of financial statements are reasonable. There are inherent limitations in the effectiveness of any system of internal control, including the possibility of human error and overriding of controls. Consequently, an effective internal control system can only provide reasonable, not absolute, assurance with respect to reporting financial information. 
+Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in the 2013 Internal Control-Integrated Framework , management did not identify any material weaknesses in our internal control over financial reporting and concluded that our internal control over financial reporting was effective as of December 31, 2016 . 
+Grant Thornton LLP, the independent registered public accounting firm that audited our financial statements for the year ended December 31, 2016 included with this Annual Report on Form 10-K, has also audited our internal control over financial reporting as of December 31, 2016 , as stated in their accompanying report. 
+75 
+Table of Contents 
+Index to Financial Statements 
+/s/ Michael G. Moore 
+/s/ Keri Crowell 
+Name: 
+Michael G. Moore 
+Name: 
+Keri Crowell 
+Title: 
+Chief Executive Officer and President 
+Title: 
+Chief Financial Officer 
+76 
+Table of Contents 
+Index to Financial Statements 
+Report of Independent Registered Public Accounting Firm 
+Board of Directors and Stockholders 
+Gulfport Energy Corporation: 
+We have audited the internal control over financial reporting of Gulfport Energy Corporation and subsidiaries (the “Company”) as of December 31, 2016 , based on criteria established in the 2013 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, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. 
+We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016 , based on criteria established in the 2013 Internal Control-Integrated Framework issued by COSO. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of the Company as of and for the year ended December 31, 2016 and our report dated February 14, 2017 expressed an unqualified opinion on those financial statements. 
+/s/ GRANT THORNTON LLP 
+Oklahoma City, Oklahoma 
+February 14, 2017 
+77 
+Table of Contents 
+Index to Financial Statements

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+approves related party transactions. 
+• Appoints, determines compensation, evaluates and terminates our independent auditors. 
+• Pre-approves audit and permissible non-audit services to be performed by the independent auditors. 
+• Prepares the
+report required by the Securities and Exchange Commission, or the SEC, for the inclusion in our annual proxy statement. 
+• Reviews and
+reassesses the adequacy of the audit committee charter on a periodic basis. 
+• Inform our
+independent auditors of the audit committee’s understanding of significant relationships and transactions with related parties and review and discuss with our independent auditors the auditors’ evaluation of our identification of,
+accounting for and disclosure of our relationships and transactions with related parties, including any significant matters arising from the audit regarding our relationships and transactions with related parties. 
+4 
+8 
+Table of Contents 
+Committee 
+Members 
+Principal Functions 
+Number of 
+Meetings in 
+2016 
+Compensation 
+Scott E. Streller* 
+Craig Groeschel 
+David L. Houston 
+C. Doug Johnson 
+• Oversees and
+administers our executive compensation policies, plans and practices and evaluates their impact on risk and risk management. 
+• Assists the board
+of directors in discharging its responsibilities relating to the compensation of our executives, including our chief executive officer, and other key employees. 
+• Administers our
+equity-based compensation plans, including the grants of stock options, restricted stock awards and other equity awards under such plans. 
+• Reviews, approves
+and administers our cash-based incentive bonus plans, including the establishment of performance criteria, targets and awards under our 2014 Executive Annual Incentive Compensation Plan. 
+• Makes
+recommendations to the board with respect to incentive compensation. 
+• Where appropriate
+or required, makes recommendations to our stockholders with respect to incentive compensation and equity-based plans. 
+• Conducts annual
+performance evaluation of the committee. 
+• Reviews
+disclosure related to executive compensation in our proxy statement and prepares an annual compensation committee report. 
+• Reviews and
+considers the stockholders’ advisory vote on executive compensation and the frequency of holding such advisory vote. 
+• Reviews and
+reassesses the adequacy of the compensation committee charter. 
+10 
+Nominating and Corporate Governance+ 
+Ben T. Morris* 
+David L. Houston 
+Scott E. Streller 
+• Assists the board
+of directors in developing criteria for, identifying and evaluating individuals qualified to serve as members of our board of directors. 
+• Selects and
+recommends director candidates to the board of directors to be submitted for election at the Annual Meeting and to fill any vacancies on the board of directors. 
+• Periodically
+reviews and makes recommendations regarding the composition and size of the board of directors and each of its committees. 
+• Reviews and
+recommends to the board of directors appropriate corporate governance policies and procedures for the Company. 
+• Conducts an
+annual assessment of the qualifications and performance of the board of directors. 
+2 
+9 
+Table of Contents 
+Committee 
+Members 
+Principal Functions 
+Number of 
+Meetings in 
+2016 
+• Annually reviews
+and reports to the board of directors on the performance of management. 
+• Reviews and
+reassesses the adequacy of the nominating committee charter. 
+* 
+Committee Chairperson. 
++ 
+Our former director, Mr. Donald L. Dillingham, who, as previously disclosed, did not stand for re-election at our 2016 Annual Meeting of Stockholders, served on the
+audit committee and the nominating and corporate governance committee of our board of directors during 2016 until the date of our 2016 Annual Meeting of Stockholders. 
+Do the committees have written charters? 
+Yes. The
+charters for our audit committee, compensation committee and nominating committee can be found on our website at www.gulfportenergy.com under the “Corporate Governance” caption. You may also obtain copies of these charters, as well
+as our Code of Business Conduct and Ethics, which is described below, by writing to our Senior Vice President of Corporate Development and Strategy, Paul K. Heerwagen IV, at Gulfport Energy Corporation, 3001 Quail Springs Parkway, Oklahoma City,
+Oklahoma 73134.

raw/filings/0000874499/2017/0001628280-18-002041/filing_metadata.csv

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+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0000874499,GPOR,GULFPORT ENERGY CORP,10-K,2018-02-22,2017-12-31,2018-02-22T20:25:03.000Z,0001628280-18-002041,gpor-12312017x10k.htm,10-K,20428479,1,0,https://www.sec.gov/Archives/edgar/data/874499/000162828018002041/gpor-12312017x10k.htm,https://www.sec.gov/Archives/edgar/data/874499/000162828018002041/,2017,2017,1

raw/filings/0000874499/2017/0001628280-18-002041/item13.txt

@@ -0,0 +1,3 @@
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+For information concerning Item 13-Certain Relationships and Related Transactions, and Director Independence, see our definitive proxy statement, which will be filed with the Securities and Exchange Commission with 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference).

raw/filings/0000874499/2017/0001628280-18-002041/item9a.txt

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+ITEM 9A. 
+CONTROLS AND PROCEDURES 
+Evaluation of Disclosure Control and Procedures . Under the direction of our Chief Executive Officer and President and our Chief Financial Officer, we have established disclosure controls and procedures that are designed to ensure that information required to be disclosed by us 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's rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and President and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures. 
+As of December 31, 2017 , an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and President and our Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and President and our Chief Financial Officer have concluded that, as of December 31, 2017 , our disclosure controls and procedures are effective. 
+Changes in Internal Control over Financial Reporting . There have not been any changes in our internal control over financial reporting that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting. 
+Management's Report on Internal Control Over Financial Reporting 
+Management is responsible for the fair presentation of the consolidated financial statements of Gulfport Energy Corporation. Management is also responsible for establishing and maintaining a system of adequate internal controls over financial reporting as defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. These internal controls are designed to provide reasonable assurance that the reported financial information is presented fairly, that disclosures are adequate and that the judgments inherent in the preparation of financial statements are reasonable. There are inherent limitations in the effectiveness of any system of internal control, including the possibility of human error and overriding of controls. Consequently, an effective internal control system can only provide reasonable, not absolute, assurance with respect to reporting financial information. 
+Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in the 2013 Internal Control-Integrated Framework , management did not identify any material weaknesses in our internal control over financial reporting and concluded that our internal control over financial reporting was effective as of December 31, 2017 . 
+Grant Thornton LLP, the independent registered public accounting firm that audited our financial statements for the year ended December 31, 2017 included with this Annual Report on Form 10-K, has also audited our internal control over financial reporting as of December 31, 2017 , as stated in their accompanying report. 
+/s/ Michael G. Moore 
+/s/ Keri Crowell 
+Name: 
+Michael G. Moore 
+Name: 
+Keri Crowell 
+Title: 
+Chief Executive Officer and President 
+Title: 
+Chief Financial Officer 
+77 
+Table of Contents 
+Index to Financial Statements 
+Report of Independent Registered Public Accounting Firm 
+Board of Directors and Stockholders 
+Gulfport Energy Corporation 
+Opinion on internal control over financial reporting 
+We have audited the internal control over financial reporting of Gulfport Energy Corporation (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2017 , based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in the 2013 Internal Control-Integrated Framework issued by COSO. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) ("PCAOB"), the consolidated financial statements of the Company as of and for the year ended December 31, 2017, and our report dated February 22, 2018 expressed an unqualified opinion on those financial statements. 
+Basis for opinion 
+The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+Definition and limitations of internal control over financial reporting 
+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. 
+/s/ GRANT THORNTON LLP 
+Oklahoma City, Oklahoma 
+February 22, 2018 
+78 
+Table of Contents 
+Index to Financial Statements

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+Certain Relationships and Related Transactions 
+Review and Approval of Related Party Transactions 
+The audit committee, as provided in its charter, reviews and approves related party transactions. The Company does not have a formal set of standards to be
+substantively applied to each transaction reviewed by the audit committee. Instead of a formalized policy, related party transactions are reviewed and judgment is applied to determine whether such transactions are in the best interests of the
+Company. Further, the Company’s Code of Business Conduct and Ethics governs various compliance areas, including conflicts of interest and fair dealings, which are considered in the process of the review and approval of related party
+transactions. 
+The Company’s policy is that all of its employees and directors, as well as their family members, must avoid any activity that is or
+has the appearance of conflicting with the Company’s business interest. This policy is included in the Company’s Code of Business Conduct and Ethics posted on its website. Each director and executive officer is instructed to always inform
+the designated compliance officer when confronted with any situation that may be perceived as a conflict of interest. Only the board of directors or a committee consisting solely of independent directors may grant waivers of the provisions of the
+Code of Business Conduct and Ethics for the Company’s executive officers and directors. In addition, at least annually, each director and executive officer completes a detailed questionnaire specifying any business relationship that may give
+rise to a conflict of interest. 
+61 
+Table of Contents 
+Further, under the audit committee charter, the audit committee is responsible for reviewing and monitoring
+compliance with our Code of Business Conduct and Ethics and recommending any warranted changes to the board of directors. In addition, the board of directors and, pursuant to its written charter, the audit committee, reviews and approves all
+relationships and transactions in which the Company and its directors, director nominees and executive officers and their immediate family members, as well as holders of more than 5% of any class of our voting securities and their family members,
+have a direct or indirect material interest. The board of directors and the audit committee approve only those transactions that, in light of known circumstances, are consistent, or are not inconsistent with, the Company’s best interests, as
+they determine in the good faith exercise of their discretion. 
+On February 17, 2017, we, through a wholly-owned subsidiary, completed our
+acquisition of certain assets, or the Vitruvian Acquisition, from Vitruvian II Woodford, LLC, or Vitruvian, an unrelated third-party seller at the time of the Vitruvian Acquisition. The consideration paid to Vitruvian was $1.85 billion, which
+included approximately 23.9 million shares of our common stock. As a result of the Vitruvian Acquisition, Vitruvian acquired more than 5% of our common stock. In connection with the Vitruvian Acquisition, we entered into a registration rights
+agreement with Vitruvian, pursuant to which we agreed to file a shelf registration statement with respect to the registration under the Securities Act of 1933, as amended, of the resale of the shares issued to Vitruvian and any shares of our common
+stock that may be issued or distributed in respect of the shares issued to Vitruvian upon certain events, which shelf registration statement became effective in April 2017. Under the registration rights agreement, we also agreed to provide certain
+demand and piggyback registration rights to Vitruvian. As Vitruvian was not a related party at the time of the transaction, our policies did not require the Vitruvian Acquisition go through the review process described above. However, the
+transaction was considered and approved by our board of directors.

raw/filings/0000874499/2018/0001628280-19-002242/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
+0000874499,GPOR,GULFPORT ENERGY CORP,10-K,2019-02-28,2018-12-31,2019-02-28T19:49:21.000Z,0001628280-19-002242,gpor-12312018x10k.htm,10-K,19987656,1,0,https://www.sec.gov/Archives/edgar/data/874499/000162828019002242/gpor-12312018x10k.htm,https://www.sec.gov/Archives/edgar/data/874499/000162828019002242/,2018,2018,1

raw/filings/0000874499/2018/0001628280-19-002242/item1.txt

@@ -0,0 +1,535 @@
+ITEM 1. 
+BUSINESS 
+General 
+We are an independent oil and natural gas exploration and production company focused on the exploration, exploitation, acquisition and production of natural gas, crude oil and natural gas liquids, or NGLs, in the United States. Our corporate strategy is to internally identify prospects, acquire lands encompassing those prospects and evaluate those prospects using subsurface geology and geophysical data and exploratory drilling. Using this strategy, we have developed an oil and natural gas portfolio of proved reserves, as well as development and exploratory drilling opportunities on high potential conventional and unconventional oil and natural gas prospects. Our principal properties are located in the Utica Shale primarily in Eastern Ohio and the SCOOP Woodford and SCOOP Springer plays in Oklahoma. In addition, among other interests, we hold an acreage position along the Louisiana Gulf Coast in the West Cote Blanche Bay, or WCBB, and Hackberry fields, an acreage position in the Alberta oil sands in Canada through our interest in Grizzly Oil Sands ULC, or Grizzly, and an approximate 21.9% equity interest in Mammoth Energy Services, Inc., or Mammoth Energy, a company listed on the Nasdaq Global Select Market (TUSK) that serves the electric utility and oil and natural gas industries. We seek to achieve reserve growth and increase our cash flow through our annual drilling programs. 
+As of February 15, 2019 , we held leasehold interests in approximately 241,000 gross ( 210,000 net) acres in the Utica Shale primarily in Eastern Ohio. In 2018 , we spud 23 gross ( 19.5 net) wells, of which three were completed as producing wells and, as of December 31, 2018 , 20 were in various stages of completion. We commenced sales from 35 gross and net wells in the Utica Shale during 2018 . During 2019 (through February 15, 2019 ), we spud five gross ( 3.7 net) wells. As of February 15, 2019 , three of these wells were in various stages of completion and the other two were still drilling. In addition, other operators drilled 28 gross ( 4.4 net) wells and commenced sales from 32 gross ( 9.4 net) wells on our Utica Shale acreage in 2018 . 
+We currently intend to drill 13 to 15 gross ( 10 to 11 net) horizontal wells, and commence sales fr om 47 to 51 gross ( 40 to 45 n et) horizontal wells on our Utica Shale acreage in 2019 . We currently anti cipate two to three net horizontal wells will be drilled, and sales commenced fro m two to three net horizo ntal wells, by other operators on our Utica Shale acreage in 2019 . 
+Aggregate net production from our Utica Shale acreage during the three months ended December 31, 2018 was approximately 102,665 million cubic feet of natural gas equivalent, or MMcfe, or 1,115.9 MMcfe per day, of which 97% was from natural gas and 3% was from oil and NGLs. 
+As of February 15, 2019 , we held leasehold interests in approximately 50,000 net surface acres in the SCOOP. In 2018 , we spud 13 gross ( 12.1 net) wells, of which four were completed as producing wells and, as of December 31, 2018 , nine were in various stages of completion. We commenced sales from 15 gross ( 12.8 net) wells in the SCOOP during 2018 . During 2019 (through February 15, 2019 ), we spud two gross ( 1.6 net) wells. As of February 15, 2019 , both of these wells were still drilling. In addition, other operators drilled 40 gross ( 3.1 net) wells and commenced sales from 47 gross ( 3.6 net) wells on our SCOOP acreage during 2018 . 
+We currently intend to drill nine to ten gross ( seven to eight net) horizontal wells, and commence sales from 15 to 17 gross ( 14 to 15 net) horizontal wells on our SCOOP acreage in 2019 . We currently anticipat e one to two net horizontal wells will be drilled, and sales commenced from one to two net hor izontal wells, by other operators on our SCOOP acreage in 2019 . 
+Aggregate net production from our SCOOP acreage during the three months ended December 31, 2018 was approximately 24,406 MMcfe, or an average of 265.3 MMcfe per day, of which 70% was from natural gas and 30% was from oil and NGLs. 
+In 2018 , at our WCBB field, we did not spud any new wells and recompleted 32 existing wells. In the fourth quarter of 2018 , net production at WCBB was approximately 837 MMcfe, or an average of 9.1 MMcfe per day, all of which was from oil. 
+In 2018 , at our East Hackberry field, we did not spud any new wells and recompleted 15 existing wells. In the fourth quarter of 2018 , net production at East Hackberry was approximately 115 MMcfe, or an average of 1.2 MMcfe per day, all of which was from oil. 
+In 2018 , at our West Hackberry field, we did not spud any new wells. In the fourth quarter of 2018 , net production at West Hackberry was approximately 17 MMcfe, or an average of 186.2 thousand cubic feet of natural gas equivalent, or Mcfe, per day, all of which was from oil. 
+2 
+Table of Contents 
+Index to Financial Statements 
+We do not anticipate any material activities in our Southern Louisiana fields during 2019 . 
+As of December 31, 2018 , we held leasehold interests in approximately 2,900 net acres in the Niobrara Formation in Northwestern Colorado. During the year ended December 31, 2018 , there were no wells spud on our Niobrara Formation acreage. In the fourth quarter of 2018 , net production from our Niobrara Formation acreage was approximately 23 MMcfe, or an average of 251.0 Mcfe per day, all of which was from oil. 
+As of December 31, 2018 , we held leasehold interests in approximately 780 net acres in the Bakken Formation of Western North Dakota and Eastern Montana, interests in 18 wells and overriding royalty interests in certain existing and future wells. In the fourth quarter of 2018 , our net production from this acreage was approximately 76 MMcfe, or an average of 827.1 Mcfe per day, of which 86% was from oil and 14% was from natural gas and natural gas liquids. 
+We, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.9% interest in Grizzly. As of December 31, 2018 , Grizzly had approximately 830,000 net acres under lease in the Athabasca, Peace River and Cold Lake oil sands regions of Alberta, Canada. For additional information regarding Grizzly, see "- Our Equity Investments–Grizzly Oil Sands " below. 
+We own a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex II. Tatex II, a privately held entity, holds an 8.5% interest in APICO, LLC, or APICO, an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering approximately 108,000 acres which includes the Phu Horm Field. For additional information regarding Tatex II and our other activities in Southeast Asia, see "- Our Equity Investments–Thailand " below. 
+In an effort to facilitate the development of our Utica Shale and other domestic acreage, we have invested in entities that can provide services that are required to support our operations. For additional information regarding these entities, see "- Our Equity Investments–Other Investments " below. 
+As of December 31, 2018 , we had 4.7 trillion cubic feet of natural gas equivalent, or Tcfe, of proved reserves with a present value of estimated future net revenues, discounted at 10%, or PV-10, of approximately $3.4 billion and associated standardized measure of discounted future net cash flows of approximately $3.0 billion , excluding reserves attributable to our interests in Grizzly and Tatex II. See Item 2. " Properties-Proved Oil and Natural Gas Reserves ” for our definition of PV-10 (a non-GAAP financial measure) and a reconciliation of our standardized measure of discounted future net cash flows (the most directly comparable GAAP measure) to PV-10. 
+Principal Oil and Natural Gas Properties 
+The following table presents certain information as of December 31, 2018 reflecting our net interest in our principal producing oil and natural gas properties in the Utica Shale primarily in Eastern Ohio, the SCOOP in Oklahoma, along the Louisiana Gulf Coast, in the Niobrara Formation in Northwestern Colorado and in the Bakken Formation in Western North Dakota and Eastern Montana. 
+Proved Reserves 
+Field 
+Average NRI/WI (1) 
+Productive 
+Wells 
+Non-Productive 
+Wells 
+Developed 
+Acreage (2) 
+Gas 
+Oil 
+NGLs 
+Total 
+Percentages 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+MMcf 
+MBbls 
+MBbls 
+MMcfe 
+Utica Shale (3) 
+44.26/54.44 
+567 
+308 
+5 
+4.23 
+92,594 
+72,693 
+3,123,629 
+5,289 
+32,500 
+3,350,363 
+SCOOP (4) 
+24.34/30.20 
+576 
+173.27 
+33 
+27.83 
+48,658 
+34,532 
+1,009,971 
+12,937 
+48,020 
+1,375,713 
+West Cote Blanche Bay Field (5) 
+80.108/100 
+69 
+69 
+146 
+146 
+5,668 
+5,668 
+18 
+1,834 
+— 
+11,022 
+E. Hackberry Field (6) 
+82.33/100 
+14 
+14 
+130 
+130 
+2,910 
+2,910 
+35 
+276 
+— 
+1,692 
+W. Hackberry Field 
+87.50/100 
+2 
+2 
+7 
+7 
+727 
+727 
+— 
+391 
+— 
+2,346 
+Niobrara Formation 
+34.52/48.61 
+3 
+1.46 
+— 
+— 
+1,998 
+999 
+— 
+128 
+— 
+768 
+Bakken Formation 
+1.51/1.83 
+18 
+0.3 
+— 
+— 
+386 
+77 
+227 
+195 
+— 
+1,398 
+Overrides/Royalty Non-operated 
+Various 
+673 
+0.9 
+— 
+— 
+— 
+— 
+9 
+— 
+— 
+9 
+Total 
+1,922 
+568.93 
+321 
+315.06 
+152,941 
+117,606 
+4,133,889 
+21,050 
+80,520 
+4,743,311 
+3 
+Table of Contents 
+Index to Financial Statements 
+(1) 
+Net Revenue Interest (NRI)/Working Interest (WI) for producing wells. 
+(2) 
+Developed acres are acres spaced or assigned to productive wells. Approximately 43% of our acreage is developed acreage and has been held by production. 
+(3) 
+Includes NRI/WI from wells that have been drilled or in which we have elected to participate. Includes 245 gross (41.44 net) wells drilled by other operators on our acreage. 
+(4) Includes NRI/WI from wells that have been drilled or in which we have elected to participate. Includes 392 gross (30.02 net) wells drilled by other operators on our acreage. 
+(5) 
+We have a 100% working interest (80.108% average NRI) from the surface to the base of the 13900 Sand which is located at 11,320 feet. Below the base of the 13900 Sand, we have a 40.40% non-operated working interest (29.95% NRI). 
+(6) 
+NRI shown is for producing wells. 
+Utica Shale (primarily in Eastern Ohio) 
+Location and Land 
+As of December 31, 2018 , we held leasehold interests in approximately 241,000 gross ( 210,000 net) acres in the Utica Shale. 
+Area History 
+As of December 31, 2018 , the Ohio Department of Natural Resources reported that there were 2,138 producing horizontal wells, 246 horizontal wells that had been drilled but were not yet completed or connected to a pipeline, 116 horizontal wells that were being drilled and an additional 449 horizontal wells that had been permitted. 
+Geology 
+The Utica Shale is located in the Appalachian Basin of the United States and Canada. The Utica Shale is a rock unit comprised of organic-rich calcareous black shale that was deposited about 440 million to 460 million years ago during the Late Ordovician period. It overlies the Trenton Limestone and is located a few thousand feet below the Marcellus Shale. 
+The source rock portion of the Utica Shale underlies portions of Kentucky, Maryland, New York, Ohio, Pennsylvania, Tennessee, West Virginia and Virginia in the United States and is also present beneath parts of Lake Ontario, Lake Erie and Ontario, Canada. Throughout this area, the Utica Shale ranges in thickness from less than 100 feet to over 800 feet. There is a general thinning from east to west. Across our position, the Utica Shale ranges in thickness from over 600 to over 750 feet. 
+The application of horizontal drilling, combined with multi-staged hydraulic fracturing to create permeable flow paths from shale units into wellbores, were the key technologies that unlocked development of the Devonian-age Marcellus Shale and the Ordovician-age Utica Shale in the Appalachian Basin states of Pennsylvania, West Virginia, Southern New York and Eastern Ohio. This proven technology has potential for application in other shale units which extend across much of the Appalachian Basin region. 
+Facilities 
+There are standard land oil and natural gas processing facilities in the Utica Shale. Our facilities located at well site pads include storage tank batteries, oil/gas/water separation equipment, vapor recovery units, line heaters, compression emission control devices and applicable metering. 
+Recent and Future Activities 
+We spud our first well, the Wagner 1-28H, on our Utica Shale acreage in February 2012 and, as of December 31, 2018 , had spud 385 gross wel ls, 290 of which were completed and were producing. In 2018 , we spud 23 gross ( 19.5 net) wells, of which three were completed as producing wells and, as of December 31, 2018 , 20 were in various stages of completion. We commenced sales from 35 gross and net wells in the Utica Shale during 2018 . During 2019 (through February 15, 2019 ), we spud five gross ( 3.7 net) wells. As of February 15, 2019 , three of these wells were in various stages of completion and the other two were still drilling. In addition, other operators drilled 28 gross ( 4.4 net) wells and commenced sales from 32 gross ( 9.4 net) wells on our Utica Shale acreage in 2018 . 
+4 
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+Index to Financial Statements 
+We currently intend to dr ill 13 to 15 gross ( 10 to 11 net) horizontal wells, and commence sales from 47 to 51 gross ( 40 to 45 net) horizontal wells, on our Utica Shale acreage in 2019 . We currently anticipate two to three net horizontal wells will be drilled, and sales commenced from two to three net horizontal wells, by other o perators on our Utica Shale acreage during 2019 . As of February 15, 2019 , we had two operated horizontal rig drilling in the play. We plan to run, on average, approximately one operated horizontal rig in the Utica Shale in 2019. 
+Production Status 
+Aggregate net production from our Utica Shale acreage during the three months ended December 31, 2018 was approximately 102,665 MMcfe, or 1,115.9 MMcfe per day, of which 97% was from natural gas and 3% was from oil and NGLs. 
+SCOOP (Oklahoma) 
+Location and Land 
+As of December 31, 2018 , we held leasehold interests in approximately 66,000 gross ( 50,000 net) surface acres in the SCOOP and approximately 92,000 net reservoir acres, which includes 50,000 net Woodford acres and 42,000 net Springer acres. 
+Area History 
+The SCOOP, or South Central Oklahoma Oil Province, is a loosely defined province that encompasses many of the top hydrocarbon producing counties in Oklahoma. The area extends mainly across Grady, Caddo, McClain, Garvin, Stevens, Carter and Love Counties. The region was historically developed by vertical wells drilled through multiple stacked reservoirs ranging from the Cambrian to Permian Periods in age. The play represents the transition to mainly horizontal development targeting predominantly oil and condensate-rich hydrocarbons. The most prolific of these reservoirs include the, Springer (Goddard) Shale, Caney Shale, Woodford Shale and Sycamore Formation. 
+Geology 
+The SCOOP play of Oklahoma is located in the southeast portion of the prolific Anadarko Basin. The SCOOP play mainly targets the Devonian to Mississippian aged Woodford Shale. The Woodford Shale is a silica and highly organic rich black shale that was deposited about 320 million to 370 million years ago. Across our position, the Woodford Shale ranges in thickness from 200 to over 400 feet and directly overlies the Hunton Limestone and underlies the Sycamore formation, both of which are also locally productive reservoirs. The Sycamore formation is age equivalent to the Meramec and Osage being developed in the STACK, or Sooner Trend Anadarko Basin Canadian and Kingfisher Counties, play and is located between the organic-rich Woodford and Caney Shales. The Sycamore formation is approximately 250 feet thick across our acreage position, presenting a significant development target. 
+Facilities 
+There are standard land oil and natural gas processing facilities in the SCOOP. Our facilities located at well site pads include storage tank batteries, oil/gas/water separation equipment, vapor recovery units, line heaters, compression emission control devices and applicable metering. 
+Recent and Future Activities 
+On February 17, 2017, we, through our wholly-owned subsidiary Gulfport MidCon, LLC, or Gulfport MidCon (formerly known as SCOOP Acquisition Company, LLC), completed our acquisition, which we refer to as our SCOOP acquisition, of certain assets from Vitruvian II Woodford, LLC, an unrelated third-party seller, for a total purchase price of approximately $1.85 billion, consisting of $1.35 billion in cash, subject to certain adjustments, and approximately 23.9 million shares of the Company’s common stock (of which approximately 5.2 million shares were placed in an indemnity escrow). Our SCOOP acquisition included approximately 46,000 net surface acres with multiple producing zones, including the Woodford and Springer formations in the SCOOP resource play, in Grady, Stephens and Garvin Counties, Oklahoma. 
+Upon our acquisition of these assets, we focused on the high-grading of equipment for our rig fleet to drive efficiencies and lower drill days in the play. Improved well performance has also been realized with enhanced completion designs compared to 
+5 
+Table of Contents 
+Index to Financial Statements 
+historical practices for the area. Our 2018 drilling program concentrated on SCOOP Woodford wells, however, during 2018, we also spud and commenced sales from one upper Sycamore well. 
+In 2018 , we spud 13 gross ( 12.1 net) wells, of which four were completed as producing wells and, as of December 31, 2018 , nine were in various stages of completion. We commenced sales from 15 gross ( 12.8 net) wells in the SCOOP during 2018 . During 2019 (through February 15, 2019 ), we spud two gross ( 1.6 net) wells. As of February 15, 2019 , both of these wells were still drilling. In addition, other operators drilled 40 gross ( 3.1 net) wells and commenced sales from 47 gross ( 3.6 ne t) wells on our SCOOP acreage in 2018 . 
+We currently intend to drill nine to ten gross ( seven to eight net) horizontal wells, and commence sales from 15 to 17 gross ( 14 to 15 net) horizontal wells, on our SCOOP acreage in 2019 . We currently anticipate one to two net horizontal wells will be drilled, and sales commenced from one to two net horizontal wells, by other operators on our SCOOP acreage during 2019 . As of February 15, 2019 , we had two operated horizontal rigs drilling in the play . We intend to run, on average, approximately 1.5 operated horizontal rigs in the SCOOP during 2019. 
+Production Status 
+Aggregate net production from our SCOOP acreage during the three months ended December 31, 2018 was approximately 24,406 net MMcfe, or 265.3 MMcfe per day, of which 70% was from natural gas and 30% was from oil and natural gas liquids. 
+West Cote Blanche Bay Field 
+Location and Land 
+The WCBB field is located approximately five miles off the coast of Louisiana in a shallow bay with water depths averaging eight to ten feet. We own a 100% working interest (80.108% net revenue interest, or NRI), and are the operator, in depths above the base of the 13900 Sand which is located at 11,320 feet. In addition, we own a 40.40% non-operated working interest (29.95% NRI) in depths below the base of the 13900 Sand, which is operated by Chevron Corporation. Our leasehold interests at WCBB contain 5,668 gross acres. 
+Area History and Production 
+Texaco, now part of Chevron Corporation, drilled the discovery well in this field in 1940 based on a seismic and gravitational anomaly. WCBB was subsequently developed on an even 160-acre pattern for much of the remainder of the decade. Developmental drilling continued and reached its peak in the 1970s when over 300 wells were drilled in the field. Of the 1,093 wells drilled as of December 31, 2018 , 980 were completed as producing wells. From the date of our acquisition of WCBB in 1997 through December 31, 2018 , we drilled 273 new wells, 240 of which were productive, for an 88% success rate. As of December 31, 2018 , estimated field cumulative gross production was 200 MMBO and 238 Bcf of gas. Of the 1,093 wells drilled in WCBB as of December 31, 2018 , 69 were producing, 146 were shut-in, and six were being used as salt water disposal wells. The other 872 wells have been plugged and abandoned. 
+Geology 
+WCBB overlies one of the largest salt dome structures on the Gulf Coast. The field is characterized by a piercement salt dome, which created traps from the Pleistocene through the Miocene formations. The relative movements affected deposition and created a complex system of fault traps. The compensating fault sets generally trend northwest to southeast and are intersected by sets having a major radial component. Later-stage movement caused extension over the dome and a large graben system (a downthrown area bounded by normal faults) was formed. 
+There are over 100 distinct sandstone reservoirs recognized throughout most of the field, and nearly 200 major and minor discrete intervals have been tested. Within the 1,093 wells that had been drilled in the field as of December 31, 2018 , over 4,000 potential zones have been penetrated. These sands are highly porous and permeable reservoirs primarily with a strong water drive. 
+WCBB is a structurally and stratigraphically complex field. All of the proved undeveloped, or PUD, locations at WCBB are adjacent to faults and abut at least one fault. Our drilling programs are designed to penetrate each PUD trap with a new wellbore in a structurally optimum position, usually very close to the fault seal. The majority of these wells have been, and new wells drilled in connection with our drilling programs will be, directionally drilled using steering tools and downhole motors. 
+6 
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+Index to Financial Statements 
+The tolerance for error in getting near the fault is low, so the complex faulting does introduce the risk of crossing the fault before encountering the zone of interest, which could result in part or all of the zone being absent in the borehole. This, in turn, can result in lower than expected or no reserves for that zone. The new wellbores eliminate the mechanical risk associated with trying to produce the zone from an old existing wellbore, while the wellbore locations are selected in an effort to more efficiently drain each reservoir. The vast majority of the PUD targets are up-dip offsets to wells that produced from a sub-optimal position within a particular zone. 
+Facilities 
+We own and operate a production facility at WCBB that includes four production tank batteries, seven natural gas compressors, a storage barge facility, a dock, a dehydration unit and a salt water disposal system. 
+Recent Activity 
+In 2018 , at our WCBB field, we recompleted 32 existing wells and spud no new wells. As of February 15, 2019 , no existing wells had been recompleted during 2019 in our WCBB field. 
+Production Status 
+In the fourth quarter of 2018 , our net production at WCBB was approximately 837 MMcfe, or an average of 9.1 MMcfe per day, all of which was from oil. 
+East Hackberry Field 
+Location and Land 
+The East Hackberry field in Louisiana is located along the western shore and the land surrounding Lake Calcasieu, 15 miles inland from the Gulf of Mexico. We own a 100% working interest (approximately 82.33% average NRI) in certain producing oil and natural gas properties situated in the East Hackberry field. As of December 31, 2018 , we held beneficial interests in approximately 4,116 acres, including the Erwin Heirs Block, which is located on land, and the adjacent State Lease 50 Block, which is located primarily in the shallow waters of Lake Calcasieu. 
+Area History and Production 
+The East Hackberry field was discovered in 1926 by Gulf Oil Company, now Chevron Corporation, by a gravitational anomaly survey. The massive shallow salt stock presented an easily recognizable gravity anomaly indicating a productive field. Initial production began in 1927 and has continued to the present. The estimated cumulative oil and condensate production through 2018 was over 4,758 MBO and 332 Bcf of casinghead gas production. A total of 272 wells have been drilled on our portion of the field. As of December 31, 2018 , 14 wells had daily production, 130 were shut-in and three had been converted to salt water disposal wells. The remaining 125 wells had been plugged and abandoned. 
+Geology 
+The Hackberry field is a major salt intrusive feature, elliptical in shape as opposed to a classic “dome,” divided into east and west field entities by a saddle. Structurally, our East Hackberry acreage is located on the eastern end of the Hackberry salt ridge. There are over 30 pay zones at this field. The salt intrusion formed a series of structurally complex and steeply dipping fault blocks in the Lower Miocene and Oligocene age rocks. These fault blocks serve as traps for hydrocarbon accumulation. Our wells currently produce from perforations found between 5,100 and 12,200 feet. 
+Facilities 
+We have a field office that serves both the East and West Hackberry fields. In addition, we own and operate two production facilities at East Hackberry that include one land based tank batteries, a production barge, two natural gas compressors, dehydration units and salt water disposal systems. 
+Recent Activity 
+7 
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+Index to Financial Statements 
+During 2018 at East Hackberry, we recompleted 15 existing wells and spud no new wells. As of February 15, 2019 , no existing wells had been recompleted during 2019 in our East Hackberry field. 
+Production Status 
+In the fourth quarter of 2018 , our net production at East Hackberry was approximately 115 MM cfe, or an averag e of 1.2 MMcfe per day, all of which was from oil. 
+West Hackberry Field 
+Location and Land 
+The West Hackberry field is located on land and is five miles west of Lake Calcasieu in Cameron Parish, Louisiana, approximately 85 miles west of Lafayette and 15 miles inland from the Gulf of Mexico. We own a 100% working interest (approximately 87.50% NRI) in 1,032 acres within the West Hackberry field. Our leases at West Hackberry are located within two miles of one of the United States Department of Energy's Strategic Petroleum Reserves. 
+Area History 
+The first discovery well at West Hackberry was drilled in 1938 and the field was developed by Superior Oil Company, now ExxonMobil Corporation, between 1938 and 1988. The estimated cumulative oil and condensate production through 2018 was 493 MBO and 140 Bcf of natural gas. As of December 31, 2018 , 42 wells had been drilled on our portion of West Hackberry. As of December 31, 2018 , two of such wells were producing, seven were shut-in and one was being used as a salt water disposal well. The remaining 32 wells have been plugged and abandoned. 
+Geology 
+Structurally, our West Hackberry acreage is located on the western end of the Hackberry salt ridge. There are over 30 pay zones at this field. West Hackberry consists of a series of fault-bounded traps in the Oligocene-age Vincent and Keough sands associated with the Hackberry Salt Ridge. Recoveries from these thick, porous, water-drive reservoirs have resulted in per well cumulative production of almost 700 MBOE. 
+Recent Activity 
+During 2018 at West Hackberry, we did not spu d any new wells . As of February 15, 2019 , no existing wells had been recompleted during 2019 in our West Hackberry field. 
+Production Status 
+In the fourth quarter of 2018 , our net production at West Hackberry was approximately 17 MMcfe, or an average of 186.2 Mcfe per day, all of which was from oil. 
+Facilities 
+We own and operate a production facility at West Hackberry that includes a land based tank battery and salt water disposal system. 
+We do not anticipate any material activities in our Southern Louisiana fields during 2019 . 
+Niobrara Formation (Northwestern Colorado) 
+Location and Land 
+Effective as of April 1, 2010, we acquired leasehold interests in the Niobrara Formation in Northwestern Colorado and, as of December 31, 2018 , we held leases for approximately 2,900 net acres. In 2018 , no wells were spud on our Niobrara Formation acreage. 
+8 
+Table of Contents 
+Index to Financial Statements 
+Area History 
+The Niobrara Formation is a shale oil rock formation located in Colorado, Northwest Kansas, Southwest Nebraska, and Southeast Wyoming. Oil and natural gas can be found at depths of 3,000 to 14,000 feet and is drilled both vertically and horizontally. The Upper Cretaceous Niobrara Formation has emerged as another potential crude oil resource play in various basins throughout the northern Rocky Mountain region. As with most resource plays, the Niobrara Formation has a history of producing through conventional technology with some of the earliest production dating back to the early 1900s. Natural fracturing has played a key role in producing the Niobrara Formation historically due to the low porosity and low permeability of the formation. Because of this, conventional production has been very localized and limited in area extent. We believe the Niobrara Formation can be produced on a more widespread basis using today's horizontal multi-stage fracture stimulation technology where the Niobrara Formation is thermally mature. 
+Geology 
+The Niobrara Formation oil play in Northwestern Colorado is located between the Piceance Basin to the south and the Sand Wash Basin to the north. Rocks mainly consist of interbedded organic-rich shales, calcareous shales and marlstones. It is the fractured marlstone intervals locally known as the Buck Peak, Tow Creek and Wolf Mountain benches that account for the majority of the area's production. These fractured carbonate reservoirs are associated with anticlinal, synclinal and monoclinal folds, and fault zones. This proven oil accumulation is considered to be continuous in nature and lightly explored. Source rocks are predominantly oil prone and thermally mature with respect to oil generation. The producing intervals are geologically equivalent to the Niobrara Formation reservoirs of the DJ and Powder River Basins, which are currently emerging as a major crude resource play. 
+Production Status 
+In the fourth quarter of 2018 , net production from our Niobrara Formation acreage was approximately 23 MMcfe, or an average of 251.0 Mcfe per day, all of which was from oil. 
+Facilities 
+There are typical land oil and natural gas processing facilities in the Niobrara Formation. Our facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units. 
+Recent Activity 
+There were no new wells drilled on our Niobrara Formation acreage in 2018 . We do not anticipate drilling any wells in the Niobrara Formation during 2019 . 
+Bakken Formation 
+Location and Land 
+The Bakken Formation is located in the Williston Basin areas of Western North Dakota and Eastern Montana. As of December 31, 2018 , we held approximately 780 net acres, interests in 18 wells and overriding royalty interests in certain existing and future wells. 
+Production Status 
+In the fourth quarter of 2018 , our net production from this acreage was approximatel y 76 MMcfe, or an average o f 827.1 Mcfe per day, of wh ich 86% was f rom oil and 14% was from natural gas and natural gas liquids. 
+Facilities 
+There are typical land, oil and natural gas processing facilities in the Williston Basin. The facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units. 
+9 
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+Index to Financial Statements 
+Recent Activities 
+There were no new wells drilled on our Bakken Formation acreage in 2018 . We do not anticipate drilling any wells in the Bakken Formation during 2019 . 
+Additional Properties 
+In addition to our core properties discussed above, we also own working interests and overriding royalty interest in various fields in Louisiana, Texas and Oklahoma as described in the following table as of December 31, 2018 : 
+Field 
+State 
+Parish/County 
+Average Working 
+Interest 
+Overriding Royalty 
+Interests 
+Producing 
+Wells 
+Non-Producing 
+Wells 
+Deer Island 
+Louisiana 
+Terrebonne 
+3.13 
+% 
+— 
+— 
+1 
+Napoleonville 
+Louisiana 
+Assumption 
+— 
+2.5 
+% 
+3 
+— 
+Crest 
+Texas 
+Ochiltree 
+2.00 
+% 
+— 
+1 
+— 
+Eagle City South 
+Oklahoma 
+Dewey 
+1.04 
+% 
+— 
+1 
+— 
+Fay South 
+Oklahoma 
+Blaine 
+0.30 
+% 
+— 
+1 
+— 
+Fay East 
+Oklahoma 
+Blaine 
+0.15 
+% 
+— 
+1 
+— 
+Squaw Cheek 
+Oklahoma 
+Blaine 
+0.13 
+% 
+— 
+1 
+— 
+Watonga Chickasha Trend 
+Oklahoma 
+Canadian 
+0.05 
+% 
+— 
+1 
+— 
+Green River Basin 
+Colorado 
+Moffat 
+0.07 
+% 
+— 
+2 
+— 
+Our Equity Investments 
+Grizzly Oil Sands . We, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.9% interest in Grizzly. As of December 31, 2018 , Grizzly had approximately 830,000 net acres under lease in the Athabasca, Peace River and Cold Lake oil sands regions of Alberta, Canada. Grizzly has high-graded three oil sands projects to various stages of development. Grizzly commenced commercial production from its Algar Lake Phase 1 steam-assisted gravity drainage, or SAGD, oil sand project during the second quarter of 2014 and has regulatory approval for up to 11,300 barrels per day of bitumen production. Algar Lake production peaked at 2,200 barrels per day during the ramp-up phase of the SAGD facility, however, in April 2015 , Grizzly made the decision to suspend operations at its Algar Lake facility due to the commodity price drop and its effect on project economics. Grizzly continues to monitor market conditions as it assesses startup plans for the facility. Grizzly also owns the May River property comprising approximately 47,000 acres. An initial 12,000 barrel per day development application covering the eastern portion of the May River lease has been deemed complete from the Alberta Energy Regulator and is awaiting final approval. A 2-D seismic program covering approximately 83 kilometers has been completed to more fully define the resource over the remaining lease beyond the development application area. In 2017, Grizzly advanced plans for cold heavy oil sands production, or CHOPS, at its Cadotte property in Peace River. However, plans for development are dependent on stabilized commodity prices. Grizzly continues to advance rail marketing strategies to ensure consistent and flexible access to premium markets for its future production. Grizzly is also advancing a project to utilize its Windell truck to rail terminal located near Conklin, Alberta, for movement of liquefied petroleum gas, or LPG, into the oil sands area for use in Thermal applications by SAGD producers. 
+Thailand . We own a 23.5% ownership interest in Tatex II. Tatex II, a privately held entity, holds an 8.5% interest in APICO, an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering approximately 108,000 acres which includes the Phu Horm Field. Our investment is accounted for on the equity method. Tatex II accounts for its investment in APICO using the cost method. In December 2006, first gas sales were achieved at the Phu Horm field located in northeast Thailand. Phu Horm's initial gross production was approximately 60 MMcf per day. For 2018 , net gas production was approximately 78 MMcf per day and condensate production was 245 barrels per day. PTT Exploration and Production Public Company Limited operates the field with a 55% interest. Other interest owners include APICO (35% interest) and ExxonMobil (10% interest). Our gross working interest (through Tatex II as a member of APICO) in the Phu Horm field is 0.7%. Since our ownership in the Phu Horm field is indirect and Tatex II's investment in APICO is accounted for by the cost method, these reserves are not included in our year-end reserve information. 
+Other Investments . In connection with Mammoth Energy's initial public offering, or IPO, in October 2016, we received 9,150,000 shares of Mammoth Energy common stock in return for our contribution to Mammoth Energy of our 30.5% interest 
+10 
+Table of Contents 
+Index to Financial Statements 
+in Mammoth Energy Partners LLC. In June 2017, we received an additional 2,000,000 shares of Mammoth Energy common stock in connection with our contribution of all of our equity interests in three other entities to Mammoth Energy. We sold 76,250 shares of our Mammoth Energy common stock in the IPO and an additional 1,354,574 shares in a subsequent underwritten public offering in 2018. As a result, as of December 31, 2018, we owned 9,829,548 shares, or approximately 21.9%, of Mammoth Energy’s outstanding common stock. 
+In February 2016 , we, through our wholly owned subsidiary Gulfport Midstream Holdings, LLC, or Midstream Holdings, entered into an agreement with Rice Midstream Holdings LLC, or Rice, a subsidiary of Rice Energy Inc., to develop natural gas gathering assets in eastern Belmont County and Monroe County, Ohio, which we refer to as the dedicated areas, through a new entity, Strike Force Midstream LLC, or Strike Force. In 2017, Rice was acquired by EQT Corporation, or EQT. Prior to the sale of the Company's interest in Strike Force (discussed below), the Company owned a 25% interest in Strike Force, and EQT acted as operator and owned the remaining 75% interest. Strike Force's gathering assets provide gathering services for wells operated by Gulfport and other operators and connectivity of existing dry gas gathering systems. First flow for Strike Force commenced on February 1, 2016 . In May 2018, the Company sold its 25% interest in Strike Force to EQT Midstream Partners, LP for proceeds of $175.0 million in cash. 
+See Note 4 to our consolidated financial statements included elsewhere in this report for additional information regarding these and our other equity investments. 
+Competition 
+The oil and natural gas industry is intensely competitive, and we compete 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 midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These competitors may be better positioned to take advantage of industry opportunities and to withstand changes affecting the industry, such as fluctuations in oil and natural gas prices and production, the availability of alternative energy sources and the application of government regulation. In addition, oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the availability or price of oil and natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas. 
+Marketing and Customers 
+The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control of our management, including but not limited to the demand for oil and natural gas and the level of domestic production and imports of oil, the proximity and capacity of gas pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of gas sold in interstate commerce. Both our Utica Shale and SCOOP natural gas production is sold to various counterparties through established NAESBs at the plant tailgates and various central delivery points owned and operated by third party midstream companies. Our natural gas production is sold under monthly, seasonal and long-term contracts and, as needed, through daily transactions. When sold in basin, pricing is typically based on Platts Gas Daily - Texas Eastern M2 Zone for our Utica Shale acreage and Platts Gas Daily - Panhandle Tx-Ok and NGPL Midcontinent for our SCOOP acreage. To maintain flow assurance and price stability, and as discussed under "– Transportation and Takeaway Capacity ," we have entered into agreements in both the Utica and SCOOP basins to transport a portion of our natural gas production to various delivery points. These agreements allow us to price the molecules at those various downstream markets less transportation charges. The majority of our Utica oil is sold to purchasers at the tailgate of a condensate stabilizer located near Cadiz, Ohio, owned and operated by MPLX Energy Logistics, or MPLX. Our SCOOP oil is sold at the lease to various purchasers at respective area postings. In Southern Louisiana, our oil is sold to parties taking custody at the lease or at the outlet from a Gulfport oil storage barge. Our NGLs in the Utica Shale are primarily fractionated at MPLX's Hopedale facility. The majority of the product is marketed by the operator with Gulfport receiving the benefit from the MPLX's aggregation and established logistic network. Our SCOOP NGLs are primarily sent to Mont Belvieu on our commitment to DCP Southern Hills and purchased at the fractionation facility. For the year ended December 31, 2018, sales to BP Energy Company, or BP, and ECO-Energy accounted for approximately 17% and 10% , respectively, of our total oil, natural gas and NGL revenues, before the effects of hedging. 
+As of December 31, 2018 , we had an average of approximately 663,000 MMBtu per day of firm sales contracted with third parties for 2019 . We had an average of approximately 526,000 MMBtu per day, 372,000 MMBtu per day, 272,000 MMBtu per day, 255,000 MMBtu per day and 212,000 MMBtu per day contracted with third parties for 2020 , 2021 , 2022 , 2023 and thereafter, respectively. 
+11 
+Table of Contents 
+Index to Financial Statements 
+Transportation and Takeaway Capacity 
+In Ohio and Oklahoma, as of December 31, 2018 , we had entered into firm transportation contracts to deliver approximately 1,205,000 MMBtu to 1,405,000 MMBtu per day for 2019 and 2020. We continuously monitor the need to secure additional firm transportation contracts for incremental volumes from our Utica Shale and SCOOP acreage but expect additional long term contracts to be limited in 2019 . Our primary long-haul firm transportation commitments include the following: 
+• 
+520,000 MMBtu per day of firm capacity on Dominion East Ohio, which began in 2014 and allows us to reach additional connectivity to Gulf Coast and Midwest natural gas markets; 
+• 
+250,000 MMBtu per day of firm capacity on Dominion Transmission, which began in 2015 and allows us to reach additional connectivity to Midwest natural gas markets; 
+• 
+194,000 MMBtu per day of firm capacity on ANR Pipeline Company facilities, which began in 2014 and allows us to reach the Michigan, Chicago and Wisconsin natural gas markets; 
+• 
+200,000 MMBtu per day of firm capacity on Tennessee Gas Pipeline facilities, which began in 2015 and allows us to reach Gulf Coast delivery points; 
+• 
+275,000 MMBtu per day of firm capacity on Rockies Express Pipeline facilities, which began in 2015 and allows us to reach additional connectivity to Gulf Coast and Midwest markets; 
+• 
+50,000 MMBtu per day of firm capacity on Rockies Express Pipeline facilities, which went into partial service in December 2016 and full service in January 2017, allowing additional connectivity to Gulf Coast and Midwest markets; 
+• 
+20,000 MMBtu per day of firm capacity on Natural Gas Pipeline facilities which began in 2015 and allows us to reach Midwest markets; 
+• 
+50,000 MMBtu per day of firm capacity on Texas Gas Transmission facilities which began in 2016 allowing additional access to Gulf Coast delivery points; 
+• 
+54,000 MMBtu per day of firm capacity on Texas Gas Transmission facilities which began in 2017 allowing additional access to Gulf Coast delivery points; 
+• 
+100,000 MMBtu per day of firm capacity on Texas Eastern Transmission facilities which began in 2017 allowing additional access to Midwest delivery points; 
+• 
+150,000 MMBtu per day of firm capacity on Energy Transfer’s Rover Pipeline facilities, 50,000 of which began in 2017 allowing additional access to Midwest delivery points, and 100,000 of which began in 2018 allowing additional access to Canadian, Midwest and Gulf Coast delivery points; and 
+• 
+100,000 MMBtu per day of firm capacity on Columbia Gulf Transmission facilities which began in late 2017 allowing additional access to Gulf Coast delivery points; and 
+• 
+50,000 MMBtu per day of firm capacity on Enable Oklahoma Intrastate which was acquired in early 2017 through our SCOOP acquisition allowing additional connectivity to East Texas and Gulf Coast markets; and 
+• 
+30,000 MMBtu per day of firm capacity on Enable Gas Transmission facilities which was acquired in early 2017 through our SCOOP acquisition allowing additional access to East Texas delivery points; and 
+• 
+20,000 MMBtu per day of firm capacity on Midcontinent Express Pipeline facilities which began mid 2017 allowing additional access to Gulf Coast delivery points; and 
+• 
+50,000 MMBtu per day of firm capacity on Gulf Crossing Pipeline facilities which began mid 2017 allowing additional access to Gulf Coast delivery points; and 
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+Index to Financial Statements 
+• 
+200,000 MMBtu per day of firm capacity on Cheniere Midship Pipeline facilities which will begin in 2019 allowing additional access to East Texas delivery points. 
+Under firm transportation contracts, we are obligated to deliver minimum daily volumes or pay fees for any deficiencies in deliveries. We continue to actively identify and evaluate additional takeaway capacity to facilitate production growth in our Utica Basin and Oklahoma positions. 
+Regulation 
+Regulation of Oil and Natural Gas Production 
+Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability. 
+We own interests in producing oil and natural gas properties located in the Utica Shale primarily in Eastern Ohio, the SCOOP Woodford and SCOOP Springer plays in Oklahoma, along the Louisiana Gulf Coast and in the Niobrara Formation in Northwestern Colorado and the Bakken Formation in Western North Dakota and Eastern Montana. The states in which our fields are located regulate the production and sale of oil and natural gas, including requirements for obtaining drilling permits, the method of developing fields and the spacing and operation of wells. In addition, regulations governing conservation matters aimed at preventing the waste of oil and natural gas resources could affect the rate of production and may include maximum daily production allowables for wells on a market demand or conservation basis. 
+Environmental Regulation 
+Our oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. Numerous governmental agencies, such as the U.S. Environmental Protection Agency, or the EPA, issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically or seismically sensitive areas, and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing earthen pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or related to our owned or operated facilities. Liability under such laws and regulations is often strict (i.e., no showing of “fault” is required) and can be joint and several. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. This trend, however, may not continue in the future. 
+Waste Handling . The Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent non-hazardous waste requirements. Moreover, the EPA or state or local governments may adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Also, in 
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+December 2016, the EPA agreed in a consent decree to review its regulation of oil and gas waste. It has until March 2019 to determine whether any revisions are necessary. Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses. 
+Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes. 
+Remediation of Hazardous Substances . The Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as CERCLA or the “Superfund” law, and analogous state laws, generally impose liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” are subject to strict liability that, in some circumstances, may be joint and several, for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous substances” have been released. 
+Water Discharges . The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” the Safe Drinking Water Act, the Oil Pollution Act, or OPA, and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. Spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers, or the Corps. On June 29, 2015, the EPA and the Corps jointly promulgated final rules redefining the scope of waters protected under the Clean Water Act. The rules are subject to ongoing litigation and have been stayed in more than half the States. Also, on December 11, 2018, the EPA and the Corps released a proposed rule that would replace the 2015 rule, and significantly reduce the waters subject to federal regulation under the Clean Water Act. Such proposal is currently subject to public review and comment, after which additional legal challenges are anticipated. As a result of such recent developments, substantial uncertainty exists regarding the scope of waters protected under the Clean Water Act. To the extent the rule expands the range of properties subject to the Clean Water Act’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. 
+The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. In addition, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants, which regulations are discussed in more detail below under the caption “ -Regulation of Hydraulic Fracturing .” Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. 
+The OPA is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict liability that, in some circumstances, may be joint and 
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+several for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters. 
+Noncompliance with the Clean Water Act or the OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws. 
+Air Emissions . The federal Clean Air Act, as amended, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, on August 16, 2012, the EPA published final regulations under the federal Clean Air Act that establish new emission controls for oil and natural gas production and processing operations, which regulations are discussed in more detail below under the caption “ -Regulation of Hydraulic Fracturing .” Also, on May 12, 2016, the EPA issued a final rule regarding the criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements. These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects. 
+Climate Change . In recent years, federal, state and local governments have taken steps to reduce emissions of greenhouse gases. The EPA has finalized a series of greenhouse gas monitoring, reporting and emission control rules for the oil and natural gas industry and the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Although the U.S. Congress has not adopted such legislation at this time, it may do so in the future and many states continue to pursue regulations to reduce greenhouse gas emissions. 
+In December 2015, the United States participated in the 21st Conference of the Parties, or COP-21, of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global temperature, and to conserve and enhance sinks and reservoirs of GHGs. The Agreement went into effect on November 4, 2016. The Agreement establishes a framework for the parties to cooperate and report actions to reduce GHG emissions. However, on June 1, 2017, President Trump announced that the United States would withdraw from the Paris Agreement, and begin negotiations to either re-enter or negotiate an entirely new agreement with more favorable terms for the United States. The Paris Agreement sets forth a specific exit process, whereby a party may not provide notice of its withdrawal until three years from the effective date, with such withdrawal taking effect one year from such notice. It is not clear what steps the Trump Administration plans to take to withdraw from the Paris Agreement, whether a new agreement can be negotiated, or what terms would be included in such an agreement. Furthermore, in response to the announcement, many state and local leaders have stated their intent to intensify efforts to uphold the commitments set forth in the international accord. 
+Restrictions on emissions of methane or carbon dioxide that may be imposed could adversely impact the demand for, price of and value of our products and reserves. As our operations also emit greenhouse gases directly, current and future laws or regulations limiting such emissions could increase our own costs. Currently, while we are subject to certain federal GHG monitoring and reporting requirements, our operations are not adversely impacted by existing federal, state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business. 
+There have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. Furthermore, claims have been made against certain energy companies alleging that GHG emissions from oil and natural gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages or other liabilities. While we are not a party to any such litigation, we could be named in actions making similar 
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+allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition. 
+Moreover, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially hotter or colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations. 
+Endangered Species Act 
+Environmental laws such as the Endangered Species Act, or the ESA and analogous state statutes, may impact exploration, development and production activities on public or private lands. The ESA provides broad protection for species of fish, wildlife and plants that are listed as threatened or endangered in the U.S., and restricts activities that may adversely affect listed species or their habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act, though, in December 2017, the U.S. Fish and Wildlife Service provided guidance limiting the reach of the Act. Federal agencies are required to insure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed species or modify their critical habitat. While some of our facilities may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. The U.S. Fish and Wildlife Service may identify, however, previously unidentified endangered or threatened species or may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species, which could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas. 
+Occupational Safety and Health Act 
+We are also subject to the requirements of the Occupational Safety and Health Act, or OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements. 
+Regulation of Hydraulic Fracturing 
+Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. We use hydraulic fracturing extensively in the development of our Utica Shale and SCOOP acreage. The federal Safe Drinking Water Act, or SDWA, regulates the underground injection of substances through the Underground Injection Control, or UIC, program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions. However, legislation has been proposed in recent sessions of Congress to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection,” to require federal permitting and regulatory control of hydraulic fracturing, and to require disclosure of the chemical constituents of the fluids used in the fracturing process. Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program, specifically as “Class II” UIC wells. 
+Additionally, on June 28, 2016, EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants. The EPA is also conducting a study of private wastewater treatment facilities (also known as centralized waste treatment, or CWT, facilities) accepting oil and gas extraction wastewater. The EPA is collecting data and information related to the extent to which CWT facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of CWT facilities, and the environmental impacts of discharges from CWT facilities. 
+On August 16, 2012, the EPA published final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes NSP standards to address emissions of sulfur dioxide and volatile organic compounds, or VOCs, and a separate set of emission 
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+standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule seeks to achieve a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. In response, the EPA has issued, and will likely continue to issue, revised rules responsive to some of the requests for reconsideration. In particular, on May 12, 2016, the EPA amended its regulations to impose new standards for methane and VOC emissions for certain new, modified and reconstructed equipment, processes and activities across the oil and natural gas sector. However, in a March 28, 2017 executive order, President Trump directed the EPA to review the 2016 regulations and, if appropriate, to initiate a rule making to rescind or revise them consistent with the stated policy of promoting clean and safe development of the nation’s energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production. On June 16, 2017, the EPA published a proposed rule to stay for two years certain requirements of the 2016 regulations, including fugitive emission requirements. Also, on October 15, 2018, the EPA published a proposed rule to significantly reduce regulatory burdens imposed by the 2016 regulations, including, for example, reducing the monitoring frequency for fugitive emissions and revising the requirements for pneumatic pumps at well sites. The above standards, to the extent implemented, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or mandate the use of specific equipment or technologies to control emissions. 
+In addition, on March 26, 2015, the Bureau of Land Management, or BLM, published a final rule governing hydraulic fracturing on federal and Indian lands. The rule requires public disclosure of chemicals used in hydraulic fracturing, implementation of a casing and cementing program, management of recovered fluids, and submission to the BLM of detailed information about the proposed operation, including wellbore geology, the location of faults and fractures, and the depths of all usable water. Also, on November 15, 2016, the BLM finalized a waste prevention rule to reduce the flaring, venting and leaking of methane from oil and gas operations on federal and Indian lands. The rule requires operators to use currently available technologies and equipment to reduce flaring, periodically inspect their operations for leaks, and replace outdated equipment that vents large quantities of gas into the air. The rule also clarifies when operators owe the government royalties for flared gas. On March 28, 2017, President Trump signed an executive order directing the BLM to review the above rules and, if appropriate, to initiate a rulemaking to rescind or revise them. Accordingly, on December 29, 2017, the BLM published a final rule to rescind the 2015 hydraulic fracturing rule; however, a coalition of environmentalists, tribal advocates and the state of California filed lawsuits challenging the rule rescission. Also, on February 22, 2018, the LM published proposed amendments to the waste prevention rule that would eliminate certain air quality provisions and, on April 4, 2018, a federal district court stayed certain provisions of the 2016 rule. At this time, it is uncertain when, or if, the rules will be implemented, and what impact they would have on our operations. 
+Furthermore, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. On December 13, 2016, the EPA released a study examining the potential for hydraulic fracturing activities to impact drinking water resources, finding that, under some circumstances, the use of water in hydraulic fracturing activities can impact drinking water resources. Also, on February 6, 2015, the EPA released a report with findings and recommendations related to public concern about induced seismic activity from disposal wells. The report recommends strategies for managing and minimizing the potential for significant injection-induced seismic events. Other governmental agencies, including the U.S. Department of Energy, the U.S. Geological Survey, and the U.S. Government Accountability Office, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing, and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business. 
+Some states and local jurisdictions in which we operate or hold oil and natural gas interests have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids. If new or more stringent state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells. 
+There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are 
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+adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal, state or local level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal, state or local laws governing hydraulic fracturing. 
+Other Regulation of the Oil and Natural Gas Industry 
+The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production. 
+The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, natural gas storage and various other matters, primarily by the Federal Energy Regulatory Commission, or FERC. Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. FERC's regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas. 
+Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. We cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of condensate and natural gas liquids are not currently regulated and are made at market prices. 
+Drilling and Production . Our operations are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The states and some counties and municipalities in which we operate also regulate one or more of the following: 
+• 
+the location of wells; 
+• 
+the method of drilling and casing wells; 
+• 
+the timing of construction or drilling activities, including seasonal wildlife closures; 
+• 
+the rates of production or “allowables”; 
+• 
+the surface use and restoration of properties upon which wells are drilled; 
+• 
+the plugging and abandoning of wells; and 
+• 
+notice to, and consultation with, surface owners and other third parties. 
+State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. 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 requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce 
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+from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or to limit the number of locations we can drill. 
+Federal, state and local regulations provide detailed requirements for the plugging and abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements. 
+Natural Gas Sales and Transportation . Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production. Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. 
+FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and release of our natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC's initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities. 
+Under FERC’s current regulatory regime, transmission services are provided on an open-access, non-discriminatory basis at cost-based rates or at negotiated rates. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of transporting gas to point-of-sale locations. 
+Oil Sales and Transportation . Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future. 
+Our crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors. 
+Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines' published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors. 
+State Regulation . The states in which we operate regulate the drilling for, and the production and gathering of, oil and natural gas, including through requirements relating to the method of developing new fields, the spacing and operation of wells 
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+and the prevention of waste of oil and natural gas resources. States may also regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill. 
+In July 2015, the Ohio Department of Natural Resources, or the ODNR, enacted a comprehensive set of rules to regulate the construction of horizontal well pads. Under these new rules, operators must submit detailed horizontal well pad design packages prepared by a professional engineer for review and certification by the ODNR Division of Oil and Gas Resources Management prior to the commencement of any oil and natural gas activity. These rules resulted in increased construction costs for operators. Furthermore, pursuant to new rules approved in August 2016, operators must immediately notify ODNR regarding certain oil and natural gas releases. Also, on November 20, 2018, Ohio EPA announced that it intends to develop new rules that would cover air pollution emissions associated with non-conventional oil and gas facilities. 
+The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us. 
+Operational Hazards and Insurance 
+The oil and natural gas business involves a variety of operating risks, including the risk of fire, explosions, blow outs, pipe failures and, in some cases, abnormally high pressure formations which could lead to environmental hazards such as oil spills, natural gas leaks and the discharge of toxic gases. If any of these should occur, we could incur legal defense costs and could be required to pay amounts due to injury, loss of life, damage or destruction to property, natural resources and equipment, pollution or environmental damage, regulatory investigation and penalties and suspension of operations. 
+In accordance with what we believe to be industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We insure some, but not all, of our properties for operational and hurricane related events. We currently have insurance policies that include coverage for general liability, physical damage to our oil and natural gas properties, operational control of certain wells, oil pollution, third party liability, workers compensation, cyber and employers' liability and other coverage. Our insurance coverage includes deductibles that must be met prior to recovery. Additionally, our insurance is subject to exclusions and limitations, and there is no assurance that such coverage will fully or adequately protect us against liability from all potential consequences, damages and losses. Any of these events could cause a significant disruption to our business. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows. 
+Currently, we have general liability insurance coverage with an annual aggregate limit of up to $101.0 million which includes sudden and accidental pollution for the effects of onshore and offshore pollution on third parties arising from our operations as well as $10.0 million of gradual pollution insurance coverage. For our offshore WCBB properties, we also have a $52.0 million property physical damage policy which insures against most operational perils, such as explosions, fire, vandalism, theft, hail and windstorms, provided, however, that this policy is limited to $16.0 million for damages arising as a result of a named windstorm. All of our insurance coverage includes deductibles of up to $250,000 per occurrence ($1.75 million in the case of a named windstorm) that must be met prior to recovery. Additionally, our insurance is subject to customary exclusions and limitations. We reevaluate the purchase of insurance, policy terms and limits annually. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable and we may elect to maintain minimal or no insurance coverage. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. The occurrence of a significant event, not fully insured against, could have a material adverse effect on our financial condition and results of operations. 
+We carry control of well insurance for all of our Utica Shale and SCOOP wells and several Southern Louisiana wells. We also require all of our third party vendors to sign master service agreements in which they agree to indemnify us for injuries and deaths of the service provider's employees as well as contractors and subcontractors hired by the service provider. 
+We have prepared and have in place spill prevention control and countermeasure plans for each of our principal facilities in response to federal and state requirements. The plans are reviewed annually and updated as necessary. As required by 
+20 
+Table of Contents 
+Index to Financial Statements 
+applicable regulations, our facilities are built with secondary containment systems to capture potential releases. We also own additional spill kits with oil booms and absorbent pads that are readily available, if needed. In addition, we have emergency response companies on retainer. These companies specialize in the clean up of hydrocarbons as a result of spills, blow-outs and natural disasters, and are on call to us 24 hours a day, seven days a week when their services are needed. We pay these companies a retainer plus additional amounts when they provide us with clean up services. Our aggregate payments for the retainer and clean up services during 2018 and 2017 were approximately $0.6 million and $0.2 million. While these companies have been able to meet our service needs when required from time to time in the past, it is possible that the ability of one or more of them to provide services to us in the future, if and when needed, could be hindered or delayed in the event of a widespread disaster. However, in light of the areas in which we operate and the nature of our production, we believe other companies would be available to us in the event our primary remediation companies are unable to perform. To supplement our planning and operation activities in Ohio, Oklahoma and Louisiana, we also actively manage an incident response planning program and coordinate with applicable state agency personnel on spills and releases through the Ohio, Oklahoma and Louisiana Incident Notification Hotlines. We also participate in the Ohio, Oklahoma and Louisiana Emergency Planning and Community Right to Know Act (EPCRA) programs, which includes reporting of various materials used or stored on-site as well as notification to state and local emergency response centers, such as local fire departments, for emergency planning purposes. 
+Headquarters and Other Facilities 
+We own an office building with approximately 120,000 square feet of office space in Oklahoma City, Oklahoma that serves as our corporate headquarters. We also own an approximately 28,500 square foot office building in Oklahoma City, Oklahoma where some of our employees office. 
+We own an approximately 12,300 square foot building located in St. Clairsville, Ohio that serves as our headquarters for our Ohio operations. We also own an approximately 12,500 square foot building in Lafayette, Louisiana. This building contains approximately 6,200 square feet of finished office area and 6,300 square feet of clear span warehouse area. We lease approximately 3,700 square feet in a building in Lafayette that we use as our Louisiana headquarters. We also lease an office in Lindsay, Oklahoma that serves as our Oklahoma production field office. Each of these properties is suitable and adequate for its use. 
+Employees 
+At December 31, 2018 , we had 350 employees. 
+Availability of Company Reports 
+Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on the Investor Relations page of our website at www.gulfportenergy.com as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. Information contained on our website, or on other websites that may be linked to our website, is not incorporated by reference into this annual report on Form 10-K and should not be considered part of this report or any other filing that we make with the SEC.

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+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+For information concerning Item 13-Certain Relationships and Related Transactions, and Director Independence, see our definitive proxy statement, which will be filed with the Securities and Exchange Commission with 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference).

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+ITEM 9A. 
+CONTROLS AND PROCEDURES 
+Evaluation of Disclosure Control and Procedures . Under the direction of our Chief Executive Officer and President and our Chief Financial Officer, we have established disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized 
+74 
+Table of Contents 
+Index to Financial Statements 
+and reported within the time periods specified in the SEC's rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and President and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures. 
+As of December 31, 2018 , an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and President and our Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and President and our Chief Financial Officer have concluded that, as of December 31, 2018 , our disclosure controls and procedures are effective. 
+Changes in Internal Control over Financial Reporting . There have not been any changes in our internal control over financial reporting that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting. 
+Management's Report on Internal Control Over Financial Reporting 
+Management is responsible for the fair presentation of the consolidated financial statements of Gulfport Energy Corporation. Management is also responsible for establishing and maintaining a system of adequate internal controls over financial reporting as defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. These internal controls are designed to provide reasonable assurance that the reported financial information is presented fairly, that disclosures are adequate and that the judgments inherent in the preparation of financial statements are reasonable. There are inherent limitations in the effectiveness of any system of internal control, including the possibility of human error and overriding of controls. Consequently, an effective internal control system can only provide reasonable, not absolute, assurance with respect to reporting financial information. 
+Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in the 2013 Internal Control-Integrated Framework , management did not identify any material weaknesses in our internal control over financial reporting and concluded that our internal control over financial reporting was effective as of December 31, 2018 . 
+Grant Thornton LLP, the independent registered public accounting firm that audited our financial statements for the year ended December 31, 2018 included with this Annual Report on Form 10-K, has also audited our internal control over financial reporting as of December 31, 2018 , as stated in their accompanying report. 
+/s/ David M. Wood 
+/s/ Keri Crowell 
+Name: 
+David M. Wood 
+Name: 
+Keri Crowell 
+Title: 
+Chief Executive Officer and President 
+Title: 
+Chief Financial Officer 
+75 
+Table of Contents 
+Index to Financial Statements 
+Report of Independent Registered Public Accounting Firm 
+Board of Directors and Stockholders 
+Gulfport Energy Corporation 
+Opinion on internal control over financial reporting 
+We have audited the internal control over financial reporting of Gulfport Energy Corporation (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2018 , based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in the 2013 Internal Control-Integrated Framework issued by COSO. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) ("PCAOB"), the consolidated financial statements of the Company as of and for the year ended December 31, 2018, and our report dated February 28, 2019 expressed an unqualified opinion on those financial statements. 
+Basis for opinion 
+The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+Definition and limitations of internal control over financial reporting 
+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. 
+/s/ GRANT THORNTON LLP 
+Oklahoma City, Oklahoma 
+February 28, 2019 
+76 
+Table of Contents 
+Index to Financial Statements

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+Certain Relationships and Related Transactions Review and
+Approval of Related Party Transactions 
+The audit committee, as provided in its charter, reviews and approves related party transactions. The Company
+does not have a formal set of standards to be substantively applied to each transaction reviewed by the audit committee. Instead of a formalized policy, related party transactions are reviewed and judgment is applied to determine whether such
+transactions are in the best interests of the Company. Further, the Company’s Code of Business Conduct and Ethics governs various compliance areas, including conflicts of interest and fair dealings, which are considered in the process of the
+review and approval of related party transactions. 
+The Company’s policy is that all of its employees and directors, as well as their family members,
+must avoid any activity that is or has the appearance of conflicting with the Company’s business interest. This policy is included in the Company’s Code of Business Conduct and Ethics posted on its website. Each director and executive
+officer is instructed to always inform the designated compliance officer when confronted with any situation that may be perceived as a conflict of interest. Only the board of directors or a committee consisting solely of independent directors may
+grant waivers of the provisions of the Code of Business Conduct and Ethics for the Company’s executive officers and directors. In addition, at least annually, each director and executive officer completes a detailed questionnaire specifying any
+business relationship that may give rise to a conflict of interest. 
+Further, under the audit committee charter, the audit committee is responsible for
+reviewing and monitoring compliance with our Code of Business Conduct and Ethics and recommending any warranted changes to the board of directors. In addition, the board of directors and, pursuant to its written charter, the audit committee, reviews
+and approves all relationships and transactions in which the Company and its directors, director nominees and executive officers and their immediate family members, as well as holders of more than 5% of any class of our voting securities and their
+family members, have a direct or indirect material interest. The board of directors and the audit committee approve only those transactions that, in light of known circumstances, are consistent, or are not inconsistent with, the Company’s best
+interests, as they determine in the good faith exercise of their discretion. 
+Separation Agreement with Our Former Chief Executive Officer and
+President and Other Related Party Transaction 
+Michael G. Moore stepped down from his position as our Chief Executive Officer and President, and as a
+member of our board of directors, effective as of October 29, 2018. In connection with Mr. M. Moore’s departure, we entered into a separation agreement with Mr. M. Moore. For a description of Mr. M. Moore’s severance
+and other provisions of his separation agreement with us, see “Severance Agreement with our Former Chief Executive Officer and President” above. 
+AMM Design, Inc., or AMM, provided landscape and related services to the third party building manager for our offices in Oklahoma City in 2018. We paid the
+building manager approximately $149,000 in respect of these services. AMM is owned by the son of Michael G. Moore, our former Chief Executive Officer and President.

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+Approval of Related Party Transactions 
+The Audit Committee, as provided in its charter, reviews and approves related party transactions. The Company does not have a formal set of standards to be substantively applied to each transaction reviewed by the Audit Committee. Instead of a formalized policy, related party transactions are reviewed and judgment is applied to determine whether such transactions are in the best interests of the Company. The Company’s Code of Business Conduct and Ethics governs various compliance areas, including conflicts of interest and fair dealings, which are considered in the process of the review and approval of related party transactions. 
+The Company’s policy is that all its employees and directors, as well as their family members, must avoid any activity that is or has the appearance of conflicting with the Company’s business interest. This policy is included in the Company’s Code of Business Conduct and Ethics posted on its website. Each director and executive officer is instructed to always inform the designated compliance officer when confronted with any situation that may be perceived as a conflict of interest. Only the Board of Directors or a committee consisting solely of independent directors may grant waivers of the provisions of the Code of Business Conduct and Ethics for the Company’s executive officers and directors. In addition, at least annually, each director and executive officer completes a detailed questionnaire specifying any business relationship that may give rise to a conflict of interest. 
+Under the Audit Committee charter, the Audit Committee is responsible for reviewing and monitoring compliance with our Code of Business Conduct and Ethics and recommending any warranted changes to the Board of Directors. In addition, the Board of Directors and, pursuant to its written charter, the Audit Committee, reviews and approves all relationships and transactions in which the Company and its directors, director nominees and executive officers and their immediate family members, as well as holders of more than 5% of any class of our voting securities and their family members, have a direct or indirect material interest. The Board of Directors and the Audit Committee approve only those transactions that, in light of known circumstances, are consistent, or are not inconsistent with, the Company’s best interests, as they determine in the good faith exercise of their discretion.

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+ITEM 1. BUSINESS 
+Our Business 
+A Delaware corporation formed in 1997, we are an independent natural gas-weighted exploration and production company with assets primarily located in the Appalachia and Anadarko basins. Our corporate strategy is focused on the economic development of our asset base in an effort to generate sustainable free cash flow. Our principal properties are located in Eastern Ohio, where we target development in the Utica formation, and Central Oklahoma where we target development in the SCOOP Woodford and Springer formations. 
+As of December 31, 2020, we had 2.6 Tcfe of proved reserves with a standardized measure of discounted future net cash flows of $540.0 million and a PV-10 of $540.0 million. See " Definitions " above for our definition of PV-10 (a non-GAAP financial measure) and " Oil, Natural Gas and NGL Reserves " below for a reconciliation of our standardized measure of discounted future net cash flows (the most directly comparable GAAP measure) to PV-10. 
+Information About Us 
+Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on the Investor Relations page of our website at www.gulfportenergy.com as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. From time to time, we also post announcements, updates, events, investor information and presentations on our website in addition to copies of our recent news releases. Information contained on our website, or on other websites that may be linked to our website, is not incorporated by reference into this annual report on Form 10-K and should not be considered part of this report or any other filing that we make with the SEC. 
+Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code 
+On November 13, 2020, Gulfport Energy Corporation, Gator Marine, Inc., Gator Marine Ivanhoe, Inc., Grizzly Holdings, Inc., Gulfport Appalachia, LLC, Gulfport Midcon, LLC, Gulfport Midstream Holdings, LLC, Jaguar Resources LLC, Mule Sky LLC, Puma Resources, Inc. and Westhawk Minerals LLC filed voluntary petitions of relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court for the Southern District of Texas. The Chapter 11 Cases are being administered jointly under the caption In re Gulfport Energy Corporation, et al ., Case No. 20-35562 (DRJ). Information about our Chapter 11 cases is available at our website (www.gulfportenergy.com). 
+We are currently operating our business and managing our properties as debtors in possession pursuant to sections 1107(a) and 1108 of the Bankruptcy Code. On November 14, 2020, the Bankruptcy Court entered an order authorizing the joint administration and procedural consolidation of these Chapter 11 Cases pursuant to Bankruptcy Rule 1015(b). At the first day hearing on November 16, 2020, the Bankruptcy Court granted certain requested relief enabling us to conduct our business activities in the ordinary course, including, among other things and subject to the terms and conditions of such orders, authorizing us to pay employee wages and benefits, pay taxes and certain governmental fees and charges, continue to operate our cash management system in the ordinary course, remit funds we hold from time to time for the benefit of third parties (such as royalty owners), and pay the pre-petition claims of certain of our vendors that hold liens under applicable non-bankruptcy law. For goods and services provided following the Petition Date, we are permitted and intend to pay vendors in the ordinary course. 
+Subject to certain exceptions provided for in section 362 of the Bankruptcy Code, all judicial and administrative proceedings against us or our property were automatically enjoined, or stayed, as of the Petition Date. In addition, the filing of new judicial or administrative actions against us or our property for claims arising prior to the date on which our Chapter 11 Cases were filed were automatically enjoined. This prohibits, for example, our lenders or noteholders from pursuing claims for defaults under our debt agreements and our contract counterparties from pursuing claims for defaults under our contracts. Accordingly, unless the Bankruptcy Court agrees to lift the automatic stay, all of our pre-petition liabilities and obligations should be settled or compromised under the Bankruptcy Code as part of our Chapter 11 proceedings. 
+Our operations and ability to execute our business remain subject to the risks and uncertainties described in Item 1A.“Risk Factors”. In addition, our assets, liabilities, capital structure, shareholders, officers and directors could change materially because of our Chapter 11 Cases. In addition, the description of our operations, properties and capital plans included in this 
+4 
+Table of Contents 
+Index to Financial Statement s 
+Annual Report on Form 10-K may not accurately reflect our operations, properties and capital plans after we emerge from Chapter 11. 
+Business Strategy 
+Gulfport aims to create sustainable value through the development of our significant resource plays in the Utica and SCOOP operating areas. Our strategy is to develop our assets in a manner that generates sustainable cash flow and improves margins and operating efficiencies, while maintaining exceptional environmental and safety performance. To accomplish these goals, we allocate capital expenditures to projects we believe offer the highest rate of return and we deploy leading drilling and completion techniques and technologies in our development efforts. 
+As noted above, we are currently engaged in an in-court restructuring process to improve our balance sheet strength, cost structure and financial strength and flexibility. 
+Operating Areas 
+We foc us our development and production activities in the geographic operating areas described below. 
+Utica - The Utica is a hydrocarbon bearing rock formation located in the Appalachian Basin of the United States and Canada. We have approximately 193,000 net reservoir acres located primarily in Belmont, Harrison, Jefferson and Monroe Counties in Eastern Ohio where the Utica ranges in thickness from 600 to over 750 feet. During the fourth quarter of 2020 we produced approximately 887 MMcfe per day net to our interests in this area and accounts for approximately 82% of our total production. 
+SCOOP - The SCOOP, or South Central Oklahoma Oil Province, is a defined area that encompasses many of the top hydrocarbon producing counties in Oklahoma within the Anadarko basin. The SCOOP play mainly targets the Devonian to Mississippian aged Woodford, Sycamore and Springer formations. We have approximately 73,000 net reservoir acres (comprised of approximately 40,000 in the Woodford formation and approximately 33,000 in the Springer formation) located primarily in Garvin, Grady and Stephens Counties. The Woodford Shale across our position ranges in thickness from 200 to over 400 feet and directly overlies the Hunton Limestone and underlies the Sycamore formation, both of which are also locally productive reservoirs. The Sycamore formation consists of hydrocarbon-bearing interbedded shales and siliceous limestones ranging in thickness from 150 to over 450 feet and is overlain by the Caney Shale. The Springer formation across our position is comprised of a series of lenticular sand and shale units. The primary targets are a series of porous, low clay and organic-rich packages within the Goddard Shale member ranging in thickness fro m 50 to over 250 feet. During the fourth quarter of 2020, we produced approximately 189 MMcfe per day net to our interests in this area and accounts for approximately 18% of our total production. 
+Additional Properties - In addition to our core properties discussed above, we also own working interests and overriding royalty interest in various fields including the Bakken formation in North Dakota that account for less than 1% of our total production and proved reserves. 
+Drilling Activity 
+The following table sets forth information with respect to operated wells drilled during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return. 
+5 
+Table of Contents 
+Index to Financial Statement s 
+2020 2019 2018 
+Gross Net Gross Net Gross Net 
+Recompletions: 
+Productive — — — — 47 47 
+Dry — — — — — — 
+Total — — — — 47 47 
+Development: 
+Productive 26 24.4 25 22.4 34 30 
+Dry — — — — — — 
+Total 26 24.4 25 22.4 34 30 
+Exploratory: 
+Productive — — 1 0.8 2 1.5 
+Dry — — — — — — 
+Total — — 1 0.8 2 1.5 
+The following table presents activity by operating area for the year ended December 31, 2020: 
+Operated Non-Operated 
+Field Drilled Turned to Sales Drilled Turned to Sales 
+Gross Net Gross Net Gross Net Gross Net 
+Utica (1) 
+16 16.0 25 23.8 — — — — 
+SCOOP (2) 
+10 8.4 4 3.8 19 0.05 12 0.04 
+Total 26 24.4 29 27.6 19 0.05 12 0.04 
+_____________________ 
+(1) Of the 16 gross wells we drilled in 2020, nine were completed as producing wells and seven were in various stages of completion as of December 31, 2020. 
+(2) Of the 10 gross wells we drilled in 2020, zero were completed as producing wells and 10 were in various stages of completion as of December 31, 2020. 
+Acreage 
+The following table presents our total gross and net productive and non-productive wells, expressed separately for oil and gas, and the total gross and net developed and undeveloped acres as of December 31, 2020. 
+Average NRI/WI Productive 
+Oil Wells Productive 
+Gas Wells Non-Productive 
+Oil Wells Non-Productive 
+Gas Wells Developed 
+Acreage Undeveloped 
+Acreage 
+Field Percentages Gross Net Gross Net Gross Net Gross Net Gross Net Gross Net 
+Utica 46.78/57.29 146 42.1 501 328.7 2 0.7 11 6.6 120,699 93,598 106,418 99,265 
+SCOOP 24.43/30.32 105 18.3 508 163.2 7 1.0 33 15.5 49,325 34,421 8,294 5,941 
+Other Various 14 0.2 9 — — — — — 1,021 395 4,145 1,021 
+Overrides/Royalty Non-operated 0.16/0.0 459 — 86 — 2 — 1 — — — — — 
+Total 724 60.6 1,104 491.9 11 1.7 45 22.1 171,045 128,414 118,857 106,227 
+Of our leases that are not held by production, most have a three- to five-year primary term, many of which include options to extend the primary term. We manage lease expirations to ensure that we do not experience unintended material expirations. Our leasehold management efforts include scheduling our operations to establish production in paying quantities in order to hold leases prior to the expiration dates, paying the prescribed lease extension payments, planning non-core divestitures or strategic acreage trades with other operators to high-grade our lease inventory and letting some leases expire that are no longer part of our development plans. The following table sets forth the potential expiration periods of gross and net undeveloped leasehold acres as of December 31, 2020. 
+6 
+Table of Contents 
+Index to Financial Statement s 
+Undeveloped Acres 
+Gross Acres Net Acres 
+Years Ending December 31: 
+2021 13,488 12,508 
+2022 16,438 14,880 
+2023 16,191 15,290 
+After 2023 3,291 3,006 
+Held by production or operations 69,449 60,543 
+Total 118,857 106,227 
+Oil, Natural Gas and NGL Reserves 
+The tables below set forth information as of December 31, 2020, with respect to our estimated proved reserves, the associated estimated future net revenue, the PV-10 and the standardized measure. None of the estimated future net revenue, PV-10 nor the standardized measure are intended to represent the current market value of the estimated oil, natural gas and NGL reserves we own. All of our estimated reserves are located within the United States. 
+December 31, 2020 
+Oil 
+(MMBbl) Natural 
+Gas 
+(Bcf) NGL (MMBbl) Total (Bcfe) 
+Proved developed 7 1,358 22 1,527 
+Proved undeveloped 7 923 16 1,061 
+Total proved (1) 
+13 2,281 38 2,588 
+Totals may not sum or recalculate due to rounding. 
+Proved Developed Proved Undeveloped Total Proved 
+($ in millions) 
+Estimated future net revenue (2) 
+$ 679 $ 285 $ 964 
+Present value of estimated future net revenue (PV-10) (2) 
+$ 504 $ 36 $ 540 
+Standardized measure (2) 
+$ 540 
+_____________________ 
+(1) Utica and SCOOP accounted for approximately 67% and 33%, respectively, of our estimated proved reserves by volume as of December 31, 2020. 
+(2) Estimated future net revenue represents the estimated future revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs under existing economic conditions as of December 31, 2020, and assuming commodity prices as set forth below. For the purpose of determining prices used in our reserve reports, we used the unweighted arithmetic average of the prices on the first day of each month within the 12-month period ended December 31, 2020. The prices used in our PV-10 measure were $39.54 per barrel and $1.99 per MMBtu, before basis differential adjustments. These prices should not be interpreted as a prediction of future prices, nor do they reflect the value of our commodity derivative instruments in place as of December 31, 2020. 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. The present value of estimated future net revenue typically differs from the standardized measure because the former does not include the effects of estimated future income tax expense. There was no effect of estimated future income tax expense as of December 31, 2020, primarily as a result of significant net operating loss carryforwards that can be used to offset income taxes on future taxable income. 
+Management uses PV-10, which is calculated without deducting estimated future income tax expenses, as a measure of the value of the Company's current proved reserves and to compare relative values among peer companies. We also 
+7 
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+Index to Financial Statement s 
+understand that securities analysts and rating agencies use this measure in similar ways. While estimated future net revenue and the present value thereof are based on prices, costs and discount factors which may be consistent from company to company, the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each individual company. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows or any other measure of a company's financial or operating performance presented in accordance with GAAP. 
+A reconciliation of the standardized measure of discounted future net cash flows to PV-10 is presented above. Neither PV-10 nor the standardized measure of discounted future net cash flows purport to represent the fair value of our proved oil and gas reserves. 
+_____________________ 
+Grizzly had no proved reserves as of December 31, 2020. For further discussion of our interest in Grizzly, see “ Our Equity Investments ” below. 
+Reserve engineering is a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. See Item 1A. “ Risk Factors ” contained elsewhere in this Form 10-K. We have not filed any estimates of total, proved net oil or gas reserves with any federal authority or agency other than the SEC since the beginning of our last fiscal year. 
+Changes in Proved Reserves during 2020. 
+The following table summarizes the changes in our estimated proved reserves during 2020 (in Bcfe): 
+Proved Reserves, December 31, 2019 4,528 
+Sales of oil and natural gas reserves in place (75) 
+Extensions and discoveries 240 
+Revisions of prior reserve estimates (1,725) 
+Current production (380) 
+Proved Reserves, December 31, 2020 2,588 
+Sales of oil and natural gas reserves in place. These are reductions to proved reserves resulting from the divestiture of minerals in place during a period. During 2020, we sold approximately 74.9 Bcfe of proved oil and natural gas reserves through various sales of our non-operated interests in our Utica assets. 
+Extensions and discoveries. These are additions to our proved reserves that result from extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery. Extensions of approximately 239.8 Bcfe of proved reserves were primarily attributable to the continued development of our Utica and SCOOP acreage. We added 14 PUD locations in our Utica acreage for 150.6 Bcfe and eight PUD locations in our SCOOP acreage for 87.8 Bcfe. The commodity prices utilized for the 2020 reserves determination as well as our revised five-year development plan focused on generating sustainable cash flow limited our ability to add significant well locations. 
+Revisions of prior reserve estimates. Revisions represent changes in previous reserve estimates, either upward or downward, resulting from development plan changes, new information normally obtained from development drilling and production history or a change in economic factors, such as commodity prices, operating costs or development costs. 
+We experienced total downward revisions of 1.7 Tcfe in estimated proved reserves, of which 1,268.4 Bcfe was the result of commodity price changes. Commodity prices experienced volatility throughout 2020 and the 12-month average price for natural gas decreased from $2.58 per MMBtu for 2019 to $1.99 per MMBtu for 2020, the 12-month average price for NGL decreased from $21.25 per barrel for 2019 to $15.40 per barrel for 2020, and the 12-month average price for crude oil decreased from $55.85 per barrel for 2019 to $39.54 per barrel for 2020. 
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+An additional 720.3 Bcfe in downward revisions was a result of the exclusion of 48 PUD locations in our Utica field and 31 PUD locations in our SCOOP field when changes in our schedule moved development of these PUD locations beyond five years of initial booking. The development plan change reflects our commitment to capital discipline and funding future activities within cash flow and ongoing optimization of our development plan. 
+Positive revisions of 263.8 Bcfe were experienced from a combination of operating and development cost improvements, well performance and working interest changes. 
+Additional information regarding estimates of proved reserves, proved developed reserves and proved undeveloped reserves at December 31, 2020, 2019 and 2018 and changes in proved reserves during the last three years are contained in the Supplemental Information on Oil and Gas Exploration and Production Activities, or Supplemental Information , in Note 19 of the notes to our consolidated financial statements included in this report. 
+Proved Undeveloped Reserves (PUDs) 
+As of December 31, 2020, our proved undeveloped reserves totaled 7 MMBbl of oil, 923 Bcf of natural gas and 16 MMBbl of NGL, for a total of 1,061 Bcfe. Approximately 60% and 40% of our PUD reserves at year-end 2020 were located in Utica and SCOOP, respectively. PUDs will be converted from undeveloped to developed as the applicable wells commence production or there are no material incremental completion capital expenditures associated with such proved developed reserves. 
+We record PUD reserves only after a development plan has been approved by our senior management and board of directors to complete the associated development drilling within five years from the time of initial booking. The PUD locations identified in our development plan are determined based on an analysis of the information that we have available at that time. After a development plan has been adopted, we may periodically make adjustments to the approved development plan due to events and circumstances that have occurred subsequent to the time the plan was approved. These circumstances may include changes in commodity price outlook and costs, delays in the availability of infrastructure, well permitting delays and new data from recently completed wells. 
+The following table summarizes the changes in our estimated proved undeveloped reserves during 2020 (in Bcfe): 
+Proved Undeveloped Reserves, December 31, 2019 2,544 
+Sales of oil and natural gas reserves in place (74) 
+Extensions and discoveries 238 
+Conversion to proved developed reserves (368) 
+Revisions of prior reserve estimates (1,279) 
+Proved Undeveloped Reserves, December 31, 2020 1,061 
+Sales of oil and natural gas reserves in place. During 2020, we sold approximately 74.2 Bcfe of proved undeveloped oil and natural gas reserves associated with various operated interests, the majority of which were in our Utica field. 
+Extensions and discoveries. Our extensions of approximately 238.4 Bcfe were primarily attributed to the addition of 14 PUD drilling locations in the Utica field and eight PUD drilling locations in the SCOOP field as a result of our current development plan that refocused some activity within our existing fields. The commodity prices utilized for the 2020 reserves determination and our revised five-year development plan focused on generating sustainable cash flow limited our ability to add well locations. 
+Conversion to proved developed reserves. Our 2020 development activities resulted in the conversion of approximately 367.7 Bcfe into proved developed producing reserves, attributable to 25 PUD locations in the Utica field and 10 PUD locations in the SCOOP field. These 35 PUDs represent a conversion rate of 14% for 2020. 
+Revision of prior reserve estimates. We experienced proved undeveloped downward revisions of 720.3 Bcfe from the exclusion of 48 PUD locations in our Utica field and 31 PUD locations in our SCOOP field due to the SEC five-year development rule. The development plan change, as approved by our senior management and Board of Directors, reflects our commitment to capital discipline, funding future activities within cash flow and ongoing optimization of our development plan. 
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+Index to Financial Statement s 
+We also experienced 842.9 Bcfe of downward revisions as a result of commodity price changes. These downward revisions were partially offset by positive revisions of 283.7 Bcfe in estimated proved reserves from a combination of operating and development cost improvements, well performance and working interest changes. 
+Costs incurred relating to the development of PUDs were approximately $182.3 million in 2020. 
+All PUD drilling locations included in our 2020 reserve report are scheduled to be drilled within five years of initial booking. 
+As of December 31, 2020, less than 1% of our total proved reserves were classified as proved developed non-producing. 
+Reserves Estimation 
+Reserve estimates for the years ended December 31, 2020, 2019 and 2018 were prepared by Netherland, Sewell & Associates, Inc. ("NSAI") for all of our operating areas. 
+NSAI is an independent petroleum engineering firm. A copy of the summary reserve reports is included as Exhibit 99.1 to this Annual Report on Form 10-K. The technical persons responsible for preparing our proved reserve estimates meet the requirements with regards to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Our independent third-party engineers do not own an interest in any of our properties and are not employed by us on a contingent basis. 
+We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with NSAI, our independent reserve engineers, to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves. Our internal technical team members meet with NSAI periodically throughout the year to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to NSAI for our properties such as ownership interest, oil and gas production, well test data, commodity prices, operating and development costs and other considerations, including availability and costs of infrastructure and status of permits. Our Senior Vice President of Reservoir Engineering is primarily responsible for overseeing the preparation of all of our reserve estimates. He is a petroleum engineer with over 20 years of reservoir and operations experience. In addition, our geophysical staff has approximately 85 years combined industry experience and our reservoir staff has approximately 50 years combined experience. 
+Our proved reserve estimates are prepared in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following: 
+• review and verification of historical production, operating, marketing and capital data, which data is based on actual production as reported by us; 
+• verification of property ownership by our land department; 
+• preparation of reserve estimates by NSAI in coordination with our experienced reservoir engineers; 
+• direct reporting responsibilities by our reservoir engineering department to our Chief Operating Officer; 
+• review by our reservoir engineering department of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes and all new proved undeveloped reserves additions; 
+• provision of quarterly updates to our board of directors regarding operational data, including production, drilling and completion activity levels and any significant changes in our reserves; 
+• annual review by our board of directors of our year-end reserve report and year-over-year changes in our proved reserves, as well as any changes to our previously adopted development plans; 
+• annual review and approval by our senior management and our board of directors of a multi-year development plan; 
+• annual review by our senior management of adjustments to our previously adopted development plan and considerations involved in making such adjustments; and 
+• annual review by our board of directors of changes in our previously approved development plan made by senior management and technical staff during the year, including the substitution, removal or deferral of PUD locations. 
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+Index to Financial Statement s 
+PV-10 Sensitivities 
+As noted above, our December 31, 2020 proved reserves were calculated using prices based on the 12-month unweighted arithmetic average of the first-day-of-the month price for the period January through December 2020 of $39.54 per barrel and $1.99 per MMBtu. Holding production and development costs constant, if SEC pricing were $43.49 per barrel and $2.19 per MMBtu, or a 10% increase, this would have resulted in an increase of 181.7 Bcfe of our total proved reserves and a $350 million increase in PV-10 value at December 31, 2020. Holding production and development costs constant, if SEC pricing were $35.59 per barrel and $1.79 per MMBtu, or a 10% decrease, this would have resulted in a decrease of 839.9 Bcfe of our total proved reserves and a $228 million decrease in PV-10 value at December 31, 2020. For each of these scenarios, the 82 PUDs that were economic at SEC pricing were included. 
+Holding production and development costs constant while assuming SEC pricing closer to the long-term strip pricing of $50.00 per barrel for crude oil and $2.50 per MMBtu for natural gas results in an increase of 1,065 Bcfe of total proved reserves and a $989 million increase in PV-10 value at December 31, 2020. For this scenario, there were an additional 55 PUD locations included that were economic at these prices. 
+Production, Prices and Production Costs 
+The following table presents our production volumes during the periods indicated: 
+Year Ended December 31, 2020 
+Net Production 
+Field Natural Gas (MMcf) Oil and Condensate (MBbl) NGL (MBbl) Natural gas equivalents (MMcfe) MMcfe per Day 
+Utica 291,133 393 1,077 299,955 820 
+SCOOP 53,853 1,392 2,886 79,519 217 
+Other 13 18 1 126 0.3 
+Total 344,999 1,803 3,964 379,600 1,037 
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+The following table presents our production volumes, average prices received and average production costs during the periods indicated: 
+2020 2019 2018 
+($ In thousands) 
+Natural gas sales 
+Natural gas production volumes (MMcf) 344,999 458,178 443,742 
+Natural gas production volumes (MMcf) per day 943 1,255 1,216 
+Total sales $ 671,535 $ 1,135,381 $ 1,318,472 
+Average price without the impact of derivatives ($/Mcf) $ 1.95 $ 2.48 $ 2.97 
+Impact from settled derivatives ($/Mcf) (1) 
+$ 0.33 $ 0.23 $ (0.04) 
+Average price, including settled derivatives ($/Mcf) $ 2.28 $ 2.71 $ 2.93 
+Oil and condensate sales 
+Oil and condensate production volumes (MBbl) 1,803 2,186 2,801 
+Oil and condensate production volumes (MBbl) per day 5 6 8 
+Total sales $ 62,902 $ 117,937 $ 177,793 
+Average price without the impact of derivatives ($/Bbl) $ 34.88 $ 53.95 $ 63.48 
+Impact from settled derivatives ($/Bbl) (2) 
+$ 25.76 $ 1.86 $ (9.51) 
+Average price, including settled derivatives ($/Bbl) $ 60.64 $ 55.81 $ 53.97 
+NGL sales 
+NGL production volumes (MBbl) 3,964 5,074 5,993 
+NGL production volumes (MBbl) per day 11 14 16 
+Total sales $ 66,814 $ 101,448 $ 178,915 
+Average price without the impact of derivatives ($/Bbl) $ 16.86 $ 19.99 $ 29.85 
+Impact from settled derivatives ($/Bbl) $ (0.04) $ 2.79 $ (2.30) 
+Average price, including settled derivatives ($/Bbl) $ 16.82 $ 22.78 $ 27.55 
+Natural gas, oil and condensate and NGL sales 
+Natural gas equivalents (MMcfe) 379,600 501,742 496,505 
+Natural gas equivalents (MMcfe) per day 1,037 1,375 1,360 
+Total sales $ 801,251 $ 1,354,766 $ 1,675,180 
+Average price without the impact of derivatives ($/Mcfe) $ 2.11 $ 2.70 $ 3.37 
+Impact from settled derivatives ($/Mcfe) $ 0.42 $ 0.24 $ (0.12) 
+Average price, including settled derivatives ($/Mcfe) $ 2.53 $ 2.94 $ 3.25 
+Production Costs: 
+Avg. lease operating expenses ($/Mcfe) $ 0.14 $ 0.15 $ 0.16 
+Avg. production taxes ($/Mcfe) $ 0.05 $ 0.06 $ 0.07 
+Avg. midstream gathering, processing & firm transportation costs ($/Mcfe) $ 1.20 $ 1.01 $ 0.98 
+Total LOE, midstream costs and production taxes ($/Mcfe) $ 1.39 $ 1.22 $ 1.21 
+(1) In November 2020, the Company early terminated certain gas sold call options which resulted in a cash payment of $60.2 million. 
+(2) In April 2020, the Company early terminated certain oil fixed price swaps which resulted in a cash receipt of $40.5 million. 
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+The following table provides a summary of our production, average sales prices and average production costs for oil and gas fields containing 15% or more of our total proved reserves as of December 31, 2020: 
+Year Ended December 31, 
+2020 2019 2018 
+Utica 
+Net Production 
+Natural gas (MMcf) 291,133 387,473 379,417 
+Oil (MBbl) 393 247 299 
+NGL (MBbl) 1,077 1,812 2,700 
+Total (MMcfe) 299,955 399,828 397,406 
+Average Price Without the Impact of Derivatives: 
+Natural gas ($/Mcf) $ 1.97 $ 2.28 $ 2.77 
+Oil ($/Bbl) $ 33.41 $ 51.11 $ 60.22 
+NGL ($/Bbl) $ 18.55 $ 19.74 $ 27.99 
+Average Lease Operating Expenses ($/Mcfe) $ 0.13 $ 0.13 $ 0.14 
+Year Ended December 31, 
+2020 2019 2018 
+SCOOP 
+Net Production 
+Natural gas (MMcf) 53,853 70,669 64,258 
+Oil (MBbl) 1,392 1,610 1,710 
+NGL (MBbl) 2,886 3,261 3,292 
+Total (MMcfe) 79,519 99,891 94,268 
+Average Price Without the Impact of Derivatives: 
+Natural gas ($/Mcf) $ 1.83 $ 2.13 $ 2.73 
+Oil ($/Bbl) $ 35.31 $ 53.32 $ 62.36 
+NGL ($/Bbl) $ 16.23 $ 20.13 $ 31.39 
+Average Lease Operating Expenses ($/Mcfe) $ 0.18 $ 0.18 $ 0.18 
+_____________________ 
+Our Equity Investments 
+Grizzly Oil Sands . We, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.5% interest in Grizzly. As of December 31, 2020, Grizzly had approximately 830,000 net acres under lease in the Athabasca, Peace River and Cold Lake oil sands regions of Alberta, Canada. Grizzly's operations have been suspended since 2016. Additionally, Grizzly had no proved reserves as of December 31, 2020. We elected to cease funding capital calls in 2019, and we have no obligation to fund any of the projects Grizzly is pursuing. Failure to fund capital calls may lead to continued dilution of our equity ownership interest in Grizzly. 
+Mammoth Energy . As of December 31, 2020, we owned 9,829,548 shares, or approximately 21.5%, of the outstanding common stock of Mammoth Energy Services Inc. 
+See Note 5 of the notes to our consolidated financial statements included elsewhere in this report for additional information regarding our equity investments. 
+Marketing 
+The principal function of our marketing operations is to provide natural gas, oil and NGL marketing services, including securing and negotiating commodity transactions, gathering, hauling, processing and transportation services, contract 
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+Index to Financial Statement s 
+administration and nomination services for production from Gulfport-operated wells. In addition, we periodically enter into a variety of oil, natural gas and NGL purchase and sale contracts with third parties for various commercial purposes, including risk mitigation and satisfaction of our firm transportation delivery commitments. These marketing activities often enhance the value of our production by aggregating volumes and allowing improved flexibility in relation to deal structure, size and counterparty exposure whether through intermediary markets or direct end markets. 
+Generally, natural gas and NGL production is sold to purchasers under both spot and term transactions. Oil production is sold under both spot and term transactions with the majority of our sales contracts being shorter term in nature. We have entered into long-term gathering, processing and transportation contracts with various parties that reserve capacity for fixed, determinable quantities of production over specified periods of time. Some contracts require us to make payments for any shortfalls in delivering or transporting minimum volumes under these commitments. See Note 17 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of our commitments. 
+Major Customers 
+Our total natural gas, oil and NGL revenues, before the effects of hedging, to major customers (purchasers in excess of 10% of total natural gas, oil and NGL sales) for the years ended December 31, 2020, 2019 and 2018 were as follows: 
+% of Sales 
+Year Ended December 31, 2020 
+ECO-Energy 12 % 
+Year Ended December 31, 2019 
+Morgan Stanley Capital 14 % 
+Year Ended December 31, 2018 
+BP Energy Company 17 % 
+ECO-Energy 10 % 
+Competition 
+The oil and natural gas industry is intensely competitive, and we compete with many other companies that have greater resources than we have. Competition can negatively impact our ability to successfully source quality vendors and service providers and our ability to secure optimal pipeline access and end markets in which to sell our production. Many of our competitors not only explore for and produce oil and natural gas, but also have midstream and further downstream operations and market a variety of hydrocarbon products on a regional, national or worldwide basis. In addition, oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include renewable sources such as wind or solar energy in addition to coal and fuel oils. Changes in the availability or price of oil and natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas. 
+Title to Oil and Natural Gas Properties 
+It is customary in the oil and natural gas industry to make only a preliminary review of title to undeveloped oil and natural gas leases at the time they are acquired and to obtain more extensive title examinations when acquiring producing properties. In future acquisitions, we will conduct title examinations on material portions of such properties in a manner generally consistent with industry practice. Certain of our oil and natural gas properties may be subject to title defects, encumbrances, easements, servitudes or other restrictions, none of which, in management's opinion, will in the aggregate materially restrict our operations. 
+Regulation - Environment, Health and Safety 
+Exploration and Production, Environmental, Health and Safety, and Occupational Laws and Regulations 
+Our operations are subject to federal, tribal, state, and local laws and regulations. These laws and regulations relate to matters that include, but are not limited to, the following: 
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+Index to Financial Statement s 
+• reporting of workplace injuries and illnesses; 
+• industrial hygiene monitoring; 
+• worker protection and workplace safety; 
+• approval or permits to drill and to conduct operations; 
+• provision of financial assurances (such as bonds) covering drilling and well operations; 
+• calculation and disbursement of royalty payments and production taxes; 
+• seismic operations and data; 
+• location, drilling, cementing and casing of wells; 
+• well design and construction of pad and equipment; 
+• construction and operations activities in sensitive areas, such as wetlands, coastal regions or areas that contain endangered or threatened species, their habitats, or sites of cultural significance; 
+• method of completing wells; 
+• hydraulic fracturing; 
+• water withdrawal; 
+• well production and operations, including processing and gathering systems; 
+• emergency response, contingency plans and spill prevention plans; 
+• air emissions and fluid discharges; 
+• climate change; 
+• use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations; 
+• surface usage, maintenance, monitoring and the restoration of properties associated with well pads, pipelines, impoundments and access roads; 
+• plugging and abandoning of wells; and 
+• transportation of production. 
+Shortly after taking office in January 2021, President Biden issued a series of executive orders designed to address climate change and requiring agencies to review environmental actions taken by the Trump administration, as well as a memorandum to departments and agencies to refrain from proposing or issuing rules until a departmental or agency head appointed or designated by the Biden administration has reviewed and approved the rule. These executive orders may result in the development of additional regulations or changes to existing regulations. Failure to comply with these laws and regulations can lead to the imposition of remedial liabilities, fines, or criminal penalties or to injunctions limiting our operations in affected areas. Moreover, multiple environmental laws provide for citizen suits which allow environmental organizations to act in the place of the government and sue operators for alleged violations of environmental law. We consider the costs of environmental protection and of safety and health compliance to be necessary, manageable parts of our business. We have been able to plan for and comply with environmental, safety and health laws and regulations without materially altering our operating strategy or incurring significant unreimbursed expenditures. However, based on regulatory trends and increasingly stringent laws, our capital expenditures and operating expenses related to compliance with the protection of the environment, safety and health have increased over the years and may continue to increase. We cannot predict with any reasonable degree of certainty our future exposure concerning such matters. See the Risk Factors described in Item 1A. of this report for further discussion of governmental regulation and ongoing regulatory changes, including with respect to environmental matters. 
+Our operations are also subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in a unit, the rate of production allowable from oil and gas wells, and the unitization or pooling of oil and gas properties. In the United States, some states allow the forced pooling or integration of tracts to facilitate exploration. Other states rely on voluntary pooling of lands and leases which may make it more difficult to develop oil and gas properties. In addition, federal and state conservation laws generally limit the venting or flaring of natural gas, and state conservation laws impose certain requirements regarding the ratable purchase of production. These regulations often impose additional operational costs to us and can also limit the amounts of oil and gas we can produce from our wells and the number of wells or the locations at which we can drill. 
+Regulatory proposals in some states and local communities have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. Federal and state agencies have continued to assess the potential impacts of hydraulic fracturing, which could spur further action toward federal, state and/or local legislation 
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+Index to Financial Statement s 
+and regulation. Further restrictions of hydraulic fracturing could reduce the amount of natural gas, oil and NGL that we are ultimately able to produce in commercial quantities from our properties. 
+Certain of our U.S. natural gas and oil leases are granted or approved by the federal government and administered by the Bureau of Land Management (BLM) or Bureau of Indian Affairs (BIA) of the Department of the Interior. Such leases require compliance with detailed federal regulations and orders that regulate, among other matters, drilling and operations on lands covered by these leases and calculation and disbursement of royalty payments to the federal government, tribes or tribal members. The federal government has been particularly active in recent years in evaluating and, in some cases, promulgating new rules and regulations regarding competitive lease bidding, venting and flaring, oil and gas measurement and royalty payment obligations for production from federal lands. In addition, on January 20, 2021, the Acting Secretary for the Department of the Interior signed an order effectively suspending new fossil fuel leasing and permitting on federal lands for 60 days. Then on January 27, 2021, President Biden issued an executive order indefinitely suspending new oil and natural gas leases on public lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices. To the extent that the review results in the development of additional restrictions on drilling, limitations on the availability of leases, or restrictions on the ability to obtain required permits, it could have a material adverse impact on our operations. 
+Permitting activities on federal lands are also subject to frequent delays. 
+Delays in obtaining permits or an inability to obtain new permits or permit renewals could inhibit our ability to execute our drilling and production plans. Failure to comply with applicable regulations or permit requirements could result in revocation of our permits, inability to obtain new permits and the imposition of fines and penalties. 
+Operating Hazards and Insurance 
+The oil and natural gas business involves a variety of operating risks, including the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, natural gas leaks, ruptures or discharges of toxic gases. If any of these should occur, we could incur legal defense costs and could suffer substantial losses due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations. Our horizontal and deep drilling activities involve greater risk of mechanical problems than vertical and shallow drilling operations. 
+We maintain a control of well insurance policy with a $25 million single well limit and a $35 million multiple wells limit that insures against certain sudden and accidental risks associated with drilling, completing and operating our wells. This insurance may not be adequate to cover all losses or exposure to liability. We also carry a $51 million comprehensive general liability umbrella insurance policy. In addition, we maintain a $10 million pollution liability insurance policy providing coverage for gradual pollution related risks and in excess of the general liability policy for sudden and accidental pollution risks. We provide workers' compensation insurance coverage to employees in all states in which we operate. While we believe these policies are customary in the industry, they do not provide complete coverage against all operating risks, and policy limits scale to our working interest percentage in certain situations. In addition, our insurance does not cover penalties or fines that may be assessed by a governmental authority. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows. Our insurance coverage may not be sufficient to cover every claim made against us or may not be commercially available for purchase in the future. 
+We have prepared and have in place spill prevention control and countermeasure plans for each of our principal facilities in response to federal and state requirements. The plans are reviewed annually and updated as necessary. As required by applicable regulations, our facilities are built with secondary containment systems to capture potential releases. We also own additional spill kits with oil booms and absorbent pads that are readily available, if needed. In addition, we have emergency response companies on retainer. These companies specialize in the clean-up of hydrocarbons as a result of spills, blow-outs and natural disasters, and are on call to us 24 hours a day, seven days a week when their services are needed. We pay these companies a retainer plus additional amounts when they provide us with clean up services. Our aggregate payments for the retainer and clean-up services during each of 2020 and 2019 were immaterial. While these companies have been able to meet our service needs when required from time to time in the past, it is possible that the ability of one or more of them to provide services to us in the future, if and when needed, could be hindered or delayed in the event of a widespread disaster. However, in light of the areas in which we operate and the nature of our production, we believe other companies would be available to us in the event our primary remediation companies are unable to perform. We pay these companies a retainer plus additional amounts when they provide us with clean up services. 
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+Index to Financial Statement s 
+Human Capital Management 
+As of December 31, 2020, we had 256 employees, all of which are non-bargaining. The commodity downturn in late 2019 and the broader economic downturn in 2020 led to significant headcount reductions in late 2019 and 2020. Retaining, replacing and developing talent is very important as our business becomes leaner and we navigate the bankruptcy process. We recognize that even though we are a natural resource company, our most valuable assets are our people. We are passionate about devoting the time, energy and resources required to attract, motivate, retain and develop our employees. 
+We understand that a workplace environment that embraces diversity and is inclusive of different ideas and perspectives is a healthy environment and one that provides the best solutions to complex challenges. While being an affirmative action employer assists us in locating qualified diversity candidates when filling positions and provides us with a metrics to reflect on how diverse we are, we have recently increased our focus on diversity across the organization including our board of directors. During 2020, our Board of Directors performed an exhaustive search as part of our board refreshment process, adding two highly qualified diversity candidates that add to the background and experience represented on our Board. Gulfport Energy Corporation’s diverse independent directors currently constitute 37.5% of the Board. The Board also reviewed and refreshed its Corporate Governance Guidelines and Diversity Principles to promote a more diverse and inclusive board and company. While 2020 was a year in which we added very few new employees, 33% of our newly hired employees were diverse hires. We also initiated a program to ensure that every employee across the company engages in peer-led, small group discussion on diversity topics. The results of these conversations will help shape initiatives in 2021, and it will also mature our diversity and inclusion practices. 
+We have numerous programs to ensure that our employees and external partners are adequately trained to perform the critical work we do safely and effectively. The programs also focus on respecting the environments where we operate. We utilize in-person training sessions developed by safety experts and supplement these sessions with computer-based modules to support a safety-first mindset in everything we do. We also provide training resources to employees through universities, electronic content services and specialized courses related to our industry through our tuition reimbursement program or third-party providers. 
+Safety is at the forefront of everything we do. We hold regular safety briefings prior to any significant project and routinely have safety stand-down meetings to highlight potential risks. Every employee is empowered to use their stop-work authority to cease operating if work is being performed in an unsafe manner. We monitor employee safety by establishing annual company-wide key safety metrics tied to leading indicators (i.e., incident reporting and investigations, hazard observations, safety and health meetings) and lagging indicators (i.e., injury rates, preventable motor vehicle accidents). We establish and carefully track key environmental and safety metrics that are a component of every employee’s incentive compensation opportunity for 2020. 
+Executive Officers 
+David M. Wood, Chief Executive Officer and President 
+David M. Wood , 64, has served as the Chief Executive Officer and President of the Company, and as a member of our board of directors, since December 2018. Prior to joining the Company, Mr. Wood served as the Chief Executive Officer and Chairman of the Board of Directors of Arsenal Resources LLC ("Arsenal"), a West Virginia-focused natural gas producer and portfolio company of First Reserve Corporation ("First Reserve"), an energy-focused private equity firm, where he most recently served as Chairman of its board of directors and previously held the role of the Chief Executive Officer. Prior to his tenure at Arsenal, Mr. Wood served as a Senior Advisor to First Reserve from 2013 to 2016, serving on several of its portfolio company boards. Prior to his position at First Reserve, Mr. Wood spent more than 17 years at Murphy Oil Corporation (NYSE: MUR) ("Murphy Oil"), a global oil and natural gas exploration and production company, where he served as Chief Executive Officer, President and a member of the board of directors from 2009 to 2012. From 1980 to 1994, Mr. Wood held various senior positions with Ashland Exploration and Production, an oil and natural gas exploration and production company. Mr. Wood began his career as a well-site geologist in Saudi Arabia. Mr. Wood also served on the Board of Directors of the general partner of Crestwood Equity Partners LP (NYSE: CEQP) and its wholly owned subsidiary, Crestwood Midstream Partners LP, an owner and operator of crude oil and natural gas midstream assets. In addition, Mr. Wood served as the Chairman of the Board of Directors for Lilis Energy, Inc. (NYSE: LLEX), an exploration and development company operating in the Delaware Basin. Mr. Wood also served on the Board of Directors of several private oil and natural gas companies, including Deep Gulf Energy LP (prior to its acquisition by Kosmos Energy Ltd.) and Berkana Energy Corp. (when it was majority owned by Murphy Oil). Mr. Wood previously served on the board of directors and as an executive committee member of the American Petroleum Institute. He was also a member of the National Petroleum Council and is a member of the Society of Exploration Geophysicists. Mr. Wood holds a B.S. in Geology from the University of Nottingham in England and completed Harvard University’s Advanced Management Program. 
+17 
+Table of Contents 
+Index to Financial Statement s 
+Quentin R. Hicks, Executive Vice President and Chief Financial Officer 
+Quentin R. Hicks , 46, has served as the Executive Vice President and Chief Financial Officer of the Company since August 2019. Prior to joining the Company, Mr. Hicks served as the Executive Vice President and Chief Financial Officer of Halcón Resources Corporation (“Halcón”), a position he held since March 2019, having previously served as Executive Vice President, Finance, Capital Markets and Investor Relations of Halcón since January 2018. Prior to that, Mr. Hicks held various roles at Halcón focused primarily on finance and investor relations. Prior to Halcón, Mr. Hicks worked for GeoResources Inc., where he served as Director of Acquisitions and Financial Planning from 2011 to 2012. From 2004 to 2011, he worked in investment banking with Bear Stearns, Sanders Morris Harris and Madison Williams, where most recently worked as a Director in their energy investment banking practice. Prior to that, Mr. Hicks worked as Manager of Financial Reporting for Continental Airlines. Mr. Hicks began his career in 1998 working as an auditor for Ernst and Young LLP. Mr. Hicks graduated from Texas A&M University with a Bachelor of Business Administration and a Master of Science degree in Accounting. In addition, Mr. Hicks holds a Master of Business Administration degree in Finance from Vanderbilt University and also holds a Certified Public Accountant license from the State of Texas. 
+Donnie G. Moore, Executive Vice President and Chief Operating Officer 
+Donnie G. Moore , 56, has served as Executive Vice President, Chief Operating Officer since January 2018. Mr. Moore had also served as Interim Chief Executive Officer of the Company from October 29, 2018, the date our former Chief Executive Officer and President left the Company, to December 18, 2018, the date of the appointment of Mr. Wood as our new Chief Executive Officer and President. From 2007 until December 2017, Mr. Moore worked at Noble Energy, Inc. (“Noble”), an independent oil and gas exploration and production company, where he most recently served as Vice President of Noble’s Texas operations for its Eagle Ford and Delaware Basin assets. Prior to that, Mr. Moore held various leadership roles at Noble including Vice President of the Marcellus Business Unit, Manager for Operations of the Wattenberg/DJ Business Unit, Manager of Operations for the Gunflint discovery in the Deepwater Gulf of Mexico and Development Manager for Noble’s Mid-Continent and Gulf Coast positions. From 1989 until 2007, Mr. Moore served in a variety of roles with ARCO Oil and Gas Company, Vastar Resources, Inc. and BP America. Mr. Moore holds a Bachelor of Science degree in Petroleum Engineering from Louisiana Tech University. 
+Patrick K. Craine, Executive Vice President, General Counsel and Corporate Secretary 
+Patrick K. Craine , 48, has served as Executive Vice President, General Counsel and Corporate Secretary of the Company since May 2019. Mr. Craine has over 20 years of extensive senior-level experience handling a broad range of securities, corporate, regulatory, governance, compliance and litigation matters, with particular expertise in the energy industry. He joined Gulfport from Chesapeake Energy Corporation (NYSE: CHK) (“Chesapeake”), a hydrocarbon exploration company, where he served as Deputy General Counsel – Chief Risk and Compliance Officer from 2013 until 2019. Prior to joining Chesapeake, Mr. Craine was a partner with Bracewell LLP, a global law firm, where his practice focused on securities and corporate regulatory matters and investigations. Before Mr. Craine entered private practice, he served as a lawyer with the SEC and the Financial Industry Regulatory Authority, where he held leadership positions in their Oil and Gas Task Forces. Mr. Craine received his Bachelor of Arts degree, summa cum laude, Phi Beta Kappa, from Wabash College, and his Juris Doctorate, cum laude, from the Southern Methodist University Dedman School of Law. 
+Michael J. Sluiter, Senior Vice President of Reservoir Engineering 
+Michael J. Sluiter , 48, has served as Senior Vice President of Reservoir Engineering of the Company since December 2018. Mr. Sluiter joined the Company from Noble Energy, Inc., where he held various engineering positions from 2007 to 2018, including, most recently, as the Permian Basin Business Unit Manager. Mr. Sluiter has over 20 years of experience in unconventional resource development, reservoir engineering, subsurface development, business development and acquisitions, as well as leadership skills, which he developed at Noble Energy, Santos Australia and Santos USA. Mr. Sluiter began his career as a wireline field services engineer for Schlumberger in Thailand. Mr. Sluiter holds a Bachelor of Science degree in Chemical Engineering from the University of Sydney, Australia. 
+18 
+Table of Contents 
+Index to Financial Statement s

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+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+The information called for by this Item 13 is incorporated herein by reference to the 2021 Proxy Statement.

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+ITEM 9A. CONTROLS AND PROCEDURES 
+Evaluation of Disclosure Control and Procedures 
+Under the direction of our Chief Executive Officer and President and our Chief Financial Officer, we have established disclosure controls and procedures that are designed to ensure that information required to be disclosed by us 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's rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and President and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures. 
+As of December 31, 2020, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and President and our Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and President and our Chief Financial Officer have concluded that, as of December 31, 2020, our disclosure controls and procedures are effective. 
+Remediation of Previously Identified Material Weakness 
+As disclosed in our Annual Report on Form 10-K for the year ended December 31, 2019, our management determined that a material weakness existed in our internal control over financial reporting over the review of the evaluation of our unevaluated oil and gas properties . 
+We have taken the necessary steps to enhance the underlying control activities, which now include redesigned processes and controls to timely identify the transfer of leasehold costs associated with acreage expirations, lease transfers, and proved reserve additions in conjunction with our current development plans. 
+Based on the results of management's evaluation, we have concluded that the controls are designed and operating effectively as of December 31, 2020 and, therefore, the previously disclosed material weakness has been remediated. 
+Changes in Internal Control over Financial Reporting 
+During the quarter ended December 31, 2020, we added certain key controls related to our ongoing reorganization. 
+Except as described above, there were no changes in our internal control over financial reporting during the quarter ended December 31, 2020, which materially affected, or were reasonably likely to materially affect, our internal control over financial reporting. 
+Management's Report on Internal Control Over Financial Reporting 
+Management is responsible for the fair presentation of the consolidated financial statements of Gulfport Energy Corporation. Management is also responsible for establishing and maintaining a system of adequate internal controls over financial reporting as defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. These internal controls are designed to provide reasonable assurance that the reported financial information is presented fairly, that disclosures are adequate and that the judgments inherent in the preparation of financial statements are reasonable. There are inherent limitations in the effectiveness of any system of internal control, including the possibility of human error and overriding of controls. Consequently, an effective internal control system can only provide reasonable, not absolute, assurance with respect to reporting financial information. 
+Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in the 2 013 Internal Control-Integrated Framework, 
+105 
+Table of Contents 
+Index to Financial Statement s 
+management did not identify and material weakness in our internal control over financial reporting and concluded that out internal control over financial reporting was effective as of December 31, 2020. 
+Grant Thornton LLP, the independent registered public accounting firm that audited our financial statements for the year ended December 31, 2020 included with this Annual Report on Form 10-K, has also audited our internal control over financial reporting as of December 31, 2020, as stated in their accompanying report. 
+/s/ David M. Wood /s/ Quentin Hicks 
+Name: David M. Wood Name: Quentin Hicks 
+Title: Chief Executive Officer and President, Director Title: Chief Financial Officer 
+106 
+Table of Contents 
+Index to Financial Statement s 
+Report of Independent Registered Public Accounting Firm 
+Board of Directors and Stockholders 
+Gulfport Energy Corporation 
+Opinion on internal control over financial reporting 
+We have audited the internal control over financial reporting of Gulfport Energy Corporation (a Delaware corporation) and subsidiaries (Debtor-in-Possession) (the “Company”) as of December 31, 2020, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31, 2020, and our report dated March 5, 2021 expressed an unqualified opinion on those financial statements. 
+Basis for opinion 
+The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+Definition and limitations of internal control over financial reporting 
+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. 
+/s/ GRANT THORNTON LLP 
+Oklahoma City, Oklahoma 
+March 5, 2021 
+107 
+Table of Contents 
+Index to Financial Statement s

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+16. RELATED PARTY TRANSACTIONS 
+In the ordinary course of business, the Company has conducted business activities with certain related parties. 
+As of December 31, 2020, the Company held approximately 21.5 % of Mammoth Energy's outstanding common stock as discussed above in Note 5 . Approximately $ 0.6 million, and $ 2.0 million of services provided by Mammoth Energy were included in lease operating expenses in the consolidated statements of operations for the years ended December 31, 2019 and 2018, respectively, with no material amounts for the year ended December 31, 2020. Approximately $ 3.1 million and $ 109.9 million of services provided by Mammoth Energy were capitalized to oil and natural gas properties before elimination of intercompany profits on the accompanying consolidated balance sheets during the years ended December 31, 2020 and 2019, respectively. At December 31, 2019, the Company owed Mammoth Energy approximately $ 8.4 million related to these services. Amounts owed to Mammoth Energy as of December 31, 2020 were immaterial. 
+See Note 18 for additional information on litigation proceedings with Mammoth Energy entities.

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+0000874499,GPOR,GULFPORT ENERGY CORP,10-K,2022-03-01,2021-12-31,2022-03-01T19:45:28.000Z,0001628280-22-004445,gpor-20211231.htm,10-K,18657052,1,1,https://www.sec.gov/Archives/edgar/data/874499/000162828022004445/gpor-20211231.htm,https://www.sec.gov/Archives/edgar/data/874499/000162828022004445/,2021,2021,1

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+ITEM 1. BUSINESS 
+Our Business 
+Gulfport is an independent natural gas-weighted exploration and production company with assets primarily located in the Appalachia and Anadarko basins. Our principal properties are located in Eastern Ohio, where we target development in what is commonly referred to as the Utica formation, and Central Oklahoma where we target development in the SCOOP Woodford and Springer formations. Gulfport's predecessor was incorporated in the State of Delaware in July 1997. Our corporate headquarters are located in Oklahoma City, Oklahoma and shares of Gulfport's common stock trade on the New York Stock Exchange (NYSE) under the ticker symbol "GPOR". Our corporate strategy is focused on the economic development of our asset base in an effort to generate sustainable free cash flow. 
+As of December 31, 2021, we had 3.9 Tcfe of proved reserves with a Standardized Measure of $4.1 billion and a PV-10 of $4.3 billion. See " Definitions " above for our definition of PV-10 (a non-GAAP financial measure) and " Oil, Natural Gas and NGL Reserves " below for a reconciliation of our standardized measure of discounted future net cash flows (the most directly comparable GAAP measure) to PV-10. 
+Information About Us 
+Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on the Investor Relations page of our website at www.gulfportenergy.com as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. From time to time, we also post announcements, updates, events, investor information and presentations on our website in addition to copies of our recent news releases. Information contained on our website, or on other websites that may be linked to our website, is not incorporated by reference into this annual report on Form 10-K and should not be considered part of this report or any other filing that we make with the SEC. 
+Emergence From Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code 
+On November 13, 2020, we and certain of our subsidiaries filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court for the Southern District of Texas. The Chapter 11 Cases were administered jointly under the caption In re Gulfport Energy Corporation, et al., Case No. 20-35562 (DRJ). The Bankruptcy Court confirmed the Plan and entered the confirmation order on April 28, 2021, and the Debtors emerged from the Chapter 11 Cases on the Emergence Date. On May 18, 2021, we began trading on the NYSE under the symbol "GPOR". 
+Although we are no longer a debtor-in-possession, we operated as debtors-in-possession through the pendency of the Chapter 11 Cases. See Note 2 and Note 3 of our consolidated financial statements for a complete discussion of the Chapter 11 Cases. 
+We believe we have emerged from the Chapter 11 Cases as a fundamentally stronger company, built to generate sustainable free cash flow, with a strengthened balance sheet. As a result of the Chapter 11 Cases, we reduced our total indebtedness by $1.4 billion by issuing equity in a reorganized entity to the holders of our unsecured notes and allowed general unsecured claimants. In addition, Gulfport reassessed its organizational needs post emergence and significantly reduced its general and administrative expense to ensure its cost structure is competitive with industry peers. We continue to focus on optimizing development of our resource plays, reducing our operating costs, per well drilling costs, general and administrative costs, and managing our liquidity. We believe our plan to generate free cash flow on an annual basis will allow us to further strengthen our balance sheet and return capital to shareholders. 
+Business Strategy 
+Gulfport aims to create sustainable value through the economic development of our significant resource plays in the Utica and SCOOP operating areas. Our strategy is to develop our assets in an environmentally responsible manner, while generating sustainable cash flow, improving margins and operating efficiencies and returning capital to shareholders. To accomplish these goals, we allocate capital expenditures to projects we believe offer the highest rate of return and we deploy leading drilling and completion techniques and technologies in our development efforts. 
+4 
+Table of Contents 
+Index to Financial Statements 
+2022 Outlook 
+Our 2022 capital expenditure program is expected to be in a range of $340 million to $380 million. We plan to operate on average approximately one operated rig in each of our Utica and SCOOP development areas. In the Utica, we intend to spud 15 gross (13.4 net) operated horizontal wells, complete drilling on 24 gross (21.7 net) operated horizontal wells and commence sales on 17 gross (15.6 net) horizontal wells. In the SCOOP, we intend to spud five gross (3.6 net) operated horizontal wells, complete drilling on 8 gross (5.5 net) operated horizontal wells and commence sales on 13 gross (10.3 net) operated horizontal wells. We expect to fund these expenditures with our operating cash flow and borrowings under our revolving credit agreement. 
+We expect this drilling program to result in approximately 975 to 1,025 MMcfe per day of production in 2022. 
+Additionally, in 2022, we expect to focus on our strategy of returning capital to our shareholders. In the fourth quarter of 2021, our board of directors authorized the repurchase of up to $100 million of our outstanding common stock and we paid our first cash dividend payment on our New Preferred Stock. 
+Operating Areas 
+Utica - The Utica covers hydrocarbon bearing rock formations located in the Appalachian Basin of the United States and Canada. We have approximately 187,000 net reservoir acres located primarily in Belmont, Harrison, Jefferson and Monroe Counties in Eastern Ohio where the Utica ranges in thickness from 600 to over 750 feet. During the Combined Period, we produced approximately 772 MMcfe per day net to our interests in this area and it accounts for approximately 77% of our total production. 
+SCOOP - The SCOOP is a defined area that encompasses many of the top hydrocarbon producing counties in Oklahoma within the Anadarko basin. The SCOOP play mainly targets the Devonian to Mississippian aged Woodford, Sycamore and Springer formations. We have approximately 74,000 net reservoir acres (comprised of approximately 41,000 in the Woodford formation and approximately 33,000 in the Springer formation) located primarily in Garvin, Grady and Stephens Counties. The Woodford Shale across our position ranges in thickness from 200 to over 400 feet and directly overlies the Hunton Limestone and underlies the Sycamore formation, both of which are also locally productive reservoirs. The Sycamore formation consists of hydrocarbon-bearing interbedded shales and siliceous limestones ranging in thickness from 150 to over 450 feet and is overlain by the Caney Shale. The Springer formation across our position is comprised of a series of lenticular sand and shale units. The primary targets are a series of porous, low clay and organic-rich packages within the Goddard Shale member ranging in thickness from 50 to over 250 feet. During the Combined Period, we produced approximately 231 MMcfe per day net to our interests in this area and it accounts for approximately 23% of our total production. 
+Oil, Natural Gas and NGL Reserves 
+Reserve engineering is a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the reserve estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. See Item 1A. “ Risk Factors ” contained elsewhere in this Form 10-K. 
+5 
+Table of Contents 
+Index to Financial Statements 
+The tables below set forth information as of December 31, 2021, with respect to our estimated proved reserves, the associated estimated future net revenue, the PV-10 and the standardized measure. None of the estimated future net revenue, PV-10 nor the standardized measure are intended to represent the current market value of the estimated oil, natural gas and NGL reserves we own. All of our estimated reserves are located within the United States. 
+December 31, 2021 
+Oil 
+(MMBbl) Natural 
+Gas 
+(Bcf) NGL (MMBbl) Total (Bcfe) 
+Utica 
+Proved developed 2 1,482 9 1,550 
+Proved undeveloped 4 1,073 4 1,123 
+Total proved 7 2,555 13 2,673 
+SCOOP 
+Proved developed 6 445 22 613 
+Proved undeveloped 4 477 18 610 
+Total proved 10 921 40 1,223 
+Total 
+Proved developed (1) 
+8 1,928 31 2,165 
+Proved undeveloped 8 1,550 22 1,733 
+Total proved 16 3,478 54 3,898 
+Totals may not sum or recalculate due to rounding. 
+(1) Includes approximately 2 Bcfe of net reserves located in non-core operating districts. 
+Successor 
+Proved Developed Proved Undeveloped Total Proved 
+($ in millions) 
+Estimated future net revenue (1) 
+$ 4,649 $ 3,585 $ 8,234 
+Present value of estimated future net revenue (PV-10) (1) 
+$ 2,655 $ 1,660 $ 4,316 
+Standardized measure (1) 
+$ 4,138 
+Totals may not sum due to rounding. 
+(1) Estimated future net revenue represents the estimated future revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs under existing economic conditions as of December 31, 2021, and assuming commodity prices as set forth below. For the purpose of determining prices used in our reserve reports, we used the unweighted arithmetic average of the prices on the first day of each month within the 12-month period ended December 31, 2021. The prices used in our PV-10 measure were $66.55 per barrel and $3.60 per MMBtu, before basis differential adjustments. These prices should not be interpreted as a prediction of future prices, nor do they reflect the value of our commodity derivative instruments in place as of December 31, 2021. 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. The present value of estimated future net revenue typically differs from the standardized measure because the former does not include the effects of estimated future income tax expense of $178 million as of December 31, 2021. 
+Management uses PV-10, which is calculated without deducting estimated future income tax expenses, as a measure of the value of the Company's current proved reserves and to compare relative values among peer companies. We also understand that securities analysts and rating agencies use this measure in similar ways. While estimated future net revenue and the present value thereof are based on prices, costs and discount factors which may be consistent from company to company, the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each individual company. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows or any other measure of a company's financial or operating performance presented in accordance with GAAP. 
+A reconciliation of the standardized measure of discounted future net cash flows to PV-10 is presented above. Neither PV-10 nor the standardized measure of discounted future net cash flows purport to represent the fair value of our proved oil and gas reserves. 
+6 
+Table of Contents 
+Index to Financial Statements 
+Proved Reserves 
+Estimates of proved reserves and related information are presented in accordance with the requirements of the SEC's rules for the Modernization of Oil and Gas Reporting. These rules permit the use of reliable technologies to estimate and categorize reserves and require the use of the unweighted average of the first-of-the-month commodity prices, adjusted for location and quality differentials, for the prior 12 months (unless contractual arrangements designate the price) to calculate economic producibility of reserves and the discounted cash flows reported as the Standardized Measure of Future Net Cash Flows Relating to Proved Reserves. Refer to Note 20 of our consolidated financial statements for more information pertaining to our proved reserves and the preparation of such estimates. 
+The following table summarizes the changes in our estimated proved reserves during 2021 (in Bcfe): 
+Proved Reserves, December 31, 2020 (Predecessor) 2,588 
+Sales of oil and natural gas reserves in place — 
+Extensions and discoveries 695 
+Revisions of prior reserve estimates 982 
+Current production (366) 
+Proved Reserves, December 31, 2021 (Successor) 3,898 
+Total may not sum due to rounding. 
+Sales of oil and natural gas reserves in place. These are reductions to proved reserves resulting from the divestiture of minerals in place during a period. During 2021, we sold approximately 0.2 Bcfe of proved oil and natural gas reserves through various sales of our non-operated interests in our other non-core assets. 
+Extensions and discoveries. These are additions to our proved reserves that result from extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery. Extensions of approximately 694.6 Bcfe of proved reserves were primarily attributable to the continued development of our Utica and SCOOP acreage. We added 29 PUD locations in our Utica acreage for 352.2 Bcfe and 34 PUD locations in our SCOOP acreage for 342.2 Bcfe. The five-year development plan focused on generating sustainable cash flow limited our ability to add significant well locations. 
+Revisions of prior reserve estimates. Revisions represent changes in previous reserve estimates, either upward or downward, resulting from development plan changes, new information normally obtained from development drilling and production history or a change in economic factors, such as commodity prices, operating costs or development costs. 
+We experienced total upward revisions of 982.2 Bcfe in estimated proved reserves, of which 889.2 Bcfe was the result of commodity price changes. Commodity prices experienced volatility throughout 2021 and the 12-month average price for natural gas increased from $1.99 per MMBtu for 2020 to $3.60 per MMBtu for 2021, the 12-month average price for NGL increased from $15.40 per barrel for 2020 to $31.90 per barrel for 2021, and the 12-month average price for crude oil increased from $39.54 per barrel for 2020 to $66.55 per barrel for 2021. 
+Upward revisions of 157.6 Bcfe were a result of a combination of well performance, operating and development cost improvements and working interest changes. A small downward revision of 64.6 Bcfe was also experienced as a result of the exclusion of 4 PUD locations in our Utica field when changes in our schedule moved development of these PUD locations beyond five years of initial booking. The development plan change reflects our commitment to capital discipline and funding future activities within cash flow and ongoing optimization of our development plan. 
+Additional information regarding estimates of proved reserves, proved developed reserves and proved undeveloped reserves at December 31, 2021, 2020 and 2019 and changes in proved reserves during the last three years are contained in the Supplemental Information on Oil and Gas Exploration and Production Activities, or Supplemental Information , in Note 20 of our consolidated financial statements. 
+7 
+Table of Contents 
+Index to Financial Statements 
+Proved Undeveloped Reserves (PUDs) 
+As of December 31, 2021, our proved undeveloped reserves totaled 1,550 Bcf of natural gas, 8 MMBbl of oil and 22 MMBbl of NGL, for a total of 1,733 Bcfe. Approximately 65% and 35% of our PUD reserves at year-end 2021 were located in Utica and SCOOP, respectively. PUDs will be converted from undeveloped to developed as the applicable wells commence production or there are no material incremental completion capital expenditures associated with such proved developed reserves. 
+We record PUD reserves only after a development plan has been approved by our senior management and board of directors to complete the associated development drilling within five years from the time of initial booking. The PUD locations identified in our development plan are determined based on an analysis of the information that we have available at that time. After a development plan has been adopted, we may periodically make adjustments to the approved development plan due to events and circumstances that have occurred subsequent to the time the plan was approved. These circumstances may include changes in commodity price outlook and costs, delays in the availability of infrastructure, well permitting delays and new data from recently completed wells. 
+The following table summarizes the changes in our estimated proved undeveloped reserves during 2021 (in Bcfe): 
+Proved Undeveloped Reserves, December 31, 2020 (Predecessor) 1,061 
+Extensions and discoveries 694 
+Conversion to proved developed reserves (362) 
+Revisions of prior reserve estimates 341 
+Proved Undeveloped Reserves, December 31, 2021 (Successor) 1,733 
+Total may not sum due to rounding. 
+Extensions and discoveries. Our extensions of approximately 694.4 Bcfe were primarily attributed to the addition of 29 PUD drilling locations in the Utica field and 34 PUD drilling locations in the SCOOP field as a result of our current five-year development plan that is focused on generating sustainable cash flow. 
+Conversion to proved developed reserves. Our 2021 development activities resulted in the conversion of approximately 362.4 Bcfe into proved developed producing reserves, attributable to 12 PUD locations in the Utica field and 11 PUD locations in the SCOOP field. These 23 PUDs represent a conversion rate of 28% for 2021. 
+Revision of prior reserve estimates. We experienced total upward revisions of 340.8 Bcfe in estimated proved undeveloped reserves, of which 340.8 Bcfe was the result of improved commodity prices. The 12-month average price for natural gas increased from $1.99 per MMBtu for 2020 to $3.60 per MMBtu for 2021, the 12-month average price for NGL increased from $15.40 per barrel for 2020 to $31.90 per barrel for 2021, and the 12-month average price for crude oil increased from $39.54 per barrel for 2020 to $66.55 per barrel for 2021. 
+We also experienced 67.6 Bcfe of downward revisions as a result of the exclusion of 4 PUD locations in our Utica field when changes in our schedule moved development of these PUD locations beyond five years of initial booking. These downward revisions were offset by upward revisions of 67.6 Bcfe in estimated proved reserves from a combination of working interest changes, well development design updates and operating and development cost improvements. 
+Costs incurred relating to the development of PUDs were approximately $268.1 million in 2021. 
+All PUD drilling locations included in our 2021 reserve report are scheduled to be drilled within five years of initial booking. 
+As of December 31, 2021, 0.01% of our total proved reserves were classified as proved developed non-producing. 
+Reserves Estimation 
+Reserve estimates for the years ended December 31, 2021, 2020 and 2019 were prepared by Netherland, Sewell & Associates, Inc. ("NSAI") for all of our operating areas. 
+8 
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+Index to Financial Statements 
+NSAI is an independent petroleum engineering firm. A copy of the summary reserve reports is included as Exhibit 99.1 to this Annual Report on Form 10-K. The technical persons responsible for preparing our proved reserve estimates meet the requirements with regards to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Our independent third-party engineers do not own an interest in any of our properties and are not employed by us on a contingent basis. 
+We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with NSAI to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves. Our internal technical team members meet with NSAI periodically throughout the year to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to NSAI for our properties such as ownership interest, oil and gas production, well test data, commodity prices, operating and development costs and other considerations, including availability and costs of infrastructure and status of permits. Our Senior Vice President of Reservoir Engineering is primarily responsible for overseeing the preparation of all of our reserve estimates. He is a petroleum engineer with over 20 years of reservoir and operations experience. In addition, our geoscience staff has approximately 85 years combined industry experience and our reservoir staff has approximately 75 years combined experience. 
+Internal Controls Over Proved Reserve Estimates 
+Our proved reserve estimates are prepared in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following: 
+• review and verification of historical production, operating, marketing and capital data, which data is based on actual production as reported by us; 
+• verification of property ownership by our land department; 
+• preparation of year-end reserve estimates by NSAI in coordination with our experienced reservoir engineers; 
+• direct reporting responsibilities by our reservoir engineering department to our Chief Executive Officer; 
+• review by our reservoir engineering department of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes and all new proved undeveloped reserves additions; 
+• provision of quarterly updates to our board of directors regarding operational data, including production, drilling and completion activity levels and any significant changes in our reserves; 
+• annual review by our board of directors of our year-end reserve report and year-over-year changes in our proved reserves, as well as any changes to our previously adopted development plans; 
+• annual review and approval by our senior management and our board of directors of a multi-year development plan; 
+• annual review by our senior management of adjustments to our previously adopted development plan and considerations involved in making such adjustments; and 
+• annual review by our board of directors of changes in our previously approved development plan made by senior management and technical staff during the year, including the substitution, removal or deferral of PUD locations. 
+PV-10 Sensitivities 
+As noted above, our December 31, 2021 proved reserves were calculated using prices based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period January through December 2021 of $66.55 per barrel and $3.60 per MMBtu. Holding production and development costs constant, if SEC pricing were $73.21 per barrel and $3.96 per MMBtu, or a 10% increase, this would have resulted in an increase of 16.2 Bcfe of our total proved reserves and a $787 million increase in PV-10 value at December 31, 2021. Holding production and development costs constant, if SEC pricing were $59.90 per barrel and $3.24 per MMBtu, or a 10% decrease, this would have resulted in a decrease of 23.8 Bcfe of our total proved reserves and a $787 million decrease in PV-10 value at December 31, 2021. For each of these scenarios, the 139 PUDs that were economic at SEC pricing were included. 
+9 
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+Index to Financial Statements 
+Acreage 
+The following table presents our total gross and net developed and undeveloped acres as of December 31, 2021: 
+Developed 
+Acreage Undeveloped 
+Acreage 
+Field Gross Net Gross Net 
+Utica 127,590 101,979 91,033 85,330 
+SCOOP 49,104 34,934 7,959 5,673 
+Other 1,021 395 4,377 1,253 
+Total 177,715 137,308 103,369 92,256 
+Of our leases that are not held by production, most have a five-year primary term, many of which include options to extend the primary term. We manage lease expirations to ensure that we do not experience unintended material expirations. Our leasehold management efforts include scheduling our operations to establish production in paying quantities in order to hold leases prior to the expiration dates, paying the prescribed lease extension payments, planning non-core divestitures or strategic acreage trades with other operators to high-grade our lease inventory and letting some leases expire that are no longer part of our development plans. The following table sets forth the potential expiration periods of gross and net undeveloped leasehold acres as of December 31, 2021: 
+Undeveloped Acres 
+Gross Acres Net Acres 
+Years Ending December 31: 
+2022 15,960 14,494 
+2023 13,937 13,045 
+2024 261 253 
+After 2024 2,637 2,565 
+Held by production or operations 70,342 61,667 
+Total (1) 
+103,137 92,024 
+(1) Does not include acreage not subject to expiration. 
+Productive Wells 
+The following table presents our total gross and net productive wells, expressed separately for oil and gas, as of December 31, 2021: 
+Average NRI/WI Productive 
+Oil Wells Productive 
+Gas Wells Total Wells 
+Field Percentages Gross Net Gross Net Gross Net 
+Utica 48.75/59.71 147 42.8 514 352.0 661 394.7 
+SCOOP 23.17/28.80 105 16.7 516 161.8 621 178.6 
+Other Various 20 1.3 8 0.1 28 1.4 
+Total (1) 
+331 60.8 1,141 513.9 1,472 574.7 
+(1) We also have override/royalty interests in 162 wells with an average NRI of 0.5%, which are not material to our operations. Totals may not sum due to rounding. 
+10 
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+Index to Financial Statements 
+Drilling Activity 
+The following table sets forth information with respect to operated wells drilled during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return. 
+Year Ended December 31, 
+2021 2020 2019 
+Gross Net Gross Net Gross Net 
+Development: 
+Productive 29 26.6 26 24.4 25 22.4 
+Dry — — — — — — 
+Total 29 26.6 26 24.4 25 22.4 
+Exploratory: 
+Productive — — — — 1 0.8 
+Dry — — — — — — 
+Total — — — — 1 0.8 
+The following table presents activity by operating area for the year ended December 31, 2021: 
+Operated Non-Operated 
+Field Drilled Turned to Sales Drilled Turned to Sales 
+Gross Net Gross Net Gross Net Gross Net 
+Utica (1) 
+20 18.9 17 17.0 — — — — 
+SCOOP (2) 
+9 7.7 11 9.4 25 1.77 21 0.05 
+Total 29 26.6 28 26.4 25 1.77 21 0.05 
+_____________________ 
+(1) Of the 20 gross wells drilled in 2021, 10 were completed as producing wells, nine were in various stages of drilling and one was waiting on completion as of December 31, 2021. 
+(2) Of the nine gross wells drilled in 2021, four were in various stages of drilling and five were in various stages of completion as of December 31, 2021. 
+11 
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+Index to Financial Statements 
+Production, Prices and Production Costs 
+The following table presents our production volumes, average prices received and average production costs during the periods indicated (sales totals in thousands): 
+Successor Predecessor Non-GAAP Combined Predecessor 
+Period from May 18, 2021 through December 31, 2021 Period from January 1, 2021 through May 17, 2021 Year Ended December 31, 2021 Year Ended December 31, 2020 Year Ended December 31, 2019 
+Natural gas sales 
+Natural gas production volumes (MMcf) 208,641 124,279 332,921 344,999 458,178 
+Natural gas production volumes (MMcf/d) 915 907 912 943 1,255 
+Total sales $ 906,096 $ 344,390 $ 1,250,486 $ 671,535 $ 1,135,381 
+Avg. price without the impact of derivatives ($/Mcf) $ 4.34 $ 2.77 $ 3.76 $ 1.95 $ 2.48 
+Impact from settled derivatives ($/Mcf) (1) 
+$ (1.44) $ (0.03) $ (0.91) $ 0.33 $ 0.23 
+Avg. price, including settled derivatives ($/Mcf) $ 2.90 $ 2.74 $ 2.85 $ 2.28 $ 2.71 
+Oil and condensate sales 
+Oil and condensate production volumes (MBbl) 1,167 531 1,699 1,803 2,186 
+Oil and condensate production volumes (MBbl/d) 5 4 5 5 6 
+Total sales $ 81,347 $ 29,106 $ 110,453 $ 62,902 $ 117,937 
+Avg. price without the impact of derivatives ($/Bbl) $ 69.71 $ 54.81 $ 65.01 $ 34.88 $ 53.95 
+Impact from settled derivatives ($/Bbl) $ (8.33) $ — $ (5.72) $ 25.76 $ 1.86 
+Avg. price, including settled derivatives ($/Bbl) $ 61.38 $ 54.81 $ 59.29 $ 60.64 $ 55.81 
+NGL sales 
+NGL production volumes (MBbl) 2,658 1,211 3,869 3,964 5,074 
+NGL production volumes (MBbl/d) 12 9 11 11 14 
+Total sales $ 105,141 $ 36,780 $ 141,921 $ 66,814 $ 101,448 
+Avg. price without the impact of derivatives ($/Bbl) $ 39.56 $ 30.37 $ 36.68 $ 16.86 $ 19.99 
+Impact from settled derivatives ($/Bbl) (2) 
+$ (4.88) $ — $ (3.35) $ (0.04) $ 2.79 
+Avg. price, including settled derivatives ($/Bbl) $ 34.68 $ 30.37 $ 33.33 $ 16.82 $ 22.78 
+Natural gas, oil and condensate and NGL sales 
+Natural gas equivalents (MMcfe) 231,594 134,735 366,329 379,600 501,742 
+Natural gas equivalents (MMcfe/d) 1,016 983 1,004 1,037 1,375 
+Total sales $ 1,092,584 $ 410,276 $ 1,502,860 $ 801,251 $ 1,354,766 
+Avg. price without the impact of derivatives ($/Mcfe) $ 4.72 $ 3.05 $ 4.10 $ 2.11 $ 2.70 
+Impact from settled derivatives ($/Mcfe) $ (1.39) $ (0.02) $ (0.89) $ 0.42 $ 0.24 
+Avg. price, including settled derivatives ($/Mcfe) $ 3.33 $ 3.03 $ 3.21 $ 2.53 $ 2.94 
+Production Costs: 
+Avg. lease operating expenses ($/Mcfe) $ 0.14 $ 0.14 $ 0.14 $ 0.14 $ 0.15 
+Avg. taxes other than income ($/Mcfe) $ 0.13 $ 0.09 $ 0.12 $ 0.08 $ 0.08 
+Avg. transportation, gathering, processing and compression ($/Mcfe) $ 0.92 $ 1.20 $ 1.02 $ 1.20 $ 1.01 
+Total LOE, midstream costs and taxes ($/Mcfe) $ 1.19 $ 1.43 $ 1.28 $ 1.42 $ 1.24 
+(1) In November 2020, the Company early terminated certain gas sold call options which resulted in a cash payment of $60.2 million. 
+(2) In April 2020, the Company early terminated certain oil fixed price swaps which resulted in a cash receipt of $40.5 million. 
+12 
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+Index to Financial Statements 
+The following table provides a summary of our production, average sales prices and average production costs for oil and gas fields containing 15% or more of our total proved reserves as of December 31, 2021: 
+Successor Predecessor Non-GAAP Combined Predecessor 
+Period from May 18, 2021 through December 31, 2021 Period from January 1, 2021 through May 17, 2021 Year Ended December 31, 2021 Year Ended December 31, 2020 Year Ended December 31, 2019 
+Utica 
+Net production 
+Natural gas (MMcf) 166,906 106,968 273,874 291,133 387,473 
+Oil (MBbl) 220 183 403 393 247 
+NGL (MBbl) 562 361 924 1,077 1,812 
+Total (MMcfe) 171,598 110,235 281,833 299,955 399,828 
+Avg. price without the impact of derivatives: 
+Natural gas ($/Mcf) $ 4.33 $ 2.64 $ 3.67 $ 1.97 $ 2.28 
+Oil ($/Bbl) $ 66.94 $ 52.43 $ 60.35 $ 33.41 $ 51.11 
+NGL ($/Bbl) $ 47.16 $ 37.21 $ 43.27 $ 18.55 $ 19.74 
+Production costs: 
+Avg. lease operating expenses ($/Mcfe) $ 0.13 $ 0.13 $ 0.13 $ 0.13 $ 0.12 
+Avg. taxes other than income ($/Mcfe) $ 0.07 $ 0.06 $ 0.07 $ 0.07 $ 0.07 
+Avg. transportation, gathering, processing and compression ($/Mcfe) $ 0.98 $ 1.26 $ 1.09 $ 1.29 $ 1.07 
+Total LOE, midstream costs and taxes ($/Mcfe) $ 1.18 $ 1.45 $ 1.29 $ 1.49 $ 1.26 
+SCOOP 
+Net production 
+Natural gas (MMcf) 41,724 17,302 59,026 53,853 70,669 
+Oil (MBbl) 933 344 1,276 1,392 1,610 
+NGL (MBbl) 2,095 849 2,945 2,886 3,261 
+Total (MMcfe) 59,893 24,461 84,353 79,519 99,891 
+Avg. price without the impact of derivatives: 
+Natural gas ($/Mcf) $ 4.40 $ 3.59 $ 4.16 $ 1.83 $ 2.13 
+Oil ($/Bbl) $ 70.37 $ 56.05 $ 66.51 $ 35.31 $ 53.32 
+NGL ($/Bbl) $ 37.51 $ 27.46 $ 34.61 $ 16.23 $ 20.13 
+Production costs: 
+Avg. lease operating expenses ($/Mcfe) $ 0.17 $ 0.22 $ 0.19 $ 0.18 $ 0.18 
+Avg. taxes other than income ($/Mcfe) $ 0.29 $ 0.20 $ 0.26 $ 0.10 $ 0.14 
+Avg. transportation, gathering, processing and compression ($/Mcfe) $ 0.74 $ 0.90 $ 0.78 $ 0.86 $ 0.80 
+Total LOE, midstream costs and taxes ($/Mcfe) $ 1.20 $ 1.32 $ 1.23 $ 1.14 $ 1.12 
+Our Investments 
+Grizzly Oil Sands . We, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.5% interest in Grizzly. As of December 31, 2021, Grizzly had approximately 830,000 net acres under lease in the Athabasca, Peace River and Cold Lake oil sands regions of Alberta, Canada. Grizzly's operations have been suspended since 2016. Additionally, Grizzly had no proved reserves as of December 31, 2021. We elected to cease funding capital calls in 2019, and we have no obligation to fund any of the projects Grizzly is pursuing. Failure to fund capital calls may lead to continued dilution of our equity ownership interest in Grizzly. Upon emergence from bankruptcy, we determined that we no longer had the ability to exercise significant influence over operating and financial policies of Grizzly. As such, we discontinued equity method of accounting for our investment in Grizzly. 
+13 
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+Index to Financial Statements 
+Mammoth Energy. As discussed in Note 15 of our consolidated financial statements, the Company's previously owned shares of the outstanding common stock of Mammoth Energy were used to settle Class 4A claims during 2021. The Company no longer owns any common stock of Mammoth Energy. 
+Marketing 
+The principal function of our marketing operations is to provide natural gas, oil and NGL marketing services, including securing and negotiating commodity transactions, gathering, hauling, processing and transportation services, contract administration and nomination services for production from Gulfport-marketed wells. Generally, natural gas and NGL production is sold to purchasers under both spot and term transactions. Oil production is sold under both spot and term transactions with the majority of our sales contracts being shorter term in nature. 
+We have entered into long-term gathering, processing and transportation contracts with various parties that reserve capacity for fixed, determinable quantities of production over specified periods of time. Some contracts require us to make payments for any shortfalls in delivering or transporting minimum volumes under these commitments. In addition, we periodically enter into a variety of oil, natural gas and NGL purchase and sale contracts with third parties for various commercial purposes, including risk mitigation and satisfaction of our firm transportation delivery commitments. These marketing activities often enhance the value of our production by aggregating volumes and allowing improved flexibility in relation to deal structure, size and counterparty exposure whether through intermediary markets or direct end markets. See Note 18 of our consolidated financial statements for further discussion of our commitments. 
+Major Customers 
+Our total natural gas, oil and NGL sales, before the effects of hedging, to major customers (purchasers in excess of 10% of total natural gas, oil and NGL sales) for the Successor Period, Predecessor Period, and years ended December 31, 2020 and 2019 were as follows: 
+% of Sales 
+Period from May 18, 2021 through December 31, 2021 (Successor) 
+ECO-Energy 20 % 
+Macquarie 10 % 
+Period from January 1, 2021 through May 17, 2021 (Predecessor) 
+ECO-Energy 14 % 
+Macquarie 12 % 
+Citadel 11 % 
+Year Ended December 31, 2020 (Predecessor) 
+ECO-Energy 12 % 
+Year Ended December 31, 2019 (Predecessor) 
+Morgan Stanley Capital 14 % 
+Competition 
+The oil and natural gas industry is intensely competitive, and we compete with many other companies that have greater resources than we have. Competition can negatively impact our ability to successfully source quality vendors and service providers, to secure optimal pipeline access and end markets in which to sell our production, to acquire new properties, and our search for, and the development of, reserves. Many of our competitors not only explore for and produce oil and natural gas, but also have midstream and further downstream operations and market a variety of hydrocarbon products on a regional, national or worldwide basis. In addition, oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include renewable sources such as wind or solar energy in addition to coal and fuel oils. Changes in the availability or price of oil and natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas. 
+14 
+Table of Contents 
+Index to Financial Statements 
+Seasonality 
+Gulfport drills and completes wells throughout the year, but adverse weather conditions can impact drilling, completion, and field operations, which can impact overall production volumes. Seasonal anomalies can minimize or exaggerate the impact on these operations, while extreme weather events can materially constrain our operations for short periods of time. 
+Title to Oil and Natural Gas Properties 
+It is customary in the oil and natural gas industry to make only a preliminary review of title to undeveloped oil and natural gas leases at the time they are acquired and to obtain more extensive title examinations when acquiring producing properties. In future acquisitions, we will conduct title examinations on material portions of such properties in a manner generally consistent with industry practice. Certain of our oil and natural gas properties may be subject to certain imperfections in title, encumbrances, easements, servitudes or other restrictions, none of which, in management's opinion, will in the aggregate materially restrict our operations. 
+Regulation - Environment, Health and Safety 
+Exploration and Production, Environmental, Health and Safety, and Occupational Laws and Regulations 
+Our operations are subject to federal, tribal, state, and local laws and regulations. These laws and regulations relate to matters that include, but are not limited to, the following: 
+• reporting of workplace injuries and illnesses; 
+• industrial hygiene monitoring; 
+• worker protection and workplace safety; 
+• approval or permits to drill and to conduct operations; 
+• provision of financial assurances (such as bonds) covering drilling and well operations; 
+• calculation and disbursement of royalty payments and production taxes; 
+• seismic operations and data; 
+• location, drilling, cementing and casing of wells; 
+• well design and construction of pad and equipment; 
+• construction and operations activities in sensitive areas, such as wetlands, coastal regions or areas that contain endangered or threatened species, their habitats, or sites of cultural significance; 
+• method of completing wells; 
+• hydraulic fracturing; 
+• water withdrawal; 
+• well production and operations, including processing and gathering systems; 
+• emergency response, contingency plans and spill prevention plans; 
+• air emissions and fluid discharges; 
+• climate change; 
+• use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations; 
+• surface usage, maintenance, monitoring and the restoration of properties associated with well pads, pipelines, impoundments and access roads; 
+• plugging and abandoning of wells; and 
+• transportation of production. 
+Shortly after taking office in January 2021, President Biden issued a series of executive orders designed to address climate change and requiring agencies to review environmental actions taken by the Trump administration, as well as a memorandum to departments and agencies to refrain from proposing or issuing rules until a departmental or agency head appointed or designated by the Biden administration has reviewed and approved the rule. These executive orders in part led to the US again depositing an instrument of acceptance of the Paris Agreement, created in 2015 during the United Nations (“U.N.”) Climate Change Conference, which thereafter re-entered into force for the US on February 19, 2021. The Paris Agreement requires countries to review and “represent a progression” in their nationally determined contributions, which set emissions reduction goals, every five years beginning in 2020. The terms of the Paris Agreement and the executive orders are expected to result in 
+15 
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+Index to Financial Statements 
+additional regulations or changes to existing regulations, which could have a material adverse effect on our business. In addition, incentives to conserve energy or use alternative energy sources could have a negative impact on our business. The executive orders and international accord may result in the development of additional regulations or changes to existing regulations. Failure to comply with laws and regulations can lead to the imposition of remedial liabilities, fines, or criminal penalties or to injunctions limiting our operations in affected areas. Moreover, multiple environmental laws provide for citizen suits which allow environmental organizations to act in the place of the government and sue operators for alleged violations of environmental law. We consider the costs of environmental protection and of safety and health compliance to be necessary, manageable parts of our business. We have been able to plan for and comply with environmental, safety and health laws and regulations without materially altering our operating strategy or incurring significant unreimbursed expenditures. However, based on policy and regulatory trends and increasingly stringent laws, our capital expenditures and operating expenses related to compliance with the protection of the environment, safety and health have increased over the years and may continue to increase. We cannot predict with any reasonable degree of certainty our future exposure concerning such matters. See the Risk Factors described in Item 1A. of this report for further discussion of governmental regulation and ongoing regulatory changes, including with respect to environmental matters. 
+Our operations are also subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in a unit, the rate of production allowable from oil and gas wells, and the unitization or pooling of oil and gas properties. In the United States, some states allow the compulsory pooling or integration of tracts to facilitate exploration and development. Other states rely on voluntary pooling of lands and leases which may make it more difficult to develop oil and gas properties. In addition, federal and state conservation laws generally limit the venting or flaring of natural gas, and state conservation laws impose certain requirements regarding the ratable purchase of production. These regulations often impose additional operational costs to us and can also limit the amounts of oil and gas we can produce from our wells and the number of wells or the locations at which we can drill. 
+Regulatory proposals in some states and local communities have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. Federal and state agencies have continued to assess the potential impacts of hydraulic fracturing, which could spur further action toward federal, state and/or local legislation and regulation. Further restrictions of hydraulic fracturing could reduce the amount of natural gas, oil and NGL that we are ultimately able to produce in commercial quantities from our properties. 
+Certain of our U.S. natural gas and oil leases are granted or approved by the federal government and administered by the Bureau of Land Management (BLM) or Bureau of Indian Affairs (BIA) of the Department of the Interior. Such leases require compliance with detailed federal regulations and orders that regulate, among other matters, drilling and operations on lands covered by these leases and calculation and disbursement of royalty payments to the federal government, tribes or tribal members. The federal government has been particularly active in recent years in evaluating and, in some cases, promulgating new rules and regulations regarding competitive lease bidding, venting and flaring, oil and gas measurement and royalty payment obligations for production from federal lands. In addition, on January 20, 2021, the Acting Secretary for the Department of the Interior signed an order effectively suspending new fossil fuel leasing and permitting on federal lands for 60 days. Then on January 27, 2021, President Biden issued an executive order indefinitely suspending new oil and natural gas leases on public lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices. To the extent that the review results in the development of additional restrictions on drilling, limitations on the availability of leases, or restrictions on the ability to obtain required permits, it could have a material adverse impact on our operations. 
+Permitting activities on federal lands are also subject to frequent delays. 
+Delays in obtaining permits or an inability to obtain new permits or permit renewals could inhibit our ability to execute our drilling and production plans. Failure to comply with applicable regulations or permit requirements could result in revocation of our permits, inability to obtain new permits and the imposition of fines and penalties. 
+Operating Hazards and Insurance 
+The oil and natural gas business involves a variety of operating risks, including the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, natural gas leaks, ruptures or discharges of toxic gases. If any of these should occur, we could incur legal defense costs and could suffer substantial losses due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations. Our horizontal and deep drilling activities involve greater risk of mechanical problems than vertical and shallow drilling operations. 
+16 
+Table of Contents 
+Index to Financial Statements 
+We maintain a control of well insurance policy with a $25 million single well limit and a $35 million multiple wells limit that insures against certain sudden and accidental risks associated with drilling, completing and operating our wells. This insurance may not be adequate to cover all losses or exposure to liability. We also carry a $51 million comprehensive general liability umbrella insurance policy. In addition, we maintain a $10 million pollution liability insurance policy providing coverage for gradual pollution related risks and in excess of the general liability policy for sudden and accidental pollution risks. We provide workers' compensation insurance coverage to employees in all states in which we operate. While we believe these policies are customary in the industry, they do not provide complete coverage against all operating risks, and policy limits scale to our working interest percentage in certain situations. In addition, our insurance does not cover penalties or fines that may be assessed by a governmental authority. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows. Our insurance coverage may not be sufficient to cover every claim made against us or may not be commercially available for purchase in the future. 
+We have prepared and have in place spill prevention control and countermeasure plans for each of our principal facilities in response to federal and state requirements. The plans go through a technical review every five years and are updated as necessary. As required by applicable regulations, our facilities are built with secondary containment systems to capture potential releases. We also own additional spill kits with oil booms and absorbent pads that are readily available, if needed. In addition, we have emergency response companies on retainer. These companies specialize in the clean-up of hydrocarbons as a result of spills, blow-outs and natural disasters, and are on call to us 24 hours a day, seven days a week when their services are needed. We pay these companies a retainer plus additional amounts when they provide us with clean up services. Our aggregate payments for the retainer and clean-up services during each of 2021 and 2020 were immaterial. While these companies have been able to meet our service needs when required from time to time in the past, it is possible that the ability of one or more of them to provide services to us in the future, if and when needed, could be hindered or delayed in the event of a widespread disaster. However, in light of the areas in which we operate and the nature of our production, we believe other companies would be available to us in the event our primary remediation companies are unable to perform. 
+Human Capital Management 
+Employees 
+As of December 31, 2021, we had 212 employees, a reduction from 256 employees the previous year. The reduction was due to the rightsizing of our organization through a controlled hiring program and a small reduction in workforce in August of 2021. All of our employees are non-bargaining. Attraction and retention of people remains one of the highest strategic goals of the organization. We remain focused on the retention and development of existing employees, as their continued commitment is critical to our success. 
+During 2021, we continued to adapt to the changing nature of the COVID-19 pandemic, by regularly assessing COVID-19 employee protocols, minimizing the numbers of people in our offices at times, conducting daily health screenings for all employees and visitors, and completing thorough contact tracing. These efforts helped protect the safety of employees, minimize the risk of transmission at Gulfport locations and keep our operations online with minimal disruption. 
+Inclusion & Diversity 
+During 2021, we continued to work on the diversity and inclusion projects that we announced in 2020 and held peer-led, small group discussions for all employees aimed at understanding how they view diversity and ways we could continue to focus on it in a meaningful way going forward. Based partly on feedback from those discussions, the Company delivered an unconscious bias training program for all employees to better help them understand themselves and how they view those around them. The results of these efforts have been overwhelmingly positive and have positioned us to further our diversity and inclusion initiatives in 2022 and beyond. 
+During 2021, our Board of Directors completely turned over as a result of the bankruptcy process and is now comprised of 40% of highly qualified diverse candidates as of the end of 2021. While 2021 was a year in which we again added very few new employees, approximately 29% of our newly hired employees were diverse hires. We are committed to evaluating our hiring and promotion practices to make sure that a diversity and inclusion mindset is considered and included throughout the Company. 
+In 2021, many Gulfport policies were added or revised, and a new Business Code of Conduct and Ethics training was provided to all employees. We are committed to maintaining the highest standards of business ethics and the employee training provided a clear review of our expectations. 
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+Health, Safety & Environment (HSE) 
+Safety is at the forefront of everything we do. We have a robust annual training program, which includes environmental, health, and safety topics. Our safety program, WORK SAFE, is comprised of twelve key topics including critical tasks and cultural conditions. We hold regular safety briefings to discuss daily operations and routinely have safety stand-down meetings to highlight potential risks. Every employee is empowered to use their stop-work authority to cease operating if work is being performed in an unsafe manner. We monitor employee safety by establishing annual company-wide key safety metrics tied to leading indicators (i.e., incident reporting and investigations, hazard observations, safety and health meetings) and lagging indicators (i.e., injury rates and preventable motor vehicle accidents). 
+As part of our focus on continuous improvement, we monitor and communicate key environmental and safety metrics both internally and externally. Trend analysis guides us to make operational changes and policy updates as necessary to protect our employees, the public, and the environment. We establish and carefully track key environmental and safety metrics that are a component of every employee’s incentive compensation opportunity for 2021. 
+We have established several programs to ensure that our employees and external partners are appropriately trained to perform the critical work we do safely and effectively. We continued to reinforce our Work Safe Program and provided training to leaders on reinforcement strategies. Additionally, we launched the Work Green program in 2021, which focuses on protecting the air, land and water where we operate and includes community-based volunteer events targeting environmental clean-up and habitat improvement initiatives. 
+Training & Development 
+Gulfport invests in our employees' professional growth to build strong teams and develop leaders for today and the future. We build our dynamic team of industry-leading professionals by engaging them in interesting and rewarding work and by providing training and development opportunities. We utilize in-person training sessions developed by safety experts and supplement these sessions with computer-based modules to support a safety-first mindset in everything we do. We continue to provide training resources to employees through universities, electronic content services and specialized courses related to our industry through our tuition reimbursement program or third-party providers. 
+Executive Officers 
+Timothy J. Cutt, Chief Executive Officer and Chairman of the Board 
+Mr. Cutt, 61, joined Gulfport as the Interim Chief Executive Officer in May 2021, and assumed the role of Chief Executive Officer in September 2021. Mr. Cutt is a Petroleum Engineer with 38 years of energy experience. He served as Chief Executive Officer and as a director of QEP Resources from January 2019 to March 2021. Prior to joining QEP, Mr. Cutt was the Chief Executive Officer and a director of Cobalt International Energy from 2016 to 2018. Previously, Mr. Cutt held several executive positions with BHP Billiton before serving as President of the Petroleum Division from 2013 to 2016. During this time, he was also a member of BHP Billiton’s Corporate Leadership Team. Mr. Cutt began his career with Mobil and worked for ExxonMobil for 24 years and served in various management roles including President of ExxonMobil de Venezuela, President ExxonMobil Canada Energy and President Hibernia Management & Development Company. Mr. Cutt served as a board member of the American Petroleum Institute (API) from 2013 to 2018. 
+William J. Buese, Chief Financial Officer 
+Mr. Buese, 50, joined Gulfport as the Chief Financial Officer in May 2021. Most recently, Mr. Buese served as Vice President, Chief Financial Officer and Treasurer of QEP Resources from January 2020 to March 2021. He joined QEP Resources in 2012 and held positions of increasing responsibility over a nine-year period, including Vice President of Finance and Treasurer and Director of Finance. Prior to joining QEP, Mr. Buese was Director of Finance at MarkWest Energy Partners, LP and served in various finance, treasury, accounting and investor relations roles from 2005 to 2012. Mr. Buese holds over 16 years of financial expertise in the energy industry and more than 25 years of financial experience overall. Mr. Buese received his Bachelor of Arts degree in Accounting from Michigan State University and Master of Science degree in Information Systems from the University of Colorado Denver. 
+Patrick K. Craine, Chief Legal and Administrative Officer 
+Mr. Craine, 49, has served as Chief Legal and Administrative Officer since June 2021 and joined Gulfport as Executive Vice President, General Counsel and Corporate Secretary in May 2019. Prior to joining the Company, Mr. Craine served as 
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+Deputy General Counsel – Chief Risk and Compliance Officer at Chesapeake Energy Corporation. Prior to joining Chesapeake in 2013, Mr. Craine was a partner with Bracewell LLP, a global law firm, where his practice focused on securities and corporate regulatory matters and investigations. Before Mr. Craine entered private practice, he served as a lawyer with the U.S. Securities and Exchange Commission and the Financial Industry Regulatory Authority where he held leadership positions in their Oil and Gas Task Forces. Mr. Craine has over 20 years of extensive senior-level experience handling a broad range of securities, corporate, regulatory, governance, compliance and litigation matters, with particular expertise in the energy industry. Mr. Craine received his Bachelor of Arts degree, summa cum laude, Phi Beta Kappa, from Wabash College, and his Juris Doctorate, cum laude, from the Southern Methodist University Dedman School of Law. 
+Michael J. Sluiter, Senior Vice President of Reservoir Engineering 
+Mr. Sluiter, 49, joined Gulfport as the Senior Vice President of Reservoir Engineering in December 2018 from Noble Energy, Inc., where he most recently served as the Permian Basin Business Unit Manager at Noble Energy, Inc. Prior to joining Noble in 2007, he spent over 17 years developing his skills and expertise in unconventional resource development, reservoir engineering, subsurface development, business development/M&A, and leadership at Noble Energy, Santos Australia and Santos USA. Mr. Sluiter began his career as a wireline field services engineer for Schlumberger in Thailand. Mr. Sluiter is a graduate of the University of Sydney, Australia, with a Bachelor of Science degree in Chemical Engineering. 
+RJ Moses, Senior Vice President of Operations and Drilling 
+Mr. Moses, 42, has served as Senior Vice President of Operations and Drilling since March 2020 and joined Gulfport Energy as the Vice President of Operations, Appalachia in August 2019. Prior to joining the Company, Mr. Moses spent over 15 years at Noble Energy, Inc., where he most recently served as a Director of Operations for Noble’s Eagleford and Denver-Julesburg (DJ) business units, managing approximately one-third of Noble’s total production at the time. Prior to that, he held various leadership roles including Operations Manager for Noble’s Marcellus business unit along with several international roles including Asset Manager for the Tamar asset (offshore Israel), Project Manager for West Africa subsea development and Lead Reservoir Engineer for West Africa. In addition, Mr. Moses served as a Senior Financial Analyst in the International division and also spent four years as an international drilling and completion engineer for Noble. Mr. Moses graduated from Texas A&M University with a Bachelor of Science degree in Petroleum Engineering and holds a Master of Business Administration degree from Texas Christian University. 
+There is no family relationship between any of our officers or between any of them and the Company's Board of Directors. The executive officers serve at the pleasure of the Company's Board of Directors. 
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+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+The information called for by this Item 13 is incorporated herein by reference to the 2022 Proxy Statement.

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+ITEM 9A. CONTROLS AND PROCEDURES 
+Evaluation of Disclosure Control and Procedures 
+Under the direction of our Chief Executive Officer and our Chief Financial Officer, and with participation of management, we have established disclosure controls and procedures that are designed to ensure that information required to be disclosed by us 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's rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures. 
+As of December 31, 2021, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and our Chief Financial Officer have concluded that, as of December 31, 2021, our disclosure controls and procedures are effective. 
+In designing and evaluating the Company's disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the control system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events and the application of judgment in evaluating the cost-benefit relationship of possible controls and procedures. Because of these and other inherent limitations of control systems, there is only reasonable assurance that the Company's controls will succeed in achieving their goals under all potential future conditions. 
+Changes in Internal Control over Financial Reporting 
+During the second quarter ended June 30, 2021, we added certain key controls related to our reorganization discussed in Note 2 of our consolidated financial statements. 
+Except as described above, there were no changes in our internal control over financial reporting during the year ended December 31, 2021, which materially affected, or were reasonably likely to materially affect, our internal control over financial reporting. 
+Management's Report on Internal Control Over Financial Reporting 
+Management is responsible for the fair presentation of the consolidated financial statements of Gulfport Energy Corporation. Management is also responsible for establishing and maintaining a system of adequate internal control over financial reporting as defined in Rule 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. These internal controls are designed to provide reasonable assurance that the reported financial information is presented fairly, that disclosures are adequate and that the judgments inherent in the preparation of financial statements are reasonable. There are inherent limitations in the effectiveness of any system of internal control, including the possibility of human error and overriding of controls. Consequently, an effective internal control system can only provide reasonable, not absolute, assurance with respect to reporting financial information. 
+Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in the 2 013 Internal Control-Integrated Framework, management did not identify any material weaknesses in our internal control over financial reporting and concluded that out internal control over financial reporting was effective as of December 31, 2021. 
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+Grant Thornton LLP, the independent registered public accounting firm that audited our financial statements for the year ended December 31, 2021 included with this Annual Report on Form 10-K, has also audited our internal control over financial reporting as of December 31, 2021, as stated in their accompanying report. 
+/s/ Timothy J. Cutt /s/ William J. Buese 
+Name: Timothy J. Cutt Name: William J. Buese 
+Title: Chief Executive Officer Title: Chief Financial Officer 
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+Report of Independent Registered Public Accounting Firm 
+Board of Directors and Stockholders 
+Gulfport Energy Corporation 
+Opinion on internal control over financial reporting 
+We have audited the internal control over financial reporting of Gulfport Energy Corporation (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2021, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company as of December 31, 2021 (Successor) and for the period from May 18, 2021 through December 31, 2021 (Successor) and the period from January 1, 2021 through May 17, 2021 (Predecessor), and our report dated March 1, 2022 expressed an unqualified opinion on those financial statements. 
+Basis for opinion 
+The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 
+We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+Definition and limitations of internal control over financial reporting 
+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. 
+/s/ GRANT THORNTON LLP 
+Oklahoma City, Oklahoma 
+March 1, 2022 
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