Index to Financial ~~Statements~~Statement

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)



ý☒		ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	~~For the fiscal year ended December 31, 2018~~ OR

For the fiscal year ended December 31, 2020

¨
☐			TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934
			~~For the transition period from to~~

For the transition period from to

Commission File Number ~~000-19514~~

001-19514

Gulfport Energy Corporation

(Exact Name of Registrant As Specified in Its Charter)



~~Delaware~~

	~~73-1521290~~
Delaware			73-1521290
(State or Other Jurisdiction of Incorporation or Organization)				(IRS Employer Identification Number)
3001 Quail Springs Parkway ~~Oklahoma City, Oklahoma~~				~~73134~~
Oklahoma City,		Oklahoma	73134
(Address of Principal Executive Offices)				(Zip Code)

(405) 252-4600

(Registrant Telephone Number, Including Area Code)

Securities registered pursuant to Section 12(b) of the Act:

None(1)



~~Title of Each Class~~		~~Name of Each Exchange on Which Registered~~
~~Common Stock, par value $0.01 per share~~		~~The Nasdaq Stock Market LLC~~

(1) On November 27, 2020, our common stock was suspended from trading on the NASDAQ Stock Market LLC ("NASDAQ"). On November 30, 2020, our common stock began trading on the OTC Pink Marketplace maintained by the OTC Markets Group, Inc. under the symbol “GPORQ". On February 2, 2021, NASDAQ filed a Form 25 delisting our common stock from trading on NASDAQ, which delisting became effective 10 days after the filing of the Form 25. In accordance with Rule 12d2-2 of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), the de-registration of our common stock under section 12(b) of the Exchange Act became effective on February 12, 2021.

Securities registered pursuant to Section 12(g) of the Act: ~~None~~

Common Stock

(Title of Class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒

~~Yes~~ ý No ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨☐ No ý☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý☒ No ¨☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or such shorter period that the registrant was required to submit such files).

Yes ý☒ No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):

Large Accelerated filer ý☐ Accelerated filer ¨☒ Non-accelerated filer ¨☐

Smaller reporting company ¨☐ Emerging growth company ¨☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨☐

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Index to Financial Statement s

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨☐ No ý☒

The aggregate market value of ~~the voting and non-voting~~our common stock held by non-affiliates ~~of the registrant computed as of~~on June 30, ~~2018, based on the closing price~~2020 was approximately $174.4 million. As of ~~the~~February 22, 2021, there were 160,762,186 shares of our $0.01 par value common stock ~~on the NASDAQ Global Select Market on June 29, 2018, the last business day of the registrant’s most recently completed second fiscal quarter ($12.57 per share), was $2,178,406,831.~~

~~As of~~ ~~February 18, 2019, 162,986,045 shares of the registrant’s common stock were~~ outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of Gulfport Energy Corporation’s Proxy Statement for the ~~2018~~2021 Annual Meeting of Stockholders are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III of this Form 10-K.

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Index to Financial ~~Statements~~Statement

GULFPORT ENERGY CORPORATION

TABLE OF CONTENTS


				Page

FORWARD-LOOKING STATEMENTS				1

SUMMARY RISK FACTORS				2

					~~Page~~

~~FORWARD-LOOKING STATEMENTS~~PART I		14

ITEM 1.			~~PART I~~BUSINESS	24

ITEM 1.1A.			~~BUSINESS~~RISK FACTORS	219

ITEM ~~1A.~~1B.			~~RISK FACTORS~~	21

~~ITEM 1B.~~	UNRESOLVED STAFF COMMENTS	4437

ITEM 2.			PROPERTIES	4437

ITEM 3.			LEGAL PROCEEDINGS	5337

ITEM 4.			MINE SAFETY DISCLOSURES	5437

PART II				5437

ITEM 5.			MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	5438

ITEM 6.			SELECTED FINANCIAL DATA	5538

ITEM 7.			MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	5738

ITEM 7A.			QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	7256

ITEM 8.			FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	7458

ITEM 9.			CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	74105

ITEM 9A.			CONTROLS AND PROCEDURES	74105

ITEM 9B.			OTHER INFORMATION	77108

PART III				77108

ITEM 10.			DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	77108

ITEM 11.			EXECUTIVE COMPENSATION	77108

ITEM 12.			SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	77108

ITEM 13.			CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	77108

ITEM 14.			PRINCIPAL ACCOUNTING FEES AND SERVICES	77108

PART IV				78109

ITEM 15.			EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	78109

~~ITEM 16.~~				~~FORM 10-K SUMMARY~~Signatures	82115

~~Signatures~~		~~S-0~~

~~Index to Consolidated Financial Statements~~		~~F-1~~

DEFINITIONS

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Index to Financial ~~Statements~~Statement s


Unless the context otherwise indicates, references to “us,” “we,” “our,” “ours,” “Gulfport,” the “Company” and “Registrant” refer to Gulfport Energy Corporation and its consolidated subsidiaries. All monetary values, other than per unit and per share amounts, are stated in thousands of U.S. dollars unless otherwise specified. In addition, the following are other abbreviations and definitions of certain terms used within this Annual Report on Form 10-K:

2005 Plan. 2005 Stock Incentive Plan.
2013 Plan. 2013 Restated Stock Incentive Plan.
2019 Plan. 2019 Amended and Restated Stock Incentive Plan.
2020 Plan. 2020 Incentive Plan, which provides incentive awards for select employees of the Company that were tied to the achievement of one or more performance goals relating to certain financial and operational metrics over a period of time.
2023 Notes. 6.625% Senior Notes due 2023.
2024 Notes. 6.000% Senior Notes due 2024.
2025 Notes. 6.375% Senior Notes due 2025.
2026 Notes. 6.375% Senior Notes due 2026.
ASC. Accounting Standards Codification.
ASU. Accounting Standards Update.
Bankruptcy Code. Chapter 11 of Title 11 of the United States Code.
Bankruptcy Court. The United States Bankruptcy Court for the Southern District of Texas.
Bankruptcy Rules. The Federal Rules of Bankruptcy Procedure.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.
Bcf. One billion cubic feet of natural gas.
Bcfe. One billion cubic feet of natural gas equivalent.
Btu. British thermal unit, which represents the amount of energy needed to heat one pound of water by one degree Fahrenheit and can be used to describe the energy content of fuels.
Building Loan. Loan agreement for our corporate headquarters scheduled to mature in June 2025.
Chapter 11 Cases. Voluntary petitions filed on November 13, 2020 by 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.
Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas, oil and NGL.
DD&A. Depreciation, depletion and amortization.
Debtors. Collectively, 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.
Developed Acreage. The number of acres allocated or assignable to productive wells or wells capable of production.
Development well. A well drilled within the proved area of a natural gas or crude oil reservoir to the depth of a stratigraphic horizon known to be productive.
DIP Credit Facility. Senior secured superpriority debtor-in-possession revolving credit facility in an aggregate principal amount of $262.5 million.
Dry Hole. A well that does not produce crude oil and/or natural gas in economically producible quantities.
Exploratory Well. A well drilled to find crude oil or natural gas in an unproved area, to find a new reservoir in an existing field previously found to be productive of crude oil or natural gas in another reservoir, or to extend a known reservoir beyond the proved area.
Grizzly. Grizzly Oil Sands ULC.
Grizzly Holdings. Grizzly Holdings Inc.
Gross Acres or Gross Wells. Refers to the total acres or wells in which a working interest is owned.
Guarantors. All existing consolidated subsidiaries that guarantee the Company's revolving credit facility or certain other debt.
Held By Production. Refers to an oil and gas lease continued into its secondary term for so long as a producing oil and/or gas well is located on any portion of the leased premises or lands pooled therewith.
Horizontal Drilling. A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled horizontally within a specified interval.
LIBOR. London Interbank Offered Rate.

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LOE. Lease operating expenses.
MBbl. One thousand barrels of crude oil, condensate or natural gas liquids.
Mcf. One thousand cubic feet of natural gas.
Mcfe. One thousand cubic feet of natural gas equivalent.
MMBbl. One million barrels of crude oil, condensate or natural gas liquids.
MMBtu. One million British thermal units.
MMcf. One million cubic feet of natural gas.
MMcfe. One million cubic feet of natural gas equivalent.
Natural Gas Liquids (NGL). Hydrocarbons in natural gas that are separated from the gas as liquids through the process of absorption, condensation, adsorption or other methods in gas processing or cycling plants. Natural gas liquids primarily include ethane, propane, butane, isobutene, pentane, hexane and natural gasoline.
Net Acres or Net Wells. Refers to the sum of the fractional working interests owned in gross acres or gross wells.
Net Revenue Interest (NRI). An interest in an oil and natural gas property entitling the owner to a share of oil, natural gas or NGL production.
NYMEX. New York Mercantile Exchange.
OCC. Oklahoma Corporation Commission.
Petition Date. November 13, 2020.
Plan. Prearranged joint plan of reorganization under the Restructuring Support Agreement.
Pre-Petition Revolving Credit Facility. Senior secured revolving credit facility, as amended, with The Bank of Nova Scotia as the lead arranger and administrative agent and certain lenders from time to time party thereto with a maximum facility amount of $580 million.
Productive Well. A well found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
Proved Developed Reserves (PDPs). Reserves expected to be recovered through existing wells with existing equipment and operating methods.
Proved Undeveloped Reserves (PUDs). Proved reserves expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for completion.
PV-10. Present net value of estimated future net revenues, discounted at 10%.
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible crude oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.
Restructuring. Restructuring contemplated under the Restructuring Support Agreement including equitizing a significant portion of our pre-petition indebtedness and rejecting or renegotiating certain contracts.
Royalty Interest. Refers to the ownership of a percentage of the resources or revenues produced from a crude oil or natural gas property. A royalty interest owner does not bear exploration, development, or operating expenses associated with drilling and producing a crude oil or natural gas property.
RSA. Restructuring Support Agreement.
SCOOP. Refers to the South Central Oklahoma Oil Province, a term used to describe 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. Our acreage is primarily in Garvin, Grady and Stephens Counties.
SEC. The United States Securities and Exchange Commission.
Section 382.Internal Revenue Code Section 382.
Senior Notes. Collectively, the 6.625% Senior Notes due 2023, the 6.000% Senior Notes due 2024, the 6.375% Senior Notes due 2025 and the 6.375% Senior Notes due 2026.
Standardized Measure. Standardized measure of discounted future net cash flows.
Tcfe. One trillion cubic feet of natural gas equivalent.
Undeveloped Acreage. Lease or mineral acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and/or natural gas.
USEPA. United States Environmental Protection Agency.
Utica. Refers to the hydrocarbon bearing rock formation located in the Appalachian Basin of the United States and Canada. Our acreage is located primarily in Belmont, Harrison, Jefferson and Monroe Counties in Eastern Ohio.
Working Interest (WI). The operating interest which gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

iii

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FORWARD-LOOKING STATEMENTS

~~Our disclosure and analysis in this~~This Form 10-K may include forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended ~~or the Securities Act,~~(the "Securities Act"), Section 21E of the Securities Exchange Act of 1934, as amended ~~or the Exchange Act,~~(the "Exchange Act"), and the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In some cases, you can identify ~~forward-looking~~forward looking statements by terms such as “may,” “will,” “should,” “could,” “would,” “expects,” “plans,” “anticipates,” “intends,” “believes,” “estimates,” “projects,” “predicts,” “potential” and similar expressions intended to identify forward-looking statements. All statements, other than statements of historical facts, included in this Form 10-K that address activities, events or developments that we expect or anticipate will or may occur in the future, including such things as the potential effects of the Chapter 11 Cases on our operations, management, and employees, our ability to consummate the restructuring, our ability to continue as a going concern, the expected impact of the COVID-19 pandemic on our business, our industry and the global economy, estimated future net revenues from oil and gas reserves and the present value thereof, future capital expenditures (including the amount and nature thereof), business strategy and measures to implement strategy, competitive strength, goals, expansion and growth of our business and operations, plans, references to future success, reference to intentions as to future matters and other such matters are forward-looking statements.

These forward-looking statements are largely based on our expectations and beliefs concerning future events, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors relating to our operations and business environment, all of which are difficult to predict and many of which are beyond our control.

Although we believe our estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management's assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this Form 10-K are not guarantees of future performance, and we cannot assure any reader that those statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the factors listed in Item 1A. “Risk Factors” and Item 7. “Management's Discussion and Analysis of Financial Condition and Results of Operations” sections and elsewhere in this Form 10-K. All forward-looking statements speak only as of the date of this Form 10-K. ~~We do not intend to publicly update or revise any~~

All forward-looking statements, ~~as a result of new information, future events~~expressed or ~~otherwise, except as required~~implied, included in this Annual Report are expressly qualified in their entirety by ~~law. These~~this cautionary ~~statements qualify all~~statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements ~~attributable to us~~that we or persons acting on our ~~behalf.~~behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Annual Report.

Investors should note that we announce financial information in SEC filings. We may use the Investors section of our website (www.gulfportenergy.com) to communicate with investors. It is possible that the financial and other information posted there could be deemed to be material information. The information on our website is not part of this Annual Report on Form 10-K.

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Index to Financial ~~Statements~~Statement

~~PART I~~



~~ITEM 1.~~			~~BUSINESS~~

~~General~~

SUMMARY RISK FACTORS

Chapter 11 Cases Risks

•The Chapter 11 Cases may have a material adverse impact on our business, financial condition, results of operations and cash flows. In addition, the consummation of a plan of reorganization will result in the cancellation and discharge of our equity securities, including our common stock.

•Delays in the Chapter 11 Cases may increase the risk of us being unable to reorganize our business and emerge from bankruptcy and increase our costs associated with the bankruptcy process.

•We are subject to certain risks and uncertainties if our exclusive right to file a plan of reorganization is terminated.

•Adverse publicity in connection with the Chapter 11 Cases or otherwise could negatively affect our businesses.

•Trading in our common stock during the Chapter 11 Cases is highly speculative and poses substantial risks.

•The RSA is subject to significant conditions and milestones that may be difficult for us to satisfy.

•A plan of reorganization may not become effective.

•The audited consolidated financial statements included in this Form 10-K for the period ended December 31, 2020 contain disclosures that express substantial doubt about our ability to continue as a going concern.

•Upon emergence from bankruptcy, the composition of our Board of Directors may change significantly.

Financial, Liquidity and Commodity Price Risks

•Natural gas, oil and NGL prices fluctuate widely, and lower prices for an ~~independent~~extended period of time are likely to have a material adverse effect on our business

•Our commodity price risk management activities may limit the benefit we would receive from increases in commodity prices, may require us to provide collateral for derivative liabilities and involve risk that our counterparties may be unable to satisfy their obligations to us.

•We have a significant amount of indebtedness. Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects.

•Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase.

•We have significant capital needs, and our ability to access the capital and credit markets to raise capital on favorable terms is limited by our debt level and industry conditions.

•If we are unable to generate enough cash flow from operations to service our indebtedness or are unable to use future borrowings to refinance our indebtedness or fund other capital needs, in each case following our restructuring, we may have to undertake alternative financing plans, which may have onerous terms or may be unavailable.

•Our development, acquisition and exploration operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a loss of properties and a decline in our oil and natural gas reserves.

•Under our method of accounting for oil and natural gas properties, declines in commodity prices may result in impairment of asset value.

•A change of control could limit our use of net operating losses to reduce future taxable income.

Industry, Business and Operational Risks

•The oil and gas exploration and production industry is very competitive, and some of our competitors have greater financial and other resources than we do.

•If we are not able to replace reserves, we may not be able to sustain production.

•The actual quantities of and future net revenues from our proved reserves may be less than our estimates.

•Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.

•Part of our strategy involves drilling in existing or emerging shale plays using the latest available horizontal drilling and completion techniques; therefore, the results of our planned exploratory drilling in these plays are subject to risks associated with drilling and completion techniques and drilling results may not meet our expectations for reserves or production.

•Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.

•Oil and natural gas operations are uncertain and involve substantial costs and risks. Operating hazards and uninsured risks may result in substantial losses and could prevent us from realizing profits.

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•We are not the operator of all of our oil and natural gas properties and therefore are not in a position to control the timing of development efforts, the associated costs or the rate of production of the reserves on such properties.

•Oil and natural gas production operations, especially those using hydraulic fracturing, are substantially dependent on the availability of water. Our ability to produce natural gas, oil and NGL economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner.

•Substantially all of our producing properties are located in Eastern Ohio and Oklahoma, making us vulnerable to risks associated with operating in these regions.

•The loss of one or more of the purchasers of our production could adversely affect our business, results of operations, financial condition and cash flows.

•The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies, oilfield services or personnel may restrict our operations.

•Our operations may be adversely affected by pipeline, trucking and gathering system capacity constraints and may be subject to interruptions that could adversely affect our cash flow.

•Our forecasted production is less than our firm transportation commitment levels under our firm transportation contracts due to decreased developmental activities, which will result in excess firm transportation costs and may have a material adverse effect on our operations.

•The outbreak of the novel coronavirus, or COVID-19, has affected and may materially adversely affect, and any future outbreak of any other highly infectious or contagious diseases may materially adversely affect, our operations, financial performance and condition, operating results and cash flows.

•A deterioration in general economic, business or industry conditions would have a material adverse effect on our results of operations, liquidity and financial condition.

•Terrorist activities could materially and adversely affect our business and results of operations.

•Cyber-attacks targeting systems and infrastructure used by the oil and gas industry and related regulations may adversely impact our operations and, if we are unable to obtain and maintain adequate protection for our data, our business may be harmed.

Legal and Regulatory Risks

•The ultimate outcome of pending legal and governmental proceedings is uncertain, and there are significant costs associated with these matters.

•Decisions by the Ohio Supreme Court interpreting the Ohio Dormant Mineral Act relating to preservation of mineral rights by surface owners could require certain curative efforts to vest title in a portion of our leasehold acreage, increase our leasehold expenses, subject us to payment of additional royalties or result in the loss of some of our leasehold acreage in Ohio.

•We are subject to extensive governmental regulation and ongoing regulatory changes, which could adversely impact our business.

•Legislation or regulatory initiatives intended to address seismic activity could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could have a material adverse effect on our business.

•Future U.S. and state tax legislation may adversely affect our business, results of operations, financial condition and cash flow.

•Our business is subject to complex and evolving laws and regulations regarding privacy and data protection.

•We may have material liability related to plugging and abandonment, reclamation, civil lawsuits and regulatory fines related to our divested Louisiana assets.

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PART I


ITEM 1.			BUSINESS

Our Business

A Delaware corporation formed in 1997, we are an independent natural gas-weighted exploration and production company ~~focused on the exploration, exploitation, acquisition and production of natural gas, crude oil and natural gas liquids, or NGLs,~~with assets primarily located in the ~~United States.~~Appalachia and Anadarko basins. Our corporate strategy is focused on the economic development of our asset base in an effort 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.generate sustainable free cash flow. Our principal properties are located in Eastern Ohio, where we target development in the Utica ~~Shale primarily~~formation, and Central Oklahoma where we target development 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.formations.

~~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 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 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 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 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.

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~~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,~~2020, we had ~~4.7 trillion cubic feet of natural gas equivalent, or~~2.6 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~~$540.0 million and ~~Tatex II.~~a PV-10 of $540.0 million. See ~~Item 2.~~ "~~Properties-Proved Oil and Natural Gas Reserves~~”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.

~~Principal Oil~~Information About Us

Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and ~~Natural Gas Properties~~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

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 ~~table presents~~the Petition Date, we are permitted and intend to pay vendors in the ordinary course.

Subject to certain ~~information~~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 ~~December 31, 2018 reflecting~~the Petition Date. In addition, the filing of new judicial or administrative actions against us or our ~~net interest~~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 ~~principal producing oil~~assets, liabilities, capital structure, shareholders, officers and ~~natural gas~~directors could change materially because of our Chapter 11 Cases. In addition, the description of our operations, properties and capital plans included in this

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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 ~~Shale primarily~~and SCOOP operating areas. Our strategy is to develop our assets in ~~Eastern Ohio,~~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 ~~SCOOP~~highest rate of return and we deploy leading drilling and completion techniques and technologies in ~~Oklahoma,along the Louisiana Gulf Coast,~~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 focus our development and production activities in the ~~Niobrara Formation in Northwestern Colorado and in the Bakken Formation in Western North Dakota and Eastern Montana.~~geographic operating areas described below.

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

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~~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 a hydrocarbon bearing rock formation 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 LimestoneWe have approximately 193,000 net reservoir acres located primarily in Belmont, Harrison, Jefferson and ~~is located a few thousand feet below the Marcellus Shale.~~

~~The source rock portion of~~Monroe Counties in Eastern Ohio where 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~~ During the fourth quarter 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 wells, 290 of~~ ~~which were completed and were producing. In 2018,~~2020 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.~~

~~Table of Contents~~

~~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,~~produced 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~~887 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~~net to our interests in this area and accounts for approximately ~~66,000~~ ~~gross (50,000~~ ~~net) surface acres in the~~ 82% of our total production.

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~~area 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 fromOklahoma within 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.~~basin. The SCOOP play mainly targets the Devonian to Mississippian aged Woodford, ~~Shale.~~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 ~~is a silica and highly organic rich black shale that was deposited about 320 million to 370 million years ago. Across~~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~~consists of hydrocarbon-bearing interbedded shales and siliceous limestones ranging in thickness from 150 to ~~the Meramec and Osage being developed in the STACK, or Sooner Trend Anadarko Basin Canadian and Kingfisher Counties, play~~over 450 feet and is ~~located between~~overlain by the ~~organic-rich Woodford and~~ Caney ~~Shales.~~Shale. The ~~Sycamore~~Springer formation ~~is approximately 250 feet thick~~ across our ~~acreage~~ position ~~presenting~~is comprised of a ~~significant development target.~~

~~Facilities~~

~~There are standard land oil~~series of lenticular sand 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

~~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 net) 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~~

shale units. 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.

~~Table of Contents~~

~~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 PUDprimary targets are ~~up-dip offsets~~a series of porous, low clay and organic-rich packages within the Goddard Shale member ranging in thickness from 50 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~~

Inover 250 feet. During the fourth quarter of ~~2018, our net production at WCBB was~~2020, we produced approximately ~~837~~ ~~MMcfe, or an average of~~ ~~9.1~~189 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 beneficialnet to our interests in ~~approximately~~ ~~4,116~~ ~~acres, including the Erwin Heirs Block, which is located on land,~~this area 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~~

~~Table of Contents~~

~~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 MMcfe, or an average of1.2~~ ~~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 spud 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~~accounts for approximately ~~2,900~~ ~~net acres. In 2018, no wells were spud on~~18% of our ~~Niobrara Formation acreage.~~total production.

~~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 approximately 76~~ ~~MMcfe, or an average o~~f~~827.1~~ ~~Mcfe per day, of which 86% was from 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.

~~Table of Contents~~

~~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 including the Bakken formation in ~~Louisiana, Texas~~North Dakota that account for less than 1% of our total production and ~~Oklahoma as described in the~~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.

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, ~~2018:~~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.

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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
—


	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

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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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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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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 ~~24.9%~~24.5% interest in Grizzly. As of December 31, ~~2018,~~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 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, thesehad no proved 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

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~~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,~~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 ~~21.9%~~21.5%, of ~~Mammoth Energy’s~~the outstanding common ~~stock.~~stock of Mammoth Energy Services Inc.

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 saleSee Note 5 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~~notes to our consolidated financial statements included elsewhere in this report for additional information regarding ~~these and~~ our ~~other~~ 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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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.~~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 ~~these companies~~our competitors not only explore for and produce oil and natural gas, but also ~~carry on~~have midstream and ~~refining~~further downstream operations and market ~~petroleum and other~~a variety of hydrocarbon 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,~~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.

~~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~~Title 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.

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~~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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~~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~~Properties

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 affectingIt is customary in the oil and natural gas industry ~~is under constant~~to make only a preliminary review ~~for amendment or expansion. Some~~ of ~~these requirements carry substantial penalties for failure~~title to ~~comply. The regulatory burden on the~~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 ~~increases~~practice. Certain of our ~~cost of doing business and, consequently, affects our profitability.~~

~~We own interests in producing~~ oil and natural gas properties ~~located~~may be subject to title defects, encumbrances, easements, servitudes or other restrictions, none of which, in management's opinion, will in the ~~Utica Shale primarily in Eastern Ohio, the SCOOP Woodford~~aggregate materially restrict our operations.

Regulation - Environment, Health and ~~SCOOP Springer plays in Oklahoma, along the Louisiana Gulf Coast~~Safety

Exploration and ~~in the Niobrara Formation in Northwestern Colorado~~Production, Environmental, Health and ~~the Bakken Formation in Western North Dakota~~Safety, and ~~Eastern Montana. The states in which our fields are located regulate the production~~Occupational Laws 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.Regulations

~~Environmental Regulation~~

Our ~~oil and natural gas exploration, development and production~~ operations are subject to ~~stringent~~federal, tribal, state, and local 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.regulations. These laws and regulations ~~may require~~relate to matters that include, but are not limited to, the ~~acquisition~~following:

Table of ~~a permit before drilling commences, restrict the types, quantities~~Contents

Index to Financial Statement s

•reporting of workplace injuries and ~~concentrations~~illnesses;

•industrial hygiene monitoring;

•worker protection and workplace safety;

•approval or permits to drill and to conduct operations;

•provision of ~~various substances that can be released into the environment in connection with~~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 ~~limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically or seismically~~in sensitive areas, ~~and other protected areas, require action to prevent or remediate pollution from current or former operations,~~ 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 ~~abandoned wells~~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 ~~closing earthen pits,~~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 ~~suspension~~development of additional regulations 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 relatedchanges to ~~our owned or operated facilities. Liability under such~~existing regulations. Failure to comply with these laws and regulations ~~is often strict (i.e., no showing~~can lead to the imposition of ~~“fault” is required)~~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 ~~can~~sue operators for alleged violations of environmental law. We consider the costs of environmental protection and of safety and health compliance to be ~~joint~~necessary, manageable parts of our business. We have been able to plan for and ~~several. Moreover, it is not uncommon for neighboring landowners~~comply with environmental, safety 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 environmentalhealth laws and regulations ~~occur frequently,~~without materially altering our operating strategy or incurring significant unreimbursed expenditures. However, based on regulatory trends and ~~any changes that result in more~~increasingly 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~~expenses related 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 legalityprotection of the ~~original conduct, on classes~~environment, safety and health have increased over the years and may continue to increase. We cannot predict with any reasonable degree of ~~persons who are considered to be responsible~~certainty our future exposure concerning such matters. See the Risk Factors described in Item 1A. of this report for ~~the release~~further discussion 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,governmental regulation 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,ongoing regulatory changes, 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.~~environmental matters.

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

Our 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 2016conservation 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 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 ~~natural~~ gas properties. ~~Some~~In the United States, some states allow the forced pooling or integration of tracts to facilitate ~~exploration while other~~exploration. Other states rely on voluntary pooling of lands and ~~leases. In some instances, forced pooling or unitization~~leases which may ~~be implemented by third parties~~make it more difficult to develop oil and ~~may reduce our interest in the unitized~~gas properties. In addition, federal and state conservation laws ~~establish maximum rates of production from oil and natural gas wells,~~ generally ~~prohibit~~limit the venting or flaring of natural gas, and state conservation laws impose certain requirements regarding the ~~ratability~~ratable purchase of production. These ~~laws~~regulations often impose additional operational costs to us and ~~regulations may~~can also limit the ~~amount~~amounts of oil and ~~natural~~ gas we can produce

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from our wells ~~or limit~~and the number of wells or the locations at which we can drill. ~~Moreover, each~~

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 ~~generally imposes a production~~ agencies have continued to assess the potential impacts of hydraulic fracturing, which could spur further action toward federal, state and/or ~~severance tax with respect~~local legislation

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and regulation. Further restrictions of hydraulic fracturing could reduce the ~~production~~amount of natural gas, oil and ~~sale~~NGL that we are ultimately able to produce in commercial quantities from our properties.

Certain of ~~oil,~~our U.S. natural gas and ~~natural~~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 ~~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~~measurement and royalty payment obligations for production from federal lands. In addition, on January 20, 2021, the ~~future. The effect~~Acting Secretary for the Department of ~~such future regulations may be to limit~~ the ~~amounts of~~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 ~~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 resultedreview results in the ~~complete removal~~development of ~~all price and non-price controls for sales~~additional restrictions on drilling, limitations on the availability 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, includingleases, or restrictions on 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 areobtain 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~~it 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~~impact on ~~us.~~our operations.

~~Operational~~

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,~~blow-outs, pipe ~~failures~~failure, abnormally pressured formations and ~~in some cases, abnormally high pressure formations which could lead to~~ environmental hazards such as oil spills, natural gas leaks, ~~and the discharge~~ruptures or discharges of toxic gases. If any of these should occur, we could incur legal defense costs and could ~~be required to pay amounts~~suffer substantial losses due to injury or loss of life, severe damage to or destruction toof 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 ~~accordance with what~~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 ~~to be~~these policies are customary in the industry, ~~practice, we maintain insurance~~they do not provide complete coverage 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~~policy limits scale to our ~~oil and natural gas properties, operational control of~~working interest percentage in 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,situations. In addition, our insurance ~~is subject to exclusions and limitations, and there is no assurance~~does not cover penalties or fines that ~~such coverage will fully or adequately protect us against liability from all potential consequences, damages and losses. Any of these events could cause~~may be assessed by a ~~significant disruption to our business.~~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.

~~Currently, we have general liability~~ Our 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~~sufficient to ~~secure additional insurance~~cover every claim made against us or ~~bonding that might~~may not 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.commercially available for purchase in the future.

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

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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~~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~~clean-up services during ~~2018~~each of 2020 and ~~2017~~2019 were ~~approximately $0.6 million and $0.2 million.~~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. ~~To supplement our planning and operation activities in Ohio, Oklahoma and Louisiana, we also actively manage an incident response planning program and coordinate~~We pay these companies a retainer plus additional amounts when they provide us 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 Rightclean up services.

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Index 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.

Financial Statement s



~~ITEM 1A.~~			~~RISK FACTORS~~

~~Risks Related~~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 ~~Business~~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 ~~Industry~~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.

~~Market conditions for~~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 ~~volatility in prices for~~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 ~~have~~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 ~~past adversely affected,~~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.

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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.

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ITEM 1A.			RISK FACTORS

Summary of Risk Factors

There are numerous factors that affect our business and operating results, many of which are beyond our control. The following is a summary of significant factors that might cause our future results to differ materially from those currently expected. The risks described below are not the only risks facing our company. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may also affect our business operations. If any of these risks actually occur, our business, financial position, operating results, cash flows, reserves or our ability to pay our debts and other liabilities could suffer, the trading price and liquidity of our securities could decline and you may lose all or part of your investment in our securities.

Chapter 11 Cases Risks

The Chapter 11 Cases may have a material adverse impact on our business, financial condition, results of operations and cash flows. In addition, the consummation of a plan of reorganization will result in the cancellation and discharge of our equity securities, including our common stock.

The Chapter 11 Cases could have a material adverse effect on our business, financial condition, results of operations and cash flows. During the pendency of the Chapter 11 Cases, our management may be required to spend a significant amount of time and effort dealing with restructuring matters rather than focusing exclusively on our business operations. Bankruptcy Court protection and operating as debtors in possession also may make it more difficult to retain management and the key personnel necessary to the success of our business. In addition, during the pendency of the Chapter 11 Cases, our customers, vendors and service providers might lose confidence in our ability to reorganize our business successfully and may ~~continue~~seek to establish alternative commercial relationships, renegotiate the terms of our agreements, terminate their relationships with us or require financial assurances from us, subject to the automatic stay imposed by the Bankruptcy Code.

Other significant risks include or relate to the following:

•the effects of the filing of the Chapter 11 Cases on our business and the interests of various constituents, including our shareholders;

•Bankruptcy Court rulings in the ~~future~~Chapter 11 Cases, including with respect to our motions, as well as the outcome of other pending litigation;

•our ability to operate within the restrictions and the liquidity limitations of the DIP Credit Agreement and any related orders entered by the Bankruptcy Court in connection with the Chapter 11 Cases;

•our ability to maintain strategic control as debtors in possession during the pendency of the Chapter 11 Cases;

•the length of time that we will operate with Chapter 11 protection and the continued availability of operating capital during the pendency of the Chapter 11 Cases;

•increased advisory costs during the pendency of the Chapter 11 Cases;

•the risks associated with restrictions on our ability to pursue some of our business strategies during the pendency of the Chapter 11 Cases;

•our ability to satisfy the conditions precedent to consummation of a plan of reorganization;

•the potential adverse effects of the Chapter 11 Cases on our business, cash flows, liquidity, financial condition and results of operations;

•the ultimate outcome of the Chapter 11 Cases in general;

•the cancellation of our existing equity securities, including our outstanding shares of common stock in the Chapter 11 Cases;

•the potential material adverse effects of claims that may not be discharged in the Chapter 11 Cases;

•uncertainties regarding the reactions of our customers, prospective customers, vendors and service providers to the Chapter 11 Cases;

•uncertainties regarding our ability to retain and motivate key personnel; and

•uncertainties and continuing risks associated with our ability to achieve our stated goals and continue as a going concern.

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Further, under Chapter 11, transactions outside the ordinary course of business are subject to the prior approval of the Bankruptcy Court, which may limit our ability to respond in a timely manner to certain events, to take advantage of certain opportunities or adapt to changing market or industry conditions.

Because of the risks and uncertainties associated with the Chapter 11 Cases, we cannot predict or quantify the ultimate impact that events occurring during the Chapter 11 Cases may have on our business, cash flows, liquidity, financial condition and results of operations, nor can we provide any assurance as to our ability to continue as a going concern.

As a result of the Chapter 11 Cases, realization of assets and liquidation of liabilities are subject to uncertainty. While operating under the protection of the Bankruptcy Code, and subject to Bankruptcy Court approval or otherwise as permitted in the normal course of business, we may sell or otherwise dispose of assets and liquidate or settle liabilities for amounts other than those reflected in our consolidated financial statements.

Delays in the Chapter 11 Cases may increase the risk of us being unable to reorganize our business and emerge from bankruptcy and increase our costs associated with the bankruptcy process.

There can be no assurance that a plan of reorganization will become effective in accordance with its terms on the timeline we anticipate, or at all. Prolonged Chapter 11 proceedings could adversely affect our ~~revenue,~~relationships with customers and employees, among other parties, which in turn could adversely affect our business, competitive position, financial condition, liquidity and results of operations and our ability to continue as a going concern. A weakening of our financial condition, liquidity and results of operations could adversely affect our ability to implement a plan of reorganization (or any other Chapter 11 plan). If we are unable to consummate a plan of reorganization, we may be forced to liquidate.

We are subject to certain risks and uncertainties if our exclusive right to file a plan of reorganization is terminated.

At the outset of a Chapter 11 case, the Bankruptcy Code provides debtors in possession the exclusive right to file and solicit acceptance of a plan of reorganization for the first 120 days of the bankruptcy case, subject to extension at the discretion of the court. All other parties are prohibited from filing or soliciting a plan of reorganization during this period. If the Bankruptcy Court terminates that right or the exclusivity period expires, there could be a material adverse effect on our ability to achieve confirmation of a plan in order to achieve our stated goals. The possible decision of creditors and/or other third parties, whose interest may be inconsistent with our own, to file alternative plans of reorganization could further protract the Chapter 11 Cases, leading us to continue to incur significant professional fees and costs. Because of these risks and uncertainties associated with the termination or expiration of our exclusivity rights, we cannot predict or quantify the ultimate impact that events occurring during the Chapter 11 Cases may have on our business, cash flows, ~~profitability, growth, production~~liquidity, financial condition and results of operations, nor can we predict the ultimate impact that events occurring during the Chapter 11 Cases may have on our corporate or capital structure.

Adverse publicity in connection with the Chapter 11 Cases or otherwise could negatively affect our businesses.

Adverse publicity or news coverage relating to us, including, but not limited to, publicity or news coverage in connection with the Chapter 11 Cases, may negatively impact our efforts to establish and promote a positive image after emergence from the Chapter 11 Cases.

Trading in our common stock during the Chapter 11 Cases is highly speculative and poses substantial risks.

The RSA contemplates that our existing equity interests will be cancelled and discharged in connection with the Chapter 11 Cases and the ~~present~~holders of those equity interests will be entitled to no recovery. Accordingly, any trading in our common stock during the pendency of the Chapter 11 Cases is highly speculative and poses substantial risks to purchasers of our common stock.

Since November 30, 2020, our common stock has been trading on the OTC Pink Marketplace maintained by the OTC Markets Group, Inc. under the symbol “GPORQ”. Securities traded in the over-the-counter market generally have significantly less liquidity than securities traded on a national securities exchange, due to factors such as a reduction in the number of investors that will consider investing in the securities, the number of market makers in the securities, reduction in securities analyst and news media coverage and lower market prices than might otherwise be obtained. In addition to those factors, the market for the outstanding shares of our common stock has been adversely affected by the provisions of the RSA that contemplate that our existing equity interests will be cancelled and discharged in connection with the Chapter 11 Cases and the holders of those equity interests, including the holders of our outstanding shares of common stock, will be entitled to no recovery relating to those equity interests. We can provide no assurance that our common stock will continue to trade on the OTC Pink Marketplace, whether broker-dealers will continue to provide public quotes of our common stock on that market,

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whether the trading volume of our common stock will be sufficient to provide for an efficient trading market or whether quotes for our common stock will continue to be provided on that market in the future.

The RSA is subject to significant conditions and milestones that may be difficult for us to satisfy.

There are certain material conditions we must satisfy under the RSA, including the timely satisfaction of milestones in the Chapter 11 Cases, which include the consummation of the financing contemplated by the Exit Credit Facilities and other transactions contemplated by a plan of reorganization. Our ability to timely complete such milestones is subject to risks and uncertainties, many of which are beyond our control.

A plan of reorganization may not become effective.

Even if a plan of reorganization is confirmed by the Bankruptcy Court, it may not become effective because it is subject to the satisfaction of certain conditions precedent (some of which are beyond our control). There can be no assurance that such conditions will be satisfied and, therefore, that a plan of reorganization will become effective and that the Debtors will emerge from the Chapter 11 Cases as contemplated by a plan of reorganization. If the effective date of a plan of reorganization is delayed, the Debtors may not have sufficient cash available to operate their businesses. In that case, the Debtors may need new or additional post-petition financing, which may increase the cost of consummating a plan of reorganization. There can be no assurance of the terms on which such financing may be available or if such financing will be available. If the transactions contemplated by a plan of reorganization are not completed, it may become necessary to amend the plan of reorganization. The terms of any such amendment are uncertain and could result in material additional expense and result in material delays to the Chapter 11 Cases.

The audited consolidated financial statements included in this Form 10-K for the period ended December 31, 2020 contain disclosures that express substantial doubt about our ability to continue as a going concern.

The audited consolidated financial statements included in this Form 10-K for the period ended December 31, 2020 have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities and other commitments in the normal course of business and does not include any adjustments that might result from uncertainty about our ability to continue as a going concern. Such assumption may not be justified. Our liquidity has been negatively impacted by the prolonged depressed price averages we receive for the oil, natural gas and NGL we sell and our substantial indebtedness and associated debt-related expenses. As a result of these and other factors, we entered into the RSA and commenced the Chapter 11 Cases. The RSA contemplates that our equity investors, including the holders of our common stock, will lose the entire value of their investment in our ~~estimated reserves.~~business. The inclusion of disclosures that express substantial doubt about our ability to continue as a going concern may negatively impact the trading price of our common stock and have an adverse impact on our relationships with third parties with whom we do business, including our customers, subcontractors, suppliers and employees, and could have a material adverse impact on our business, financial condition, results of operations and cash flows.

Upon emergence from bankruptcy, the composition of our Board of Directors will likely change significantly.

The composition of our Board of Directors is expected to change significantly following the Chapter 11 Cases. Any new directors may have different backgrounds, experiences and perspectives from those individuals who currently serve on our Board of Directors and, thus, may have different views on the issues that will determine the future of our company. As a result, our future strategy and plans may differ materially from those of the past.

Financial, Liquidity and Commodity Price Risks

Natural gas, oil and NGL prices fluctuate widely, and lower prices for an extended period of time are likely to have a material adverse effect on our business.

Our revenues, cash flows, profitability, future rate of growth, production and the carrying value of our oil and natural gas properties depend significantly upon the prevailing prices for natural gas and, to a lesser extent, ~~oil. Historically,~~oil and NGL. We incur substantial expenditures to replace reserves, sustain production and fund our business plans. Low oil, natural gas and NGL prices can negatively affect the amount of cash available for capital expenditures, debt service and debt repayment and our ability to borrow money or raise additional capital and, as a result, could have a material adverse effect on our financial condition, results of operations, cash flows and reserves. In addition, periods of low natural gas, oil and NGL prices may result in ceiling test write-downs of our oil and natural gas ~~prices~~properties.

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Historically, the markets for natural gas, oil and NGL have been volatile, and they are ~~subject~~likely to continue to be volatile. For example, during 2019, West Texas intermediate light sweet crude oil, which we refer to as West Texas Intermediate or WTI, prices ranged from $46.31 to $66.24 per barrel and the Henry Hub spot market price of natural gas ranged from $1.75 to $4.25 per MMBtu. During 2020, WTI prices ranged from $(36.98) to $63.27 per barrel and the Henry Hub spot market price of natural gas ranged from $1.33 to $3.14 per MMBtu.

Wide fluctuations in ~~response to changes in supply~~natural gas, oil and ~~demand, market uncertainty and a variety of additional~~NGL prices may result from factors that are beyond our control, including:

•domestic and worldwide supplies of oil, natural gas and ~~domestic supplies~~NGL, including U.S. inventories of oil and natural ~~gas;~~gas reserves;

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•the level of prices, and expectations about future prices, of oil and natural gas;

•changes in the level of consumer and industrial demand, including impacts from global or national health epidemics and concerns, such as the recent coronavirus;

•the cost of exploring for, developing, producing and delivering oil and natural gas;

•the expected rates of declining current production;

•changes in the level of consumer and industrial demand;

•the price and availability of alternative fuels;

~~technical~~•technological advances affecting energy consumption;

•risks associated with operating drilling rigs;

•the effectiveness of worldwide conservation measures;

•the availability, proximity and capacity of ~~pipeline capacity and~~pipelines, other transportation facilities and processing facilities;

•the level and effect of trading in commodity futures markets, including by commodity price speculators and others;

•U.S. exports of oil, natural gas, liquefied natural gas and NGL;

•the price and level of foreign imports;

•the nature and extent of domestic and foreign governmental regulations and taxes;

•the ability of the members of the Organization of Petroleum Exporting Countries and others to agree to and maintain oil price and production controls;

~~speculative trading in crude oil and natural gas derivative contracts;~~

•political or economic instability or armed conflict in oil and natural gas producing regions, including the Middle East, Africa, South America and Russia;

~~the overall~~ •weather conditions;

•acts of terrorism; and

•domestic and global economic ~~environment; and~~

~~weather conditions, including hurricanes, and other natural disasters that can affect oil and natural gas operations over a wide area.~~conditions.

These factors and the volatility of the energy markets make it extremely difficult to predict future natural gas, oil and ~~natural gas~~NGL price movements with any certainty. ~~During 2017, West Texas intermediate light sweet crude oil, which we refer to as West Texas Intermediate or WTI, prices ranged from $42.48 to $60.46 per barrel and the Henry Hub spot market price of~~Even with natural gas, ranged from $2.44 to $3.71 per MMBtu. During 2018, WTI prices ranged from $44.48 to $77.41 per barrel and the Henry Hub spot market price of natural gas ranged from $2.49 to $6.24 per MMBtu. If the prices of oil and ~~natural gas decline, our operations, financial condition and level of expenditures for the development~~NGL derivatives currently in place to mitigate price risks associated with a portion of our ~~oil and natural gas reserves may be materially and adversely affected. In addition, lower oil and~~2021 cash flows, we have substantial exposure to natural gas prices, ~~may~~and to a lesser extent, oil and NGL prices, in 2022 and beyond. In addition, a prolonged extension of lower prices could reduce the ~~amount~~quantities of ~~oil and natural gas~~reserves that we ~~can produce economically.~~may economically produce. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development activities are curtailed, full cost accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. ~~Reductions~~

Our commodity price risk management activities may limit the benefit we would receive from increases in commodity prices, may require us to provide collateral for derivative liabilities and involve risk that our counterparties may be unable to satisfy their obligations to us.

To manage our exposure to price volatility, we enter into natural gas, oil and NGL price derivative contracts. Our natural gas, oil and NGL derivative arrangements may limit the benefit we would receive from increases in commodity prices. The fair value of our natural gas, oil and NGL derivative instruments can fluctuate significantly between periods. Our decision to mitigate cash flow volatility through derivative arrangements, if any, is based in part on our view of current and future market conditions and our desire to stabilize cash flows necessary for the development of our proved reserves. We may choose not to enter into derivatives if the pricing environment for certain time periods is not deemed to be favorable. Additionally, we may choose to liquidate existing derivative positions prior to the expiration of their contractual maturities to monetize gain positions

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for the purpose of funding our capital program.

Natural gas, oil and NGL derivative transactions expose us to the risk that our counterparties, which are generally financial institutions, may be unable to satisfy their obligations to us. During periods of declining commodity prices, the value of our commodity derivative asset positions increase, which increases our counterparty exposure. Although the counterparties to our hedging arrangements are required to secure their obligations to us under certain scenarios, if any of our counterparties were to default on its obligations to us under the derivative contracts or seek bankruptcy protection, it could have an adverse effect on our ability to fund our planned activities and could result in a larger percentage of our future cash flows being exposed to commodity price changes.

We have a significant amount of indebtedness. Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects.

As of December 31, 2020, we had approximately $1.8 billion in principal amount of debt outstanding, primarily attributable to our senior notes. We also had $292.9 million in borrowings outstanding under our Pre-Petition Revolving Credit Facility and $157.5 million in borrowings under our DIP Credit Facility.

Our outstanding indebtedness could have important consequences to you, including the following:

•our high level of indebtedness could make it more difficult for us to satisfy our obligations with respect to our indebtedness, and any failure to comply with the obligations under any of our debt instruments, including their restrictive covenants, could result in a default under our revolving credit facility or the indentures governing our senior notes;

•the restrictions imposed on the operation of our business by the terms of our debt agreements may hinder our ability to take advantage of strategic opportunities to grow our business;

•our ability to obtain additional financing for working capital, capital expenditures, debt service requirements, restructuring, acquisitions or general corporate purposes may be impaired, which could be exacerbated by further volatility in the credit markets;

•our level of indebtedness could place us at a competitive disadvantage compared to our competitors that may have proportionately less debt;

•our flexibility in planning for, or reacting to, changes in our ~~reserves~~business and the industry in which we operate may be limited;

•our high level of indebtedness makes us more vulnerable to economic downturns and adverse developments in our business; and

•we may be vulnerable to interest rate increases, as our borrowings under our revolving credit facility are at variable interest rates.

Any of the foregoing could ~~also negatively impact the~~have a material adverse effect on our business, financial condition, results of operations and prospects.

Our ability to pay our expenses and fund our working capital needs and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors. We will not be able to control many of these factors, such as commodity prices, other economic conditions and governmental regulation. If our borrowing base under our revolving credit facility ~~which could limit~~decreases as a result of lower prices of natural gas, oil or NGL, operating difficulties, declines in reserves or for any other reason, our liquidity and ability to conduct additional exploration and development ~~activities.~~

~~Strategic determinations,~~activities may be limited. To the extent that the value of the collateral pledged under our revolving credit facility declines as a result of lower oil and natural gas prices, asset dispositions or otherwise, we may be required to pledge additional collateral to maintain the current availability of the commitments thereunder, and we cannot assure you that we will be able to maintain a sufficiently high valuation to maintain the current borrowing base. In addition, if we are unable to generate sufficient cash flow and are otherwise unable to obtain funds necessary to meet required payments of principal, premium, if any, or interest on our indebtedness, or if we otherwise fail to comply with the various covenants, including ~~the allocation of capital~~financial and other resources to strategic opportunities, are challenging, and our failure to appropriately allocate capital and resources among our strategic opportunities may adversely affect our financial condition and reduce our future growth rate.

Our future growth prospects are dependent upon our ability to identify optimal strategies for our business. In developing our 2019 business plan, we considered allocating capital and other resources to various aspects of our businesses, including well development, reserve acquisitions, midstream infrastructure and other activities. We also considered our likely sources of capital. Notwithstanding the determinations madeoperating covenants, in the ~~development~~instruments governing our indebtedness, we could be in default under the terms of the agreements governing such indebtedness. In the event of such default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest. More specifically, the lenders under our ~~2019 plan, business opportunities not previously identified periodically come~~revolving credit facility could elect to terminate their commitments, cease making further loans and institute foreclosure proceedings against our ~~attention, including possible acquisitions~~assets, and ~~dispositions. If~~ we ~~fail to identify optimal business strategies, including~~could be forced into bankruptcy or litigation. Any of the appropriate rate of reserve development, or fail to optimize our capital investment and capital raising opportunities and the use of our other resources in furtherance of our business strategies, our financial condition and

above risks could materially

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~~growth rate may be~~ adversely ~~affected. Moreover, economic or other circumstances may change from those contemplated by~~affect our ~~2019 plan, and our failure to recognize or respond to those changes may limit our ability to achieve our objectives.~~

We periodically engage in acquisitions, dispositions and other strategic transactions, including equity investments and joint ventures such as our recent midstream agreement with EQT. These transactions involve various inherent risks, such as changes in prevailing market conditions, our ability to obtain the necessary regulatory approvals, the timing of and conditions that may be imposed on us by regulators and our ability to achieve benefits anticipated to result from the transactions. Further, our equity investments and joint venture arrangements may restrict our operational and corporate flexibility and subject us to risks and uncertainties, such as committing us to fund operating and/or capital expenditures, the timing and amount of which we may not be able to control. Further, the counterparties to these transactions may not satisfy their obligations to the joint venture. Our inability to complete a transaction or to achieve our strategic orbusiness, financial ~~goals in any transaction could have significant adverse effects on our earnings,~~condition, cash flows and ~~financial position.~~results of operations.

~~Concerns over general economic, business or industry conditions~~Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase.

Our earnings are exposed to interest rate risk associated with borrowings under our revolving credit facility and DIP credit facility. Our revolving credit facility and DIP Credit Facility are structured under floating rate terms. As such, our interest expense is sensitive to fluctuations in the London Interbank Offered Rate. At December 31, 2020, amounts borrowed under our revolving credit facility and DIP Credit Facility bore interest at the weighted average rates of 3.15% and 5.50%, respectively . A 1% increase in the average interest rate would have increased our interest expense by approximately $2.1 million based on outstanding borrowings under our revolving credit facility and DIP Credit Facility throughout the year ended December 31, 2020. An increase in our interest rate at the time we have variable interest rate borrowings outstanding under our revolving credit facility and DIP Credit Facility will increase our costs, which may have a material adverse effect on our results of operations ~~liquidity~~ and financial condition. As of December 31, 2020, we did not hedge our interest rate risk.

~~Concerns over global economic conditions, energy costs, geopolitical issues, inflation,~~We have significant capital needs, and our ability to access the ~~availability~~capital markets to raise capital on favorable terms is limited by our debt level and cost of credit and the European, Asian and the United States financial markets have contributed to economic volatility and diminished expectations for the global economy. In addition, continued hostilitiesindustry conditions.

Disruptions in the ~~Middle East~~capital and credit markets, in particular with respect to the ~~occurrence~~energy sector, could limit our ability to access these markets or ~~threat of terrorist attacks in the United States or other countries could adversely affect the global economy. These factors, combined with volatility in~~may significantly increase our cost to borrow. Low commodity prices ~~business and consumer confidence and unemployment rates,~~ have ~~in the past precipitated,~~caused and may incontinue to cause lenders to increase the ~~future precipitate, an economic slowdown. Concerns about global economic growth~~interest rates under our revolving credit facility, enact tighter lending standards, refuse to refinance existing debt around maturity on favorable terms or at all and reduce or cease to provide funding to borrowers. If we are unable to access the capital and credit markets on favorable terms, it could have a ~~significant~~material adverse effect on our business, financial condition, results of operations, cash flows and liquidity and our ability to repay or refinance our debt. Additionally, challenges in the economy have led and could further lead to reductions in the demand for natural gas, oil and NGL, or further reductions in the prices of natural gas, oil and NGL, which could have a negative impact on our financial position, results of operations and cash flows.

If we are unable to generate enough cash flow from operations to service our indebtedness or are unable to use future borrowings to refinance our indebtedness or fund other capital needs, in each case following our restructuring, we may have to undertake alternative financing plans, which may have onerous terms or may be unavailable.

Our earnings and cash flow could vary significantly from year to year due to the volatility of hydrocarbon commodity prices. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. Additionally, our future cash flow may be insufficient to meet our debt obligations and commitments or to make necessary capital expenditures. A range of economic, competitive, business and industry factors will affect our future financial performance and, as a result, our ability to generate cash flow from operations and service our debt. Factors that may cause us to generate cash flow that is insufficient to meet our debt obligations include the events and risks related to our business, many of which are beyond our control. Any cash flow insufficiency would have a material adverse impact on ~~global~~our business, financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact ourcondition, results of operations, cash flows and liquidity and our ability to repay or refinance our debt.

If we do not generate sufficient cash flow from operations to service our indebtedness following our restructuring, or if future borrowings are not available to us in an amount sufficient to enable us to pay or refinance our indebtedness, we may be required to undertake various alternative financing plans, which may include:

•seeking alternative financing or additional capital investment;

•selling strategic assets;

•reducing or delaying capital investments; or

•revising or delaying our strategic plans.

We cannot assure you that we would be able to implement any alternative financing plans, if necessary, on commercially reasonable terms or at all,or that any such alternative financing plans would allow us to meet our debt obligations following our restructuring. If we are unable to generate sufficient cash flow to satisfy our debt obligations or to obtain necessary and sufficient alternative financing, our business, financial ~~condition.~~condition, results of operations, cash flows and liquidity could be materially and adversely affected.

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Our development, acquisition and exploration operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a loss of properties and a decline in our oil and natural gas reserves.

Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. To increase reserves and production, we undertake development, exploration and other replacement activities or use third parties to accomplish these activities. We have made and expect to make in the future substantial capital expenditures in our business and operations for the development, production, exploration and acquisition of oil and natural gas reserves. For example, we currently estimate our exploration and production capital expenditures for 2019 to be in the range of $525.0 million to $550.0 million and an additional $40.0 million to $50.0 million for leasehold expenditures, primarily lease extensions and infill leasing within our Utica Shale and Scoop development plans.

Historically, we have financed capital expenditures primarily with cash flow from operations, the issuance of equity and debt securities and borrowings under our ~~bank and other~~revolving credit ~~facilities.~~facility. Our cash flow from operations and access to capital are subject to a number of variables, including:

•our proved reserves;

•the volume of oil and natural gas we are able to produce from existing wells;

•the prices at which oil and natural gas are sold;

•our ability to acquire, locate and produce economically new reserves; and

•our ability to borrow under our credit facility.

We cannot assure you that our operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. Further, our actual capital expenditures in ~~2019~~2021 could exceed our capital expenditure budget. In the event our capital expenditure requirements at any time are greater than the amount of capital we

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have available, we could be required to seek additional sources of capital, which may include traditional reserve base borrowings, debt financing, joint venture partnerships, production payment financings, sales of assets, offerings of debt or equity securities or other means. We cannot assure you that we will be able to obtain debt or equity financing on terms favorable to us, or at all.

If we are unable to fund our capital requirements, we may be required to curtail our operations relating to the exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves, or we may be otherwise unable to implement our development plan, complete acquisitions or take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations. In addition, a delay in or the failure to complete proposed or future infrastructure projects could delay or eliminate potential efficiencies.

~~Our failure~~Under our method of accounting for oil and natural gas properties, declines in commodity prices may result in impairment of asset value.

We use the full cost method of accounting for oil and natural gas operations.Accordingly, all costs, including nonproductive costs and certain general and administrative costs associated with acquisition, exploration and development of oil and natural gas properties, are capitalized.Net capitalized costs are limited to ~~successfully identify, complete~~the estimated future net revenues, after income taxes, discounted at 10% per year, from proved oil and ~~integrate~~natural gas reserves and the cost of the properties not subject to amortization.Such capitalized costs, including the estimated future ~~acquisitions~~development costs and site remediation costs, if any, are depleted by an equivalent units-of-production method, converting natural gas to barrels at the ratio of six Mcf of natural gas to one barrel of oil.

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being amortized, less income tax effects related to differences between the book and tax basis of the oil and natural gas properties.If the net book value reduced by the related net deferred income tax liability exceeds the ceiling, an impairment or noncash writedown is required.A ceiling test impairment can result in a significant loss for a particular period.Once incurred, a write down of oil and natural gas properties is not reversible at a later date, even if oil or gas prices increase.As a result of the decline in commodity prices, we recorded a ceiling test impairment of $1.4 billion for the year ended December 31, 2020.If prices of natural gas, oil and natural gas liquids continue to decrease, we will be required to further write down the value of our oil and natural gas properties.Future non-cash asset impairments could negatively affect our results of operations.

A change of control could limit our use of net operating losses to reduce future taxable income.

As of December 31, 2020, we had a net operating loss, or NOL, carryforward of approximately $1.9 billion for federal income tax purposes. If we were to experience an “ownership change,” as determined under Section 382 of the Internal Revenue Code of 1986, as amended (or the "Code"), our ~~earnings and slow~~ability to offset taxable income arising after the ownership change with NOLs generated prior to the ownership change would be limited, possibly substantially. In general, an ownership change would establish an annual limitation on the amount of our ~~growth.~~

~~There~~pre-change NOLs we could utilize to offset our taxable income in any future taxable year to an amount generally equal to the value of our stock immediately prior to the ownership change multiplied by the long-term tax-exempt rate for the month in which such ownership change occurs. In general, an ownership change will occur if there is ~~intense competition for acquisition opportunities~~a cumulative increase in our ~~industry.~~ ownership of more than 50 percentage points by one or more “5% shareholders” (as defined in the Code) at any time during a rolling three-year period. On April 30, 2020, the board of directors of the Company adopted a tax benefits preservation plan in order to protect against a possible limitation on the Company’s ability to use its tax net operating losses and certain other tax benefits to reduce potential future U.S. federal income tax obligations.The Tax Benefits Preservation Plan is intended to prevent against such an ownership change by deterring any person or group from acquiring beneficial ownership of 4.9% or more of the Company’s securities.

Industry, Business and Operational Risks

The oil and gas exploration and production industry is very competitive, and some of our competitors have greater financial and other resources than we do.

We face competition in every aspect of our business, including, but not limited to, buying and selling reserves and leases, obtaining goods and services needed to operate our business and marketing natural gas, oil or NGL. Competitors include multinational oil companies, independent production companies and individual producers and operators. Some of our competitors have greater financial and other resources than we do and, due to our debt levels and other factors, may have greater access to the capital and credit markets. 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. As a result, these competitors may be able to address these competitive factors more effectively or weather industry downturns more easily than we can. We also face indirect competition from alternative energy sources, including wind, solar and electric power.

Our performance depends largely on the talents and efforts of highly skilled individuals and on our ability to attract new employees and to retain and motivate our existing employees. Competition in our industry for qualified employees is intense. If we are unsuccessful in attracting and retaining skilled employees and managerial talent, our ability to compete effectively may be diminished. We also compete for the equipment required to explore, develop and operate properties. Typically, during times of rising commodity prices, drilling and operating costs will also increase. During these periods, there is often a shortage of drilling rigs and other oilfield equipment and services, which could adversely affect our ability to execute our development plans on a timely basis and within budget.

If we are not able to replace reserves, we may not be able to sustain production.

Our future success depends largely upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Unless we replace the reserves we produce through successful development, exploration or acquisition activities, our proved reserves and production will decline over time. Thus, our future oil and natural gas reserves and production, and therefore our cash flow and income, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves.

The actual quantities of ~~producing properties requires an assessment~~and future net revenues from our proved reserves may be less than our estimates.

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The estimates of our proved reserves and the estimated future net revenues from our proved reserves included in this report are based upon various assumptions, including assumptions required by the SEC relating to natural gas, oil and NGL prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating natural gas, oil and NGL reserves is complex and involves significant decisions and assumptions associated with geological, geophysical, engineering and economic data for each well. Therefore, these estimates are subject to future revisions.

Actual future production, natural gas, oil and NGL prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable ~~reserves;~~

~~future~~natural gas, oil and NGL reserves most likely will vary from these estimates. Such variations may be significant and could materially affect the estimated quantities and present value of our proved reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development drilling, prevailing oil and natural gas prices and ~~their applicable differentials;~~other factors, many of which are beyond our control.

~~operating costs;~~As of December 31, 2020, approximately 41% of our total estimated proved reserves were PUDs and

~~potential environmental and other liabilities.~~

~~The accuracy of these assessments is inherently uncertain and we~~ may not be ~~able~~ultimately developed or produced. Recovery of PUDs requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve reports of our independent petroleum engineers assume that substantial capital expenditures are required to ~~identify attractive acquisition opportunities. In connection with these assessments, we perform a review of~~develop such reserves. You should be aware that the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspectionsestimated development costs may not ~~always be performed on every well,~~equal our actual costs, development may not occur as scheduled and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. Even if we do identify attractive acquisition opportunities, weresults may not be as estimated. Delays in the development of our reserves, further decreases in commodity prices or increases in costs to drill and develop such reserves will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. If we choose not to develop our PUDs, or if we are not otherwise able to ~~complete~~successfully develop them, we will be required to remove them from our reported proved reserves. In addition, under the ~~acquisition or do so on commercially acceptable terms.~~

Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, these acquisitionsSEC's reserve reporting rules, because PUDs generally may be in geographic regions in which we do not currently operate, which could result in unforeseen operating difficulties and difficulties in coordinating geographically dispersed operations, personnel and facilities. In addition,booked only if ~~we enter into new geographic markets,~~they relate to wells scheduled to be drilled within five years of the date of booking, we may be required to remove any PUDs that are not developed within this five-year time frame.

You should not assume that the present values included in this report represent the current market value of our estimated reserves. In accordance with SEC requirements, the estimates of our present values are based on prices and costs as of the date of the estimates. The price on the date of estimate is calculated as the average natural gas and oil price during the 12 months ending in the current reporting period, determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period. The December 31, 2020 present value is based on a $1.99 per MMBtu of gas price and a $39.54 per Bbl of oil price, before considering basis differential adjustments. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of an estimate.

Actual future net revenues from our oil and natural gas properties will also be affected by factors such as:

•actual prices we receive for oil and natural gas;

•the amount and timing of actual production;

•supply of and demand for oil and natural gas; and

•changes in governmental regulations or taxation.

The timing of both the production and the expenses from the development and production of oil and natural gas properties will affect both the timing of future net cash flows from our proved reserves and their present value. Any changes in demand for oil and natural gas, governmental regulations or taxation will also affect the future net cash flows from our production. In addition, the 10% discount factor that is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes is not necessarily the most appropriate discount factor. Interest rates in effect from time to time and the risks associated with our business or the oil and gas industry in general will affect the appropriateness of the 10% discount factor.

Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.

We have a substantial inventory of undeveloped properties. Development and exploratory drilling and production activities are subject to additional and unfamiliar legal and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Further,many risks, including the ~~success of any completed acquisition~~risk that commercially productive reservoirs will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions maynot be ~~larger and for purchase prices significantly higher than those paid for earlier acquisitions.~~

No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our earnings and growth. Our financial position and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods.

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~~Index to Financial Statements~~

Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties that we acquire or obtain protection from sellers against such liabilities.

discovered. Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not necessarily reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well or pipeline. We cannot necessarily observe structural and environmental problems, such as pipe corrosion, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the

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property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

We ~~may incur losses as a result of title defects in the properties in which we invest.~~

It is our practice in acquiring oil and natural gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition.

Prior to the drilling of an oil or natural gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in the assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.

Recent decisions by the Ohio Supreme Court interpreting the Ohio Dormant Mineral Act relating to preservation of mineral rights by surface owners could require certain curative efforts to vest title in a portion of our leasehold acreage, increase our leasehold expenses, subject us to payment of additional royalties and/or result in the loss of some of our leasehold acreage in Ohio.

On September 15, 2016, the Ohio Supreme Court issued a series of decisions relating to the Ohio Dormant Mineral Act, which we refer to as the ODMA. In the lead case, Corban v. Chesapeake Exploration L.L.C., the court concluded that the 1989 version of the ODMA did not transfer ownership of dormant mineral rights automatically, by operation of law. Instead, prior to 2006, surface owners were required to bring a quiet title action in order to establish abandonment of mineral rights. After June 30, 2006, (the effective date of the 2006 version of the ODMA), surface owners are required to follow the statutory notice and recording procedures enacted in 2006. We have assessed the impact of these recent Ohio Supreme Court decisions on our operations in Ohio where the majority of our acreage and our producing properties are located and have taken steps to mitigate any potential risks identified as a result of our assessment. However, the Ohio Supreme Court decisions could require certain curative efforts to vest title in a portion of our leasehold acreage, increase our leasehold expense, subject us to payment of additional royalties and/or result in the loss of some of our leasehold acreage in Ohio, any of which could have an adverse effect on our results of operations and financial condition.

~~If we are unable to complete capital projects in a timely manner, our business, financial condition, results of operations and cash flows could be materially and adversely affected.~~

Delays related to capital spending programs involving engineering, procurement and construction of facilities (including improvements and repairs to our existing facilities) could adversely affect our ability to achieve forecasted internal rates of return and operating results. Delays in making required changes or upgrades to our facilities could subject us to fines or penalties as well as affect our ability to supply certain products we produce. Such delays may arise as a result of unpredictable factors, many of which are beyond our control, including:

~~denial of or delay in receiving requisite regulatory approvals and/or permits;~~

~~unplanned increases in the cost of construction materials or labor;~~

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~~disruptions in transportation of components or construction materials;~~

~~adverse weather conditions, natural disasters or other events (such as equipment malfunctions, explosions, fires or spills) affecting our facilities, or those of vendors or suppliers;~~

~~shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;~~

~~market-related increases in a project's debt or equity financing costs; and~~

~~nonperformance by, or disputes with, vendors, suppliers, contractors or subcontractors.~~

~~Any one or more of these factors could have a significant impact on our ongoing capital projects.~~

~~Our Canadian oil sands projects are complex undertakings and may not be completed at our estimated cost or at all.~~

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 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. We reviewed our investment in Grizzly for impairment, resulting in an aggregate other than temporary impairment write down of $23.1 million for the year ended December 31, 2016. As of and during the years ended December 31, 2018 and 2017, commodity prices had increased as compared to 2016. We engaged an independent third party to perform a sensitivity analysis based on updated pricing as of December 31, 2018, and concluded that there were no impairment indicators that required further evaluation for impairment. If commodity prices decline, further impairment of our investment in Grizzly may result in the future. The Algar Lake and other pending and proposed projects are complex, subject to extensive governmental regulation and will require significant additional financing. There can be no assurance that the necessary governmental approvals will be granted or that such financing could be obtained on commercially reasonable terms or at all, or that if one or more of these projects are completed that they will be successful or that we realize a return on our investment.

~~The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies, oilfield services or personnel may restrict our operations.~~

The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and demand for and wage rates of qualified drilling rig crews also rise with increases in demand. In accordance with customary industry practice, we rely on independent third party service providers to provide most of the services necessary to drill new wells. If we are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer, and we may not be able to drill all of our acreage before our leases expire. Shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies, personnel, trucking services, tubulars, fracking and completion services and production equipment could delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations.

Oil and natural gas production operations, especially those using hydraulic fracturing, are substantially dependent on the availability of water. Restrictions on the ability to obtain water may impact our operations.

Water is an essential component of oil and natural gas production during the drilling, and in particular, hydraulic fracturing, process. Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our exploration and production operations, could adversely impact our operations.

~~We rely on a few key employees whose absence or loss could disrupt our operations resulting in a loss of revenues.~~

Many key responsibilities within our business have been assigned to a small number of employees. The loss of their services, particularly the loss of David M. Wood, our Chief Executive Officer and President, or our other senior management and technical personnel, could disrupt our operations and have a material adverse effect on our financial condition and results of

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~~Index to Financial Statements~~

~~operations.~~Our executives are not restricted from competing with us if they cease to be employed by us, except under certain limited circumstances prohibiting competition while making use of our trade secrets. We are party to an employment agreement with certain of our executive officers. As a practical matter, however, employment agreements may not assure the retention of our employees. Further, we do not maintain “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees.

~~Estimates of oil and natural gas reserves are uncertain and may vary substantially from actual production.~~

There are numerous uncertainties associated with estimating quantities of proved reserves and in projecting future rates of production and timing of expenditures. The reserve information herein represents estimates prepared by (i) Netherland, Sewell & Associates, Inc., or NSAI, with respect to our Utica Shale acreage and our WCBB and Hackberry fields at December 31, 2018, 2017 and 2016, our SCOOP acreage at December 31, 2018 and 2017 and our Niobrara field and our overriding royalty and non-operated interests at December 31, 2018 and (ii) our personnel with respect to our Niobrara field and our overriding royalty and non-operated interests at December 31, 2017, and 2016. Petroleum engineering is not an exact science. Information relating to our proved oil and natural gas reserves is based upon engineering estimates. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, future site restoration and abandonment costs, the assumed effects of regulations by governmental agencies and assumptions concerning future oil and natural gas prices, future operating costs, severance and excise taxes, capital expenditures and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of the future net cash flows expected therefrom prepared by different engineers or by the same engineers at different times may vary substantially. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.

Estimates of reserves as of year-end 2018, 2017 and 2016 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month period ended December 31, 2018, 2017 and 2016, respectively, in accordance with the revised guidelines of the SEC applicable to reserves estimates for such years. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties.

The present value of future net revenues from our proved reserves is not necessarily the same as the current market value of our estimated oil and natural gas reserves. We base the estimated discounted future net revenue from our proved reserves for 2018, 2017 and 2016 on an average price equal to the unweighted arithmetic average of prices received on a field-by-field basis on the first day of each month within the 12-month period ended December 31, 2018, 2017 and 2016, respectively, in accordance with the revised guidelines of the SEC applicable to reserves estimates for such years.

~~Actual future net revenues from our oil and natural gas properties will also be affected by factors such as:~~

~~actual prices we receive for oil and natural gas;~~

~~the amount and timing of actual production;~~

~~supply of and demand for oil and natural gas; and~~

~~changes in governmental regulations or taxation.~~

The timing of both our production and our incurrence of costs in connection with the development and production of oil and natural gas properties will affect the timing of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

~~SEC rules could limit our ability to book additional proved undeveloped reserves in the future.~~

SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit

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our ability to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill those wells within the required five-year timeframe, because they have become uneconomic or otherwise.

~~The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.~~

Approximately 55.4% of our total estimated proved reserves at December 31, 2018, were proved undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve reports of our independent petroleum engineers assume that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves, further decreases in commodity prices or increases in costs to drill and develop such reserves will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves.

There are numerous uncertainties in estimating quantities of bitumen reserves and resources in connection with our equity investment in Grizzly and the indicated level of reserves or recovery of bitumen may not be realized.

There are numerous uncertainties in estimating quantities of bitumen reserves and resources, and the indicated level of reserves or recovery of bitumen may not be realized. In general, estimates of economically recoverable bitumen reserves and the future net cash flow from such reserves are based upon a number of factors and assumptions made as of the date on which the reserve and resource estimates were determined, such as geological and engineering estimates which have uncertainties, the assumed effects of regulation by governmental agencies and estimates of future commodity prices and operating costs, all of which may vary considerably from actual results. All such estimates are, to some degree, uncertain and classifications of reserves are only attempts to define the degree of uncertainty involved. For these reasons, estimates of the economically recoverable bitumen, the classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially.

Estimates with respect to reserves and resources that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves, rather than upon actual production history. Estimates based on these methods generally are less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history may result in variations in the estimated reserves. Reserve and resource estimates may require revision based on actual production experience. Reserve and resources estimates are determined with reference to assumed oil prices and operating costs. Market price fluctuations of oil prices may render uneconomic the recovery of certain grades of bitumen. The actual gravity or quality of bitumen to be produced from Grizzly's lands cannot be determined at this time.

The marketability of our production is dependent upon compressors, gathering lines, transportation barges and other facilities, certain of which we do not control. When these facilities are unavailable, our operations can be interrupted and our revenues reduced.

The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of natural gas lines and transportation barges owned by third parties. In general, we do not control these transportation facilities and our access to them may be limited or denied. A significant disruption in the availability of these transportation facilities or our compression and other production facilities could adversely impact our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations. With respect to our Utica Shale acreage where we are focusing a portion of our exploration and development activity, historically there has been no or only limited infrastructure in this area and the commencement of production from our initial and subsequent wells on our Utica Shale acreage has been delayed due to challenges in obtaining rights-of-way and acquiring necessary state and federal permitting and the completion of facilities by our midstream service provider.

If production from our Utica Shale or SCOOP acreage decreases due to decreased developmental activities, production related difficulties or otherwise, we may fail to meet our firm commitment delivery obligations under our firm transportation contracts, which will result in fees and may have a material adverse effect on our operations.

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~~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. See Item 1. “Business-Transportation and Takeaway Capacity~~.” Under these firm transportation contracts, we are obligated to deliver minimum daily volumes or pay fees for any deficiencies in deliveries. If production from our Utica Shale or SCOOP acreage decreases due to decreased developmental activities, taking into consideration the current low commodity price environment, production related difficulties or otherwise, we may be unable to meet our obligations under the existing firm transportation contracts, resulting in fees, which may be significant and may have a material adverse effect on our operations.

~~Substantially all of our producing properties are located in Eastern Ohio, Oklahoma and Louisiana, making us vulnerable to risks associated with operating in these regions.~~

Our largest fields by production are located in Eastern Ohio, Oklahoma and approximately five miles off the coast of Louisiana in a shallow bay with water depths averaging eight to ten feet. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production in these geographic regions caused by weather conditions such as snow, ice, fog, rain, hurricanes or other natural disasters or lack of field infrastructure. Losses could occur for uninsured risks or in amounts in excess of any existing insurance coverage. We may not be able to obtain and maintain adequate insurance at rates we consider reasonable and it is possible that certain types of coverage may not be available.

~~Our identified drilling locations, which are part of our anticipated future drilling plans, are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.~~

We have identified over 1,000 drilling locations on our Ohio and Oklahoma properties assuming full development of all of our acreage. These drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, oil and natural gas prices, inclement weather, costs, drilling results and regulatory changes. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that may result in a total loss of investment and adversely affect our business, financial condition or results of operations.

Our drilling activities are subject to many risks. For example, we cannot assure you that new wells drilled by us will be productive or that we will recover all or any portion of our investment in such wells. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient oil or natural gas to return a profit at then realized prices after deducting drilling, operating and other costs. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or that it can be produced economically. The costs of exploration, exploitation and development activities are subject to numerous uncertainties beyond our control, and increases in those costs can adversely affect the economics of a project. Further, our drilling and producing operations may be curtailed, delayed, canceled or otherwise negatively impacted as a result of other factors, including:

~~unusual or unexpected geological formations;~~

~~loss of drilling fluid circulation;~~

~~title problems;~~

~~facility or equipment malfunctions;~~

~~unexpected operational events;~~

~~shortages or delivery delays of equipment and services;~~

~~compliance with environmental and other governmental requirements; and~~

~~adverse weather conditions.~~

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Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties.

~~Operating hazards and uninsured risks may result in substantial losses and could prevent us from realizing profits.~~

Our operations are subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, gas leaks, ruptures or discharges of toxic gases. In addition, our operations are subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. We may face liability for environmental damage caused by previous owners of properties purchased by us, which liabilities may or may not be covered by insurance. The occurrence of any of these events could result in substantial losses to us 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 investigations and penalties, suspension of operations and repairs required to resume operations.

In accordance with what we believe to be customary industry practice, we historically have maintained insurance against some, but not all, of our business risks. Our insurance may not be adequate to cover any losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its availability may be at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations or cash flow. 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. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.

~~Our operations may be exposed to significant delays, costs and liabilities as a result of environmental, health and safety requirements applicable to our business activities.~~

We may incur significant delays, costs and liabilities as a result of federal, state and local environmental, health and safety requirements applicable to our exploration, development and production activities. These laws and regulations may, among other things: (i) require us to obtain a variety of permits or other authorizations governing our air emissions, water discharges, waste disposal or other environmental impacts associated with drilling, producing and other operations; (ii) regulate the sourcing and disposal of water used in the drilling, fracturing and completion processes; (iii) limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier, seismically active areas and other protected areas; (iv) require remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; and/or (v) impose substantial liabilities and restrictions on our activities as a result of spills, pollution or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of oil or natural gas production. These laws and regulations are complex, change frequently and have tended to become increasingly stringent over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, the suspension or revocation of necessary permits, licenses and authorizations (which could cause us to cease operations), the requirement that additional pollution controls be installed and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations. Under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. In addition, the risk of accidental and/or unpermitted spills or releases from our operations could expose us to significant liabilities, penalties and other sanctions under applicable laws.

Moreover, public interest in the protection of the environment has tended to increase over time. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.

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~~Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.~~

We acquire significant amounts of unproved property in order to further our development efforts and expect to continue to undertake acquisitions in the future. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire unprovedunproven properties ~~and lease undeveloped acreage~~ that we believe will enhance our growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our initial investments. Additionally, ~~we cannot assure you~~there can be no assurance that ~~unproved property~~undeveloped properties acquired ~~by us or undeveloped acreage leased~~ by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive, or that we will recover all or any portion of our investment in such ~~unproved property~~undeveloped properties or wells.

Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient commercial quantities to cover the drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and many factors can adversely affect the economics of a well or property. Drilling and completion operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, title problems, equipment failures or accidents, shortages of midstream transportation, equipment or personnel, environmental issues, state or local bans or moratoriums on hydraulic fracturing and ~~for other reasons.~~produced water disposal, and a decline in commodity prices, among others. The profitability of wells, particularly in certain of the areas in which we operate, will be reduced or eliminated if commodity prices decline. In addition, wells that are profitable may not meet our internal return targets, which are dependent upon the current and ~~expected~~ future market prices for natural gas, oil and ~~natural gas, expected~~NGL, costs associated with producing natural gas, oil and ~~natural gas~~NGL and our ability to add reserves at an acceptable cost. Drilling results in our newer oil and liquids-rich shale plays may be more uncertain than in shale plays that are more developed and have longer established production histories, and we can provide no assurance that drilling and completion techniques that have proven to be successful in other shale formations to maximize recoveries will be ultimately successful when used in newly developed shale formations. All costs of development and exploratory drilling activities are capitalized under the full cost method, even if the activities do not result in commercially productive discoveries, which may result in a future impairment of our oil and natural gas properties if commodity prices decrease.

We rely to a significant extent on seismic data and other technologies in evaluating undeveloped properties and in conducting our exploration activities. The seismic data and other technologies we use do not allow us to know conclusively, prior to acquisition of undeveloped properties, or drilling a well, whether oil or natural gas is present or may be produced economically. If we incur significant expense in acquiring or developing properties that do not produce as expected or at profitable levels, it could have a material adverse effect on our results of operations and financial condition.

Part of our strategy involves drilling in existing or emerging shale plays using the latest available horizontal drilling and completion techniques; therefore, the results of our planned exploratory drilling in these plays are subject to risks associated with drilling and completion techniques and drilling results may not meet our expectations for reserves or production.

Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations and successfully cleaning out the well bore after completion of the final fracture stimulation stage. In addition, to the extent we engage in horizontal drilling, those activities may adversely affect our ability to successfully drill in one or more of our identified vertical drilling locations. Furthermore, certain of the ~~new techniques~~development activities we ~~are adopting,~~employ, such as ~~infill~~offset drilling and multi-well pad drilling, may cause irregularities or interruptions in production due to, in the case of ~~infill~~offset drilling, ~~offset~~adjacent wells being shut in and, in the case of multi-well pad drilling, the time required to drill and complete multiple wells before any such wells begin producing.

The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas often have limited or no production history and consequently we are less able to predict future drilling results in these ~~areas.~~areas, such as our SCOOP play in Oklahoma. The area was historically developed by vertical wells drilled through multiple stacked reservoirs and recent development has focused on the Woodford formation; however, development in the Sycamore and Springer formations has been limited. As emerging formations, our drilling results in this area are more uncertain than drilling results in areas that are more developed and have been producing for a longer period of time. Since limited production history from horizontal wells in the SCOOP Sycamore and Springer formations exists over our acreage position, it is difficult to predict our

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future drilling results.

Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, ~~and/~~or declines in natural gas and oil prices, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future.

WeOur undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.

Leases on oil and natural gas properties typically have ~~been~~a term of three to five years, after which they expire unless, prior to expiration, a well is drilled and production of hydrocarbons in paying quantities is established. In addition, many of our oil and natural gas leases require us to drill wells that are commercially productive, and if we are unsuccessful in drilling such wells, we could lose our rights under such leases. Although 74% of our Utica acreage is held by existing production, the remaining acreage is subject to expiration. Of the remaining 26% of our Utica acreage not held by production, 24% will be subject to expiration in 2021, 29% in 2022, 30% in 2023 and 17% thereafter, although our Utica leases generally grant us the right to extend these leases for an ~~early entrant into~~additional five-year period. Although 99% of our SCOOP acreage is held by existing production, the remaining acreage is subject to expiration. Of the remaining 1% of our SCOOP ~~play~~acreage not held by production, 78% will be subject to expiration in ~~Oklahoma. As~~2021, 12% in 2022, 5% in 2023 and 5% thereafter. Although we seek to actively manage our undeveloped properties, our drilling plans for these areas are subject to change based upon various factors, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. Low commodity prices may cause us to delay our drilling plans and, as a result, lose our ~~drilling results in this area~~right to develop the related properties. The cost to renew expiring leases may ~~vary,~~increase significantly, and ~~the value~~we may not be able to renew such leases on commercially reasonable terms or at all. If we are unable to fund renewals of expiring leases, we could lose portions of our ~~undeveloped~~ acreage ~~will decline if~~and our actual drilling ~~results~~activities may differ materially from our current expectations, which could adversely affect our business.

Oil and natural gas operations are ~~unsuccessful.~~uncertain and involve substantial costs and risks. Operating hazards and uninsured risks may result in substantial losses and could prevent us from realizing profits.

We have been an early entrant into the SCOOP play in Oklahoma. On February 17, 2017, we completed our SCOOP acquisition, which included approximately 46,000 net surface acres with multiple producing zones,Our oil and natural gas operating activities are subject to numerous costs and risks, including the ~~Woodford~~risk that we will not encounter commercially productive oil or gas reservoirs. Drilling for oil, natural gas and ~~Springer formations in~~NGL can be unprofitable, not only from dry holes, but from productive wells that do not return a profit because of insufficient revenue from production or high costs. Substantial costs are required to locate, acquire and develop oil and gas properties, and we are often uncertain as to the ~~SCOOP resource play, in Grady, Stephens~~amount and Garvin Counties, Oklahoma. The area was historically developed by vertical wells drilled through multiple stacked reservoirs; however, the current play represents the transition to mainly horizontal development. As a developing play, our drilling results in this area are more uncertain than

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drilling results in areas that are more developed and have been producing for a longer period of time. Since limited production history from horizontal wells in the SCOOP exists and since we have limited experience drilling in this play, it is difficult to predict our future drilling results.those costs. Our cost of drilling, completing, equipping and operating wells is often uncertain before drilling commences. Declines in ~~this area~~commodity prices and overruns in budgeted expenditures are common risks that can make a particular project uneconomic or less economic than forecasted. While both exploratory and developmental drilling activities involve these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons. For the 11% of our daily production volumes from properties which we did not serve as operator as of December 31, 2020, we are dependent on the operator for operational and regulatory compliance. In addition, our oil and gas properties can become damaged, our operations may be ~~higher than initially expected,~~curtailed, delayed or canceled and the ~~value~~costs of such operations may increase as a result of a variety of factors, including, but not limited to:

•unexpected drilling conditions, pressure conditions or irregularities in reservoir formations;

•loss of drilling fluid circulation;

•equipment failures or accidents;

•fires, explosions, blowouts, cratering or loss of well control, as well as the mishandling or underground migration of fluids and chemicals;

•risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives;

•adverse weather conditions and natural disasters, such as tornadoes, earthquakes, hurricanes and extreme temperatures;

•issues with title or in receiving governmental permits or approvals;

•restricted takeaway capacity for our ~~undeveloped acreage~~production, including due to inadequate midstream infrastructure or constrained

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downstream markets;

•environmental hazards or liabilities, including liabilities for environmental damage caused by previous owners of properties purchased by us;

•restrictions in access to, or disposal of, water used or produced in drilling and completion operations;

•shortages or delays in the ~~SCOOP may decline if drilling results are unsuccessful. We cannot assure you that unproved property acquired,~~availability of services or ~~undeveloped acreage leased, by us~~delivery of equipment; and

•unexpected or unforeseen changes in ~~the SCOOP~~regulatory policy, and political or ~~other emerging plays will be profitably developed, that wells drilled by us~~public opinions.

The occurrence of one or more of these factors could result in ~~prospects that we pursue will be productive~~a partial or ~~that we will recover all or any portion~~total loss of our investment in ~~such unproved~~a particular property, ~~or wells.~~as well as significant liabilities.

~~A key part of our strategy involves using~~While we may maintain insurance against some, but not all, of the ~~latest available horizontal drilling and completion techniques, which involve~~ risks ~~and uncertainties in their application.~~

~~Our operations involve utilizing some of the latest drilling and completion techniques as developed by us~~described above, our insurance may not be adequate to cover casualty losses or liabilities, and our ~~service providers. Risks~~insurance does not cover penalties or fines that ~~we face while drilling include, but are not limited to, the following:~~

•~~effectively controlling the level of pressure flowing from particular wells;~~

•~~landing our wellbore in the desired drilling zone;~~

•~~staying in the desired drilling zone while drilling horizontally through the formation;~~

•~~running our casing the entire length of the wellbore; and~~

•~~being able to run tools~~may be assessed by a governmental authority. For certain risks, such as political risk, business interruption, war, terrorism and ~~other equipment consistently through the horizontal wellbore.~~

~~Risks that~~piracy, we ~~face while completing our wells include, but are not limited to, the following:~~

•~~the ability to fracture stimulate the planned number of stages;~~

•~~the ability to run tools the entire length of the wellbore during completion operations; and~~

•~~the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage~~

The results of our drilling in new or emerging formations (including the SCOOP) are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no ~~production history and, consequently,~~insurance coverage. Also, in the future we ~~are more limited in assessing future drilling results in these areas. If our drilling results are less than anticipated, the return on our investment for a particular project~~ may not be ~~as attractive as~~able to obtain insurance at premium levels that justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we ~~anticipated~~are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and weon our financial condition, results of operations or cash flow. 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. A loss not fully covered by insurance could ~~incur~~have a material ~~write-downs~~adverse effect on our financial position, results of ~~unevaluated properties~~operations and ~~the value of our undeveloped acreage could decline in the future.~~cash flows.

We are not the operator of all of our oil and natural gas properties and therefore are not in a position to control the timing of development efforts, the associated costs or the rate of production of the reserves on such properties.

We are not the operator of all of the properties in which we have an interest, and have limited ability to exercise influence over the operations of such non-operated properties or their associated costs. Dependence on the operator and other working interest owners for these projects, and limited ability to influence operations and associated costs, could prevent the realization of targeted returns on capital in drilling or acquisition activities. The success and timing of development and exploration activities on properties operated by others will depend upon a number of factors that will be largely outside of our control, including:

•the timing and amount of capital expenditures;

•the availability of suitable drilling equipment, production and transportation infrastructure and qualified operating personnel;

•the operator's expertise and financial resources;

•approval of other participants in drilling wells;

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•selection of technology; and

•the rate of production of the reserves.

In addition, when we are not the majority owner or operator of a particular oil or natural gas project, if we are not willing or able to fund our capital expenditures relating to such projects when required by the majority owner or operator, our interests in these projects may be reduced or forfeited.

A significant portion of our net leasehold acreage is undeveloped, and that acreage may not ultimately be developed or become commercially productive, which could cause us to lose rights under our leases as well as have a material adverse effect on our oilOil and natural gas ~~reserves~~production operations, especially those using hydraulic fracturing, are substantially dependent on the availability of water. Our ability to produce natural gas, oil and ~~future production~~NGL economically and ~~therefore,~~in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our ~~future cash flow~~operations or are unable to dispose of or recycle the water we use economically and ~~income.~~in an environmentally safe manner.

~~A significant portion of our net leasehold acreage~~Water is ~~undeveloped, or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities~~an essential component of oil and natural gas ~~regardless~~production during the drilling, and in particular, hydraulic fracturing, process. Our inability to locate sufficient amounts of ~~whether~~water, or dispose of or recycle water used in our exploration and production operations, could adversely impact our operations. For water sourcing, we first seek to use non-potable water supplies for our operational needs. In certain areas, there may be insufficient local aquifer capacity to provide a source of water for drilling activities. Water must then be obtained from other sources and transported to the drilling site. An inability to secure sufficient amounts of water or to dispose of or recycle the water used in our operations could adversely impact our operations in certain areas. The imposition of new environmental regulations could further restrict our ability to conduct

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operations such ~~acreage contains proved reserves. In addition, many~~as hydraulic fracturing by restricting the disposal of things such as produced water and drilling fluids.

Substantially all of our producing properties are located in Eastern Ohio and Oklahoma, making us vulnerable to risks associated with operating in these regions.

Our largest fields by production are located in Eastern Ohio and Oklahoma. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production in these geographic regions caused by weather conditions such as snow, ice, fog, rain, hurricanes, tornados or other natural disasters or lack of field infrastructure. Losses could occur for uninsured risks or in amounts in excess of any existing insurance coverage. We may not be able to obtain and maintain adequate insurance at rates we consider reasonable and it is possible that certain types of coverage may not be available.

The loss of one or more of the purchasers of our production could adversely affect our business, results of operations, financial condition and cash flows.

The largest purchaser of our oil and natural gas leases require us to drill wells that are commercially productive, and if we are unsuccessful in drilling such wells, we could lose our rights under such leases. Our future oil and natural gas reserves and production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage.

~~Our undeveloped acreage must be drilled before lease expiration to hold~~during the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.

Unless production is established within the spacing units covering the undeveloped acres on which some of the locations are identified, the leases for such acreage will expire. Approximately 18% of our Utica Shale undeveloped acreage that is subject to expiration will be subject to expiration in 2019, with 16% of such acreage expiring in 2020, 15% in 2021 and 51% thereafter, although our Utica Shale leases generally grant us the right to extend these leases for an additional five-year period. As ofyear ended December 31, ~~2018, leases representing 88%, 8% and 4% of our SCOOP undeveloped acreage that is subject to expiration are scheduled to expire in 2019,~~ 2020 ~~and 2021, respectively. As of December 31, 2018, leases representing 66%~~accounted for approximately 12% of our total ~~Niobrara Formation undeveloped acreage are scheduled to expire in 2019. The cost to renew expiring leases may increase significantly,~~natural gas, oil and ~~we may not be able to renew such leases on commercially reasonable terms~~NGL revenues. If this purchaser or ~~at all. If we~~one or more other significant purchasers, are unable to ~~fund renewals~~satisfy its contractual obligations, we may be unable to sell such production to other customers on terms we consider acceptable. Further, the inability of ~~expiring leases, we could lose portions~~one or more of our ~~acreage and our actual drilling activities may differ materially from our current expectations, which~~customers to pay amounts owed to us could adversely affect ~~our business.~~

~~Conservation measures and technological advances could reduce demand for oil and natural gas.~~

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

~~Our operations are subject to various governmental laws and regulations which require compliance that can be burdensome and expensive and could expose us to significant liabilities.~~The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies, oilfield services or personnel may restrict our operations.

~~Our~~The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and demand for and wage rates of qualified drilling rig crews also rise with increases in demand. In accordance with customary industry practice, we rely on independent third party service providers to provide most of the services necessary to drill new wells. If we are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations ~~are~~could suffer, and we may not be able to drill all of our acreage before our leases expire. Shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies, personnel, trucking services, tubulars, fracking and completion services and production equipment could delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations.

Our operations may be adversely affected by pipeline, trucking and gathering system capacity constraints and may be subject to ~~various federal,~~interruptions that could adversely affect our cash flow.

The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of natural gas lines and transportation barges owned by third parties. In general, we do not control these transportation facilities and our access to them may be limited or denied. In certain resource plays, the capacity of gathering and transportation systems is insufficient to accommodate potential production from existing and new wells. A significant disruption in the availability of these transportation facilities or our compression and other production facilities could adversely impact our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations.

With respect to our Utica acreage where we are focusing a portion of our exploration and development activity, historically there has been no or only limited infrastructure in this area and the commencement of production from our initial and subsequent wells on our Utica acreage has been delayed due to challenges in obtaining rights-of-way and acquiring necessary state and ~~local governmental regulations that~~federal permitting and the completion of facilities by our midstream service provider. Capital constraints could limit the construction of new pipelines and gathering systems and the providing or expansion of trucking services by third parties in the Utica and the other areas in which we operate. Until this new capacity is available, we may experience delays in producing and selling our natural gas, oil and NGL. In such event, we might have to shut in our wells awaiting a pipeline connection or capacity or sell natural gas, oil or NGL production at significantly lower prices than those quoted on NYMEX or than we currently project, which would adversely affect our results of operations.

A portion of our natural gas, oil and NGL production in any region may be ~~changed~~interrupted, or shut in, from time to time for numerous reasons, including weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could materially adversely affect our cash flow.

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Our forecasted production is less than our firm transportation commitment levels under our firm transportation contracts due to decreased developmental activities, which will result in excess firm transportation costs and may have a material adverse effect on our operations.

As of December 31, 2020, we had entered into firm transportation contracts to deliver approximately 1,399,000 and 1,467,000 MMBtu per day for 2021 and 2022, respectively. Under these firm transportation contracts, we are obligated to deliver minimum daily volumes or pay fees for any deficiencies in deliveries. As a result of the reduced production from our Utica or SCOOP acreage due to decreased developmental activities, taking into consideration the current low commodity price environment, we expect that we will be unable to meet our obligations under the existing firm transportation contracts, resulting in fees, which may be significant and may have a material adverse effect on our operations.

The outbreak of the novel coronavirus, or COVID-19, has affected and may materially adversely affect, and any future outbreak of any other highly infectious or contagious diseases may materially adversely affect, our operations, financial performance and condition, operating results and cash flows.

The recent outbreak of COVID-19 has affected, and may materially adversely affect, our business and financial and operating results. The severity, magnitude and duration of the current COVID-19 outbreak is uncertain, rapidly changing and hard to predict. In 2020, the outbreak has significantly impacted economic activity and ~~political conditions. Matters subject~~markets around the world, and COVID-19 or another similar outbreak could negatively impact our business in numerous ways, including, but not limited to, ~~regulation include discharge permits~~the following:

•our revenue may be reduced if the outbreak results in an economic downturn or recession, as many experts predict, to the extent it leads to a prolonged decrease in the demand for ~~drilling~~natural gas and, to a lesser extent, NGL and oil;

•our operations ~~drilling bonds, reports concerning~~may be disrupted or impaired, thus lowering our production level, if a significant portion of our employees or contractors are unable to work due to illness or if our field operations are suspended or temporarily shut-down or restricted due to control measures designed to contain the ~~spacing~~outbreak;

•the operations of ~~wells, unitization~~our midstream service providers, on whom we rely for the transmission, gathering and ~~pooling~~processing of ~~properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate~~a significant portion of ~~flow of~~our produced natural gas, oil and NGL, may be disrupted or suspended in response to containing the outbreak, and/or the difficult economic environment may lead to the bankruptcy or closing of the facilities and infrastructure of our midstream service providers, which may result in substantial discounts in the prices we receive for our produced natural gas, ~~wells below actual production capacity to conserve supplies of~~ oil and ~~gas.~~ NGL or result in the shut-in of producing wells or the delay or discontinuance of development plans for our properties; and

•the disruption and instability in the financial markets and the uncertainty in the general business environment may affect our ability to execute on our business strategy, including our focus on reducing our leverage profile. If we are not able to successfully execute our plan to reduce our leverage profile, our high level of indebtedness could make it more difficult for us to satisfy our obligations with respect to our indebtedness, and any failure to comply with the obligations under any of our debt instruments, including their restrictive covenants, could result in a default under our revolving credit facility or the indentures governing our senior notes. Additionally, our credit ratings may be lowered, we may reduce or delay our planned capital expenditures or investments, and we may revise or delay our strategic plans.

We expect that the principal areas of operational risk for us are availability of service providers and supply chain disruption. Active development operations, including drilling and fracking operations, represent the greatest risk for transmission given the number of personnel and contractors on site. While we believe that we are following best practices under COVID-19 guidance, the potential for transmission still exists. In certain instances, it may be necessary or determined advisable for us to delay development operations.

In addition, the COVID-19 pandemic has increased volatility and caused negative pressure in the capital and credit markets. As a result, we may experience difficulty accessing the capital or financing needed to fund our exploration and production ~~handling, storage, transportation, remediation, emission~~operations, which have substantial capital requirements, or refinance our upcoming maturities on satisfactory terms or at all. We typically fund our capital expenditures with existing cash and ~~disposal~~cash generated by operations (which is subject to a number of variables, including many beyond our control) and, to the extent our capital expenditures exceed our cash resources, from borrowings under our revolving credit facility and other external sources of capital. If our cash flows from operations or the borrowing capacity under our revolving credit facility are insufficient to fund our capital expenditures and we are unable to obtain the capital necessary for our planned capital budget or our operations, we could be required to curtail our operations and the development of our properties, which in turn could lead to a decline in our reserves and production, and could adversely affect our business, results of operations and financial position.

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To the extent the COVID-19 pandemic adversely affects our business and financial results, it may also have the effect of heightening many of the other risks set forth in Item 1A., “Risk Factors” in our Annual Report on Form 10-K, such as those relating to our financial performance and debt obligations. The rapid development and fluidity of this situation precludes any prediction as to the ultimate adverse impact of COVID-19 on our business, which will depend on numerous evolving factors and future developments that we are not able to predict, including the length of time that the pandemic continues, its effect on the demand for natural gas, NGL and oil, the response of the overall economy and the financial markets as well as the effect of governmental actions taken in response to the pandemic.

A deterioration in general economic, business or industry conditions would have a material adverse effect on our results of operations, liquidity and financial condition.

Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit and the European, Asian and the United States financial markets have contributed to economic volatility and diminished expectations for the global economy. Historically, concerns about global economic growth have had a significant impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and materially adversely impact our results of operations, liquidity and financial condition.

Terrorist activities could materially and adversely affect our business and results of operations.

Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign attacks, as well as military or other actions taken in response to these acts, could cause instability in the global financial and energy markets. Continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy in unpredictable ways, including the disruption of energy supplies and markets, increased volatility in commodity prices, or the possibility that the infrastructure on which we rely could be a direct target or an indirect casualty of an act of terrorism, and, in turn, could materially and adversely affect our business and results of operations. These factors, combined with volatility in commodity prices, business and consumer confidence and unemployment rates, have in the past precipitated, and may in the future precipitate, an economic slowdown.

Cyber-attacks targeting systems and infrastructure used by the oil and gas industry and related regulations may adversely impact our operations and, if we are unable to obtain and maintain adequate protection for our data, our business may be harmed.

Our business has become increasingly dependent on digital technologies to conduct certain exploration, development and production activities. We depend on digital technology to estimate quantities of oil, ~~and~~ natural gas ~~by-products thereof~~and NGL reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our customers, employees and third-party partners. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Our technologies, systems, networks, and those of our vendors, suppliers and other ~~substances~~business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized access to our seismic data, reserves information, customer or employee data or other proprietary or commercially sensitive information could lead to data corruption, communication interruption, or other disruptions in our exploration or production operations or planned business transactions, any of which could have a material adverse impact on our results of operations. If our information technology systems cease to function properly or our cybersecurity is breached, we could suffer disruptions to our normal operations, which may include drilling, completion, production and ~~materials produced~~corporate functions. A cyber-attack involving our information systems and related infrastructure, or ~~used~~that of our business associates, could result in ~~connection with oil~~supply chain disruptions that delay or prevent the transportation and ~~natural gas operations are subject~~marketing of our production, non-compliance leading to ~~regulation under federal, state~~regulatory fines or penalties, loss or disclosure of, or damage to, our or any of our customer’s, supplier’s or royalty owners’ data or confidential information that could harm our business by damaging our reputation, subjecting us to potential financial or legal liability, and ~~local~~requiring us to incur significant costs, including costs to repair or restore our systems and data or to take other remedial steps.

In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems and insurance coverage for protecting against cyber security risks may not be sufficient. As cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cyber-attacks. In addition, new laws and regulations ~~including those relating to protection of human health~~governing data privacy and the ~~environment. Failure~~unauthorized disclosure of confidential information pose increasingly complex compliance challenges and potentially elevate costs, and any failure to comply with these laws and regulations could result in significant penalties and legal liability.

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Legal and Regulatory Risks

The ultimate outcome of pending legal and governmental proceedings is uncertain, and there are significant costs associated with these matters.

We are defending against claims by royalty owners alleging, among other things, that we underpaid royalty owners. The resolution of disputes regarding past payments could cause our future obligations to royalty owners to increase and would negatively impact our future results of operations.

The outcome of any pending or future litigation or governmental regulatory matter is uncertain and may adversely affect our results of operations. In addition, we have incurred substantial legal expenses in the past three years, and such expenses may continue to be significant in the future. Further, attention to these matters by members of our senior management has been required, reducing the time they have available to devote to managing our business.

Decisions by the Ohio Supreme Court interpreting the Ohio Dormant Mineral Act relating to preservation of mineral rights by surface owners could require certain curative efforts to vest title in a portion of our leasehold acreage, increase our leasehold expenses, subject us to payment of additional royalties or result in the ~~assessment~~loss of ~~sanctions,~~some of our leasehold acreage in Ohio.

On September 15, 2016, the Ohio Supreme Court issued a series of decisions relating to the Ohio Dormant Mineral Act, which we refer to as the ODMA. In the lead case, Corban v. Chesapeake Exploration L.L.C., the court concluded that the 1989 version of the ODMA did not transfer ownership of dormant mineral rights automatically, by operation of law. Instead, prior to 2006, surface owners were required to bring a quiet title action to establish abandonment of mineral rights. After June 30, 2006, (the effective date of the 2006 version of the ODMA), surface owners are required to follow the statutory notice and recording procedures enacted in 2006. We have assessed the impact of these recent Ohio Supreme Court decisions on our operations in Ohio where the majority of our acreage and our producing properties are located and have taken steps to mitigate any potential risks identified as a result of our assessment. However, the Ohio Supreme Court decisions could require certain curative efforts to vest title in a portion of our leasehold acreage, increase our leasehold expense, subject us to payment of additional royalties or result in the loss of some of our leasehold acreage in Ohio, any of which could have an adverse effect on our results of operations and financial condition.

We are subject to extensive governmental regulation and ongoing regulatory changes, which could adversely impact our business.

Our operations are subject to extensive federal, state, tribal, local and other laws, rules and regulations, including ~~administrative, civil or criminal penalties, permit revocations,~~with respect to environmental matters, worker health and safety, wildlife conservation, the gathering and transportation of oil, gas and NGL, conservation policies, reporting obligations, royalty payments, unclaimed property and the imposition of taxes. Such regulations include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling, completion and well operations. If permits are not issued, or if unfavorable restrictions or conditions are imposed on our drilling or completion activities, we may not be able to conduct our operations as planned. For example, 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 ~~pollution controls and injunctions limiting~~restrictions on drilling, limitations on the availability of leases, or ~~prohibiting some or all of~~restrictions on the ability to obtain required permits, it could have a material adverse impact on our operations. ~~Moreover,~~In addition, we may be required to make large, sometimes unexpected, expenditures to comply with applicable governmental laws, rules, regulations, permits or orders.

In addition, changes in public policy have affected, and in the future could further affect, our operations. Regulatory changes could, among other things, restrict production levels, impose price controls, alter environmental protection requirements and increase taxes, royalties and other amounts payable to the government. Our operating and compliance costs could increase further if existing laws and regulations are revised or reinterpreted or if new laws and regulations become applicable to our operations. We do not expect that any of these laws and regulations ~~impose increasingly strict requirements for water~~will affect our operations materially differently than they would affect other companies with similar operations, size and ~~air pollution control and solid waste management, which trend may continue. Significant expenditures may be required~~financial strength. Although we are unable to ~~comply with governmental~~predict changes to existing laws and regulations, ~~applicable~~such changes could significantly impact our profitability, financial condition and liquidity. As is discussed below this is particularly true of changes related to ~~us. See Item 1.~~ ~~“Business-~~

pipeline safety, seismic activity, hydraulic fracturing, climate change and endangered species designations.

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~~Regulation-Environmental Matters~~Pipeline Safety. The pipeline assets owned by our midstream service providers are subject to stringent and ~~Regulation”~~ complex regulations related to pipeline safety and ~~Item 1.~~ ~~“Business-Regulation-Other Regulation~~integrity management. The Pipeline and Hazardous Materials Safety Administration (PHMSA) has established a series of rules that require pipeline operators to develop and implement integrity management programs for gas, NGL and condensate transmission pipelines as well as certain low stress pipelines and gathering lines transporting hazardous liquids, such as oil, that, in the ~~Oil~~event of a failure, could affect “high consequence areas.” Recent PHMSA ruleshave also extended certain requirements for integrity assessments and ~~Natural Gas Industry”~~leak detections beyond high consequence areas. Further, legislation funding PHMSA through 2023 requires the agency to engage in additional rulemaking to amend the integrity management program, emergency response plan, operation and maintenance manual, and pressure control recordkeeping requirements for ~~a description~~gas distribution operators; to create new leak detection and repair program obligations; and to set new minimum federal safety standards for onshore gas gathering lines.At this time, we cannot predict the cost of ~~certain laws~~these requirements or other potential new or amended regulations, but they could be significant, and ~~regulations that affect us.~~

~~Federal and state legislative and regulatory initiatives relating to hydraulic fracturing~~any such costs incurred by our midstream service providers could result in increased ~~costs~~midstream gathering and ~~additional~~processing expenses for us. Moreover, violations of pipeline safety regulations by our midstream service providers could result in the imposition of significant penalties which may impact the cost or availability of pipeline capacity necessary for our operations.

Seismic Activity. Earthquakes in some of our operating ~~restrictions or delays.~~

~~Hydraulic fracturing is an important common practice~~areas and elsewhere have prompted concerns about seismic activity and possible relationships with the energy industry. For example, the OCC issued guidance to operators in the SCOOP and STACK areas for management of certain seismic activity that ~~is used~~may be related to ~~stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. We use~~ hydraulic fracturing ~~extensively in connection with the development and production of certain of our oil and natural gas properties. The process involves the injection of~~or water sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. 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. The hydraulic fracturing process is typically regulated by state oil and natural 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 permittingdisposal activities. Legislative and regulatory ~~control~~initiatives intended to address these concerns may result in additional levels of ~~hydraulic fracturing,~~regulation or other requirements that could lead to operational delays, increase our operating 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.

compliance costs or otherwise adversely affect our operations. In addition, ~~several~~we could be subject to third-party lawsuits seeking damages or other remedies as a result of alleged induced seismic activity in our areas of operation.

Hydraulic Fracturing. Several states ~~and local jurisdictions in which we operate or hold oil and natural gas interests~~ have adopted or are considering adopting regulations that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing operations. Three states (New York, Maryland and Vermont) have banned the use of high-volume hydraulic fracturing. In addition to state laws, some local municipalities have adopted or are considering adopting land use restrictions, such as city ordinances, that may restrict or prohibit the performance of well drilling in general or hydraulic fracturing in particular. There have also been certain ~~circumstances, impose more stringent operating standards and/~~governmental reviews that focus on deep shale and other formation completion and production practices, including hydraulic fracturing. Governments may continue to study hydraulic fracturing. We cannot predict the outcome of future studies, but based on the results of these studies to date, federal and state legislatures and agencies may seek to further regulate or ~~require the disclosure of the composition of~~even ban hydraulic fracturing ~~fluids. For a more detailed discussion~~activities. In addition, if existing laws and regulations with regard to hydraulic fracturing are revised or reinterpreted or if new laws and regulations become applicable to our operations through judicial or administrative actions, our business, financial condition, results of operations and cash flows could be adversely affected. A decision is pending.

We cannot predict whether additional federal, state ~~and~~or local ~~laws and initiatives concerning hydraulic fracturing, see Item 1. “Business-Regulation-Regulation of Hydraulic Fracturing” above.~~

~~If new~~ laws or regulations ~~are adopted that significantly restrict~~applicable to hydraulic fracturing will be enacted in the future and, if so, what actions any such laws or regulations would require or prohibit. If additional levels of regulation or permitting requirements were imposed on hydraulic fracturing operations, our business and operations could be subject to delays, increased operating and compliance costs and potential bans. Additional regulation could also lead to greater opposition to hydraulic fracturing, including litigation.

Climate Change. Continuing political and social attention to the issue of climate change has resulted in legislative, regulatory and other initiatives to reduce greenhouse gas emissions, such as carbon dioxide and methane. Policy makers at both the U.S. federal and state levels have introduced legislation and proposed new regulations designed to quantify and limit the emission of greenhouse gases through inventories, limitations or taxes on greenhouse gas emissions. Several states where we operate have imposed venting and flaring limitations designed to reduce methane emissions from oil and gas exploration and production activities. Legislative and state initiatives to date have generally focused on the development of cap and trade or carbon tax programs. Renewable energy standards (also referred to as renewable portfolio standards) require electric utilities to provide a specified minimum percentage of electricity from eligible renewable resources, with potential increases to the required percentage over time. The development of a federal renewable energy standard, or the development of additional or more stringent renewable energy standards at the state level could reduce the demand for oil and gas, thereby adversely impacting our earnings, cash flows and financial position. Cap and trade programs offer greenhouse gas emission allowances that are gradually reduced over time. A cap and trade program or expanded use of cap and trade programs at the state level could impose direct costs on us through the purchase of allowances and could impose indirect costs by incentivizing consumers to shift away from fossil fuels. In addition, federal or state carbon taxes could directly increase our costs of operation and similarly incentivize consumers to shift away from fossil fuels.

In addition, activists concerned about the potential effects of climate change have directed their attention at sources of

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funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult ~~or costly~~to secure funding for usexploration and production activities. Members of the investment community have also begun to screen companies such as ours for sustainability performance, including practices related to greenhouse gases and climate change, before investing in our common units. Any efforts to improve our sustainability practices in response to these pressures may increase our costs, and we may be forced to implement technologies that are not economically viable in order to improve our sustainability performance and to meet the specific requirements to perform ~~fracturing to stimulate production from tight formations as well as make it easier~~services for ~~third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process~~certain customers.

These various legislative, regulatory and other activities addressing greenhouse gas emissions could adversely affect ~~groundwater. In addition, if hydraulic fracturing is further regulated at the federal, state~~our business, including by imposing reporting obligations on, or ~~local level,~~limiting emissions of greenhouse gases from, our ~~fracturing activities~~equipment and operations, which 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 reduce the volumes of oil and natural gas that we can recover economically and causerequire us to incur ~~substantial compliance costs. Reduced production and/or compliance or~~costs to reduce emissions of greenhouse gases associated with our operations. Limitations on greenhouse gas emissions could also adversely affect demand for oil and gas, which could lower the ~~consequences~~value of ~~any failure to comply by us could~~our reserves and have a material adverse effect on our profitability, financial condition and ~~results~~liquidity. Furthermore, increasing attention to climate change risks has resulted in increased likelihood of ~~operations.~~governmental investigations and private litigation, which could increase our costs or otherwise adversely affect our business.

Endangered Species. The Endangered Species Act (ESA) prohibits the taking of endangered or threatened species or their habitats. While some of our assets and lease acreage may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in material compliance with the ESA. However, the designation of previously unidentified endangered or threatened species in areas where we intend to conduct construction activity or the imposition of seasonal restrictions on our construction or operational activities could materially limit or delay our plans.

Legislation or regulatory initiatives intended to address seismic activity could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could have a material adverse effect on our business.

State and federal regulatory agencies have recently focused on a possible connection between hydraulic fracturing related activities, particularly the underground injection of wastewater into disposal wells, and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. In addition, a number of lawsuits have been filed in some states, including in Oklahoma, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements regarding the permitting of produced water disposal wells or otherwise to assess the relationship between seismicity and the use of such wells.

We dispose of large volumes of produced water gathered from our drilling and production operations in our Louisiana fields by injecting it into wells pursuant to permits issued to us by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities.

In our Utica and SCOOP operations, we ~~attempt~~make an effort to reuse/recycle all produced water from production and completion activities through our fracture stimulation operations when active. While our objective is to recycle or share 100% of all produced water, we do inject water into ~~third party~~third-party commercially operated disposal wells in line with all state and federal mandated practices and cease

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produced water recycle whenever fracture stimulation operations are ~~idle.~~idle once sharing opportunities with other operators have been exhausted. In the state of Ohio, all water used during drilling operations is disposed of through injection into ~~third party~~third-party salt water disposal wells regulated by applicable state agencies.

In our SCOOP operations, state regulations allow for the storage of produced water in permitted, above ground, lined and monitored impoundments. These storage impoundments allow the recycle of approximately two-thirds of our produced water from all production and completion operations and approximately 80% of water used in the drilling phase of our operations. The limited water disposed of during drilling operations is injected into state regulated commercial disposal wells.

The adoption and implementation of any new laws or regulations that restrict our ability to use hydraulic fracturing or dispose of produced water gathered from our drilling and production activities by own disposal wells, could have a material adverse effect on our business, financial condition and results of operations.

~~Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of the areas where we operate.~~

Oil and natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife species or their habitat. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. Permanent restrictions imposed to protect threatened or endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce our reserves.

The adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. The U.S. Congress adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173), or Dodd-Frank Act, which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The legislation was signed into law by the President on July 21, 2010. In its rulemaking under the legislation, the Commodities Futures Trading Commission, or CFTC, has issued a final rule on position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents (with exemptions for certain bona fide hedging transactions). The CFTC's final rule was set aside by the U.S. District Court for the District of Columbia on September 28, 2012 and remanded to the CFTC to resolve ambiguity as to whether statutory requirements for such limits to be determined necessary and appropriate were satisfied. As a result, the rule has not yet taken effect, although the CFTC has indicated that it intends to appeal the court's decision and that it believes the Dodd-Frank Act requires it to impose position limits. The impact of such regulations upon our business is not yet clear. Certain of our hedging and trading activities and those of our counterparties may be subject to the position limits, which may reduce our ability to enter into hedging transactions.

In addition, the Dodd-Frank Act does not explicitly exempt end users (such as us) from the requirement to use cleared exchanges, rather than hedging over-the-counter, and the requirements to post margin in connection with hedging activities. While it is not possible at this time to predict when the CFTC will finalize certain other related rules and regulations, the Dodd-Frank Act and related regulations may require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although whether these requirements will apply to our business is uncertain at this time. If the regulations ultimately adopted require that we post margin for our hedging activities or require our counterparties to hold margin or maintain capital levels, the cost of which could be passed through to us, or impose other requirements that are more burdensome than current regulations, our hedging would become more expensive and we may decide to alter our hedging strategy.

The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our existing or future derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The new legislation and any new regulations could significantly increase the cost of derivative contracts

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(including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our derivative contracts in existence at that time, and increase our exposure to less creditworthy counterparties. If we reduce or change the way we use derivative instruments as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations or cash flows.

~~Regulation of greenhouse emissions could result in increased operating costs and reduced demand for the oil and natural gas we produce.~~

In recent years, federal, state and local governments have taken steps to reduce emissions of greenhouse gases, or GHGs. The EPA has finalized a series of GHG monitoring, reporting and emissions control rules for oil and natural gas industry, and the U.S. Congress has, from time to time, considered adopting legislation to reduce emissions. Almost one-half of the states have already taken measures to reduce emissions of GHGs primarily through the development of GHG emission inventories and/or regional GHG cap-and-trade programs. While we are subject to certain federal GHG monitoring and reporting requirements, our operations currently are not adversely impacted by existing federal, state and local climate change initiatives. For a description of GHG existing and proposed rules and regulations, see Item 1. “~~Business-Regulation-Environmental Regulation-Climate Change~~.”

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce.

In addition, 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 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.

A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

Section 1(b) of the Natural Gas Act of 1938, or the NGA, exempts natural gas gathering facilities from regulation by FERC. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish whether a pipeline performs a gathering function and therefore is exempt from FERC's jurisdiction under the NGA. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is a fact-based determination. The classification of facilities as unregulated gathering is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress,

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which could cause our revenues to decline and operating expenses to increase and may materially adversely affect our business, financial condition or results of operations. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability, which could have a material adverse effect on our business, financial condition or results of operations.

~~We face extensive competition in our industry.~~

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.

~~The loss of one or more of the purchasers of our production could adversely affect our business, results of operations, financial condition and cash flows.~~

The two largest purchasers of our oil and natural gas during the year ended December 31, 2018 accounted for approximately 17% and 10%, respectively, of our total oil, natural gas and NGL revenues. If these purchasers or one or more other significant purchasers, are unable to satisfy its contractual obligations, we may be unable to sell such production to other customers on terms we consider acceptable. Further, the inability of one or more of our customers to pay amounts owed to us could adversely affect our business, financial condition, results of operations and cash flows.

~~Our method of accounting for oil and natural gas properties may result in impairment of asset value.~~

We use the full cost method of accounting for oil and natural gas operations. Accordingly, all costs, including nonproductive costs and certain general and administrative costs associated with acquisition, exploration and development of oil and natural gas properties, are capitalized. Net capitalized costs are limited to the estimated future net revenues, after income taxes, discounted at 10% per year, from proven oil and natural gas reserves and the cost of the properties not subject to amortization. Such capitalized costs, including the estimated future development costs and site remediation costs, if any, are depleted by an equivalent units-of-production method, converting natural gas to barrels at the ratio of six Mcf of natural gas to one barrel of oil.

Companies that use the full cost method of accounting for oil and gas properties are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the 12-month unweighted arithmetic average of the first-day-of-the-month prices for 2018, 2017 and 2016 adjusted for any contract provisions or financial derivatives, if any, that hedge oil and natural gas revenue, excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, less income tax effects related to differences between the book and tax basis of the oil and natural gas properties. If the net book value reduced by the related net deferred income tax liability exceeds the ceiling, an impairment or noncash writedown is required. A ceiling test impairment can result in a significant loss for a particular period. Once incurred, a write down of oil and natural gas properties is not reversible at a later date, even if oil or gas prices increase. As a result of the decline in commodity prices, we recorded a ceiling test impairment of $715.5 million for the year ended December 31, 2016. If prices of oil, natural gas and natural gas liquids continue to decrease, we may be required to further write down the value of our oil and natural gas properties. Future ~~non-cash asset impairments could negatively affect our results of operations.~~

~~Recently enacted U.S. tax legislation as well as future~~ U.S. and state tax ~~legislations~~legislation may adversely affect our business, results of operations, financial condition and cash flow.

On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act, or the Tax Act, that significantly reforms the Internal Revenue Code of 1986, as amended, or the Code. Among other changes, the Tax Act (i) permanently reduces the U.S. corporate income tax rate, (ii) repeals the corporate alternative minimum tax, (iii) eliminates the deduction for certain domestic production activities, (iv) imposes new limitations on the utilization of net operating losses, and (v) provides for more general changes to the taxation of corporations, including changes to cost recovery rules and to the deductibility of interest expense. The Tax Act is complex and

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far-reaching, and we cannot predict with certainty the resulting impact its enactment will have on us. The ultimate impact of the Tax Act may differ from our estimates due to changes in interpretations and assumptions made by us as well as additional regulatory guidance that may be issued, and any such changes in our interpretations and assumptions could have an adverse effect on our business, results of operations, financial condition and cash flow.

~~In addition, from~~From time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws affecting the oil and gas industry. For example, ~~legislations~~legislative proposals have been introduced in the U.S. Congress in the past tothat, if enacted, would (i) eliminate the immediate deduction for intangible drilling and development costs, (ii) repeal of the percentage depletion allowance for oil and natural gas ~~properties;~~properties, and (iii) extend the amortization period for certain geological and geophysical expenditures. ~~While these specific changes are not included in the Tax Act, no~~No accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. In addition, at the state level, legislative changes imposing increased taxes on oil and gas production have periodically been considered in Ohio and Oklahoma. These proposed changes in the U.S. federal and state tax law, if adopted, or other similar changes that would impose additional tax on our activities or reduce or eliminate deductions currently available with respect to natural gas and oil exploration, development or similar activities, could adversely affect our business, results of operations, financial condition and cash flows.

~~Additional~~Our business is subject to complex and evolving laws and regulations regarding privacy and data protection.

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The regulatory environment surrounding data privacy and protection is constantly evolving and can be subject to significant change. New laws and regulations governing data privacy and the unauthorized disclosure of confidential information pose increasingly complex compliance challenges and potentially elevate our costs as we collect and store personal data related to royalty owners. Any failure to comply with these laws and regulations could result in significant penalties and legal liability. For example, the California Consumer Privacy Act (“CCPA”) was signed into law on June 28, 2018 and largely took effect on January 1, 2020. The CCPA, among other things, contains new disclosure obligations for businesses that collect personal information about California residents and enhanced consumer protections for those individuals, and provides for statutory fines for data security breaches or other CCPA violations. Meanwhile, over fifteen other states have considered privacy laws like the CCPA. We will continue to monitor and assess the impact of these state ~~taxes~~laws, which may impose substantial penalties for violations, impose significant costs for investigations and compliance, require us to change our business practices, allow private class-action litigation and carry significant potential liability for our business should we fail to comply with any such applicable laws.

Any failure, or perceived failure, by us to comply with applicable data protection laws could result in heightened risk of litigation, including private rights of action, and proceedings or actions against us by governmental entities or others, subject us to significant fines, penalties, judgments and negative publicity, require us to change our business practices, increase the costs and complexity of compliance, and adversely affect our business. As noted above, we are also subject to the possibility of cyber incidents or attacks, which themselves may result in a violation of these laws. Additionally, if we acquire a company that has violated or is not in compliance with applicable data protection laws, we may incur significant liabilities and penalties as a result.

We may have material liability related to plugging and abandonment, reclamation, civil lawsuits and regulatory fines associated with our divested Louisiana assets.

Gulfport operated hundreds of wells in Louisiana before divesting substantially all Louisiana assets to PEL Gulf Coast, LLC (“Perdido”) in 2019. The Perdido Purchase Sale Agreement (“PSA”) contains a broad assumption of all obligations, as well as defense and indemnity obligations, in favor of Gulfport and against Perdido for all current and former Gulfport wells. To the extent Perdido files for bankruptcy protection or is unable to meet its obligations, Gulfport may have material liability related to plugging and abandonment, reclamation, civil lawsuits and regulatory fines.


ITEM 1B.			UNRESOLVED STAFF COMMENTS

None.


ITEM 2.			PROPERTIES

Information regarding our properties is included in Item 1 and in the Supplemental Information on Oil and Gas Exploration and Production Activities in Note 19 of the notes to our consolidated financial statements included in this report.


ITEM 3.			LEGAL PROCEEDINGS

The information with respect to this Item 3. Legal Proceedings is set forth in Note 1 8 in the accompanying consolidated financial statements. Additionally, see Note 1 and Note 2 in the accompanying consolidated financial statements for additional discussion of on-going claims and disputes in our Chapter 11 proceedings, certain of which may be material.


ITEM 4.			MINE SAFETY DISCLOSURES

Not applicable.

PART II

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ITEM 5.			MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Common Stock

On November 27, 2020, our common stock was suspended from trading on NASDAQ. On November 30, 2020, our common stock began trading on the OTC Pink Marketplace maintained by the OTC Markets Group, Inc. under the symbol “GPORQ". On February 2, 2021, NASDAQ filed a Form 25 delisting our common stock from trading on NASDAQ, which delisting became effective 10 days after the filing of the Form 25. In accordance with Rule 12d2-2 of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), the de-registration of our common stock under section 12(b) of the Exchange Act became effective on February 12, 2021.

Shareholders

At the close of business on February 22, 2021, there were approximately 311 stockholders and 19,574 beneficial owners of our common stock.

Dividends

We have never paid dividends on our common stock.


ITEM 6.			SELECTED FINANCIAL DATA

The following table sets forth selected consolidated financial data of Gulfport as of and for the years ended December 31, 2020, 2019, 2018, 2017 and 2016. The data are derived from our audited consolidated financial statements. The table below should be read in connection with Management's Discussion and Analysis of Financial Condition and Results of Operations and our consolidated financial statements and the related notes appearing elsewhere in Items 7 and 8, respectively, of this report.


	Fiscal Year Ended December 31,
	2020		2019		2018		2017		2016
	(In thousands, except share data)
Selected Consolidated Statements of Operations Data:
Revenues	$	866,542	$	1,563,126	$	1,551,701	$	1,320,303	$	385,910












(Loss) Income from Operations	(1,362,605)		(1,703,693)		398,959		555,781		(862,422)













Income Tax Expense (Benefit)	7,290		(7,563)		(69)		1,809		(2,913)

Net (Loss) Income Available to Common Stockholders	$	(1,625,133)	$	(2,002,358)	$	430,560	$	435,152	$	(979,709)
Net (Loss) Income Per Common Share—Basic:	$	(10.14)	$	(12.49)	$	2.46	$	2.42	$	(7.97)
Net (Loss) Income Per Common Share—Diluted:	$	(10.14)	$	(12.49)	$	2.45	$	2.41	$	(7.97)


	At December 31,
	2020		2019		2018		2017		2016
	(In thousands)
Selected Consolidated Balance Sheet Data:
Total assets	$	2,539,871	$	3,882,819	$	6,051,036	$	5,807,752	$	4,223,145
Total debt, including current maturities	$	253,743	$	1,978,651	$	2,087,416	$	2,038,943	$	1,593,875
Total liabilities subject to compromise	$	2,293,480	$	—	$	—	$	—	$	—
Total liabilities	$	2,840,371	$	2,568,227	$	2,723,268	$	2,706,138	$	2,039,253
Stockholders’ (deficit) equity	$	(300,500)	$	1,314,592	$	3,327,768	$	3,101,614	$	2,183,892


ITEM 7.			MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis represents management’s perspective of our business, financial condition and overall performance. This information is intended to provide investors with an understanding of our past performance, current

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financial condition and outlook for the future and should be read in conjunction with “Item 8. Financial Statements and Supplementary Data” of this report. The following discussion and analysis generally discusses 2020 and 2019 items and year-to-year comparisons between 2020 and 2019. Discussions of 2018 items and year-to-year comparisons between 2019 and 2018 that are not included in this Form 10-K can be found in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2019.

Overview

We are an independent natural gas-weighted exploration and production company focused on the exploration, acquisition and production of natural gas, ~~extraction may be imposed~~crude oil and NGL in the United States with primary focus in the Appalachia and Anadarko basins. Our principal properties are located in Eastern Ohio targeting the Utica formation and in central Oklahoma targeting the SCOOP Woodford and SCOOP Springer formations.

Voluntary Reorganization Under Chapter 11

On November 13, 2020, we and 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 are being administered jointly under the caption In re Gulfport Energy Corporation, et al., Case No. 20-35562 (DRJ).We continue to operate our businesses as "debtors-in-possession" under the jurisdiction of the Bankruptcy Court, in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court.

The Bankruptcy Court has granted first- and second- day motions filed by us that were designed primarily to mitigate the impact of the Chapter 11 Cases on our operations, customers and employees.As a result, we are able to conduct normal business activities and pay all associated obligations for the period following the Bankruptcy Filing and are authorized to pay owner royalties, employee wages and benefits and certain vendors and suppliers in the ordinary course for goods and services provided.During the pendency of the Chapter 11 Cases, all transactions outside the ordinary course of business require the prior approval of the Bankruptcy Court.

For the duration of the Chapter 11 Cases, our operations and ability to develop and execute our business plan are subject to the risks and uncertainties associated with the Chapter 11 process as described in Item 1A. “Risk Factors.” As a result of ~~future legislation.~~these risks and uncertainties, the number of our shares of common stock and stockholders, assets, liabilities, officers and/or directors could be significantly different following the outcome of the Chapter 11 Cases, and the description of our operations, properties and capital plans included in this Form 10-K may not accurately reflect our operations, properties and capital plans following the Chapter 11 Cases.

During the Chapter 11 Cases, we expect our financial results to continue to be volatile as restructuring activities and expenses, contract terminations and rejections and claims assessments significantly impact our consolidated financial statements.As a result, our historical financial performance is likely not indicative of our financial performance after the date of the Bankruptcy Filing.In addition, we have incurred significant professional fees and other costs in connection with preparation for the Chapter 11 Cases and expect that we will continue to incur significant professional fees and costs throughout our Chapter 11 Cases.

See Note 2 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for a complete discussion of the Chapter 11 Cases.

Delisting of our Common Stock from Nasdaq

On November 27, 2020, our common stock was suspended from trading on NASDAQ.On November 30, 2020, our common stock began trading on the OTC Pink Marketplace maintained by the OTC Markets Group, Inc. under the symbol “GPORQ".On February 2, 2021, NASDAQ filed a Form 25 delisting our common stock from trading on NASDAQ, which delisting became effective 10 days after the filing of the Form 25. In accordance with Rule 12d2-2 of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), the de-registration of our common stock under section 12(b) of the Exchange Act became effective on February 12, 2021.

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COVID-19 Pandemic and Impact on Global Demand for Oil and Natural Gas

In ~~February 2013,~~March 2020, the ~~Governor~~World Health Organization classified the outbreak of COVID-19 as a pandemic and recommended containment and mitigation measures worldwide. The measures have led to worldwide shutdowns and halting of commercial and interpersonal activity, as governments around the world imposed regulations in efforts to control the spread of COVID-19 such as shelter-in-place orders, quarantines, executive orders and similar restrictions.

We remain focused on protecting the health and well-being of our employees and the communities in which we operate while assuring the continuity of our business operations. We have implemented preventative measures and developed corporate and field response plans to minimize unnecessary risk of exposure and prevent infection. We have a crisis management team for health, safety and environmental matters and personnel issues, and we have established a COVID-19 Response Team to address various impacts of the ~~State~~situation, as they have been developing. We also have modified certain business practices (including remote working for our corporate employees and restricted employee business travel) to conform to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention, the World Health Organization and other governmental and regulatory authorities.

In May 2020, we began our phased transition back to the office for our corporate employees. As part of ~~Ohio proposed~~this transition, we have put into place preventative measures to focus on social distancing and minimizing unnecessary risk of exposure. Such measures include, but are not limited to, daily health surveys, protective masks in public areas of the building, no outside visitors, limiting the number of employees on elevators and additional sanitizing. As of the date of this filing, we have transitioned a ~~plan~~majority of our corporate employees back to the corporate office; however, we continue to provide a balanced work schedule that allows for a significant portion of the work week to be performed remotely. We will continue to monitor trends and governmental guidelines and may adjust our return to office plans accordingly to ensure the health and safety of our employees.

As a result of our business continuity measures, we have not experienced significant disruptions in executing our business operations during 2020. While we did not experience significant disruptions to our operations in 2020, we are unable to predict the impact on our business, including our cash flows, liquidity, and results of operations in future periods due to numerous uncertainties. There is considerable uncertainty regarding the extent to which COVID-19 will continue to spread and the extent and duration of governmental and other measures implemented to slow the spread of the virus, such as large-scale travel bans and restrictions, quarantines, shelter-in-place orders and business and government shutdowns. Restrictions of this nature may cause, us, our suppliers and other business counterparties to experience operational delays, or delays in the ~~Ohio House~~delivery of materials and supplies. We expect the principal areas of operational risk for us are the availability and reliability of service providers and potential supply chain disruption. Additionally, the operations of our midstream service providers, on whom we rely for the transmission, gathering and processing of a significant portion of our produced natural gas, NGL and oil, may be disrupted or suspended in response to ~~enact new severance taxes~~containing the outbreak, or the difficult economic environment may lead to the bankruptcy or closing of the facilities and infrastructure of our midstream service providers. This may result in substantial discount in the prices we receive for our produced natural gas, NGL and oil or result in the shut-in of producing wells or the delay or discontinuance of development plans for our properties.

One of the impacts of the pandemic has been a significant reduction in global demand for oil and natural gas. The significant decline in demand has been met with a sharp decline in oil prices following the announcement of price reductions and production increases in March 2020 by members of the Organization of Petroleum Exporting Countries, and other foreign, oil-exporting countries. The resulting supply/demand imbalance is having disruptive impacts on the oil and natural gas ~~industry. The proposal was part of the state budget bill. Due to pressure~~exploration and production industry and on other industries that serve exploration and production companies. These industry conditions, coupled with those resulting from the ~~State Senate, the proposal was removed from the bill. The bill then passed without the severance tax on June 7, 2013, with an effective date of July 1, 2013. Later~~COVID-19 pandemic, has led to significant global economic contraction generally and in ~~2013, the Ohio House introduced a stand-alone bill~~our industry in particular. We expect to address the severance tax. HB 375 was introduced on December 4, 2013 and after many hearings and amendments, contained a 2.5% severance tax on horizontal drillers with a percentage of the proceeds earmarked for affected communitiessee continued volatility in ~~Southeastern Ohio. This bill passed the Ohio House on May 14, 2014. The Ohio State Senate held a hearing on the bill, but there was no further movement before the recess of that General Assembly.~~

In February 2015, the Governor of Ohio proposed another plan to the new General Assembly to enact new severance taxes on the oil and gas industry. This proposal was part of a state budget proposal to finance a reduction in personal income taxes and other initiatives. The proposal would have imposed a 6.5% tax on oil and gas sold at the wellhead. This severance tax increase was removed from the Bill that was ultimately passed by the Ohio House.

A new General Assembly took office in January 2017, and the Governor of Ohio proposed a new severance tax initiative. The proposal would impose a fixed rate of 6.5% for crude oil and natural gas when sold at the wellhead and a lower rate of 4.5% at later stages of distribution for natural gas and natural gas liquids. The proposal was again met with opposition and was not included in the final budget that was passed and signed by the Governor on June 30, 2017 and effective for the period of July 1, 2017 through June 30, 2019.

These proposed changes in the U.S. and applicable state tax law, if adopted, or other similar changes that tax our production or reduce or eliminate deductions currently available with respect to natural gas and oil exploration and development, could adversely affect our business, financial condition, results of operations and cash flows.

Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.

Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.

We are exposed to fluctuations in the price of natural gas and oil. Although we have hedged a portion of our estimated 2018 production, we may still be adversely affected by continuing and prolonged declines in the price of natural gas and oil.

We use derivative instruments to reduce price volatility associated with certain of our oil and natural gas sales, but these hedges may be inadequate to protect us from continuing and prolonged declines in the price of oil and natural gas. For information regarding these derivative instruments, see Item 7A. "~~Quantitative and Qualitative Disclosures about Market Risk." Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less~~

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~~than expected or~~ oil and natural gas prices ~~increase. Further, to~~for the ~~extent that~~foreseeable future, which may, over the ~~price of oil and natural gas remains at current levels~~long term, adversely impact our business. Continued depressed demand or ~~declines further, we will not be able to hedge future production at the same level as our current hedges, and our results of operations and financial condition would be negatively impacted.~~

~~Our hedging transactions expose us to counterparty credit risk.~~

Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty's liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract.

~~A terrorist attack or armed conflict could harm our business.~~

Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demandprices for oil and natural gas potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers' operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

~~Loss of our information and computer systems could adversely affect our business.~~

We are dependent on our information systems and computer based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, whether due to cyber attack or otherwise, possible consequences include our loss of communication links, inability to find, produce, process and sell oil and natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.

~~We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss.~~

The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, and processing activities. For example, we depend on digital technologies to interpret seismic data, manage drilling rigs, production equipment and gathering systems, conduct reservoir modeling and reserves estimation, and process and record financial and operating data. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Our technologies, systems, networks, and those of its vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of its business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems and insurance coverage for protecting against cyber security risks may not be sufficient. As cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents.

~~Risks Relating to Our Indebtedness~~

~~Our substantial level of indebtedness could adversely affect our business, financial condition, results of operations and prospects.~~

As of December 31, 2018, we had total indebtedness (net of unamortized debt issuance costs) of approximately $2.1 billion, primarily attributable to our senior notes. We had $45.0 million in borrowings outstanding under our secured revolving credit facility and our borrowing base availability was $638.4 million after giving effect to an aggregate of $316.6 million of letters of credit.

~~Our outstanding indebtedness could have important consequences to you, including the following:~~

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our high level of indebtedness could make it more difficult for us to satisfy our obligations with respect to our indebtedness, and any failure to comply with the obligations under any of our debt instruments, including restrictive covenants, could result in a default under our secured revolving credit facility or the senior note indentures;

~~the restrictions imposed on the operation of our business by the terms of our debt agreements may hinder our ability to take advantage of strategic opportunities to grow our business;~~

our ability to obtain additional financing for working capital, capital expenditures, debt service requirements, restructuring, acquisitions or general corporate purposes may be impaired, which could be exacerbated by further volatility in the credit markets;

we must use a substantial portion of our cash flow from operations to pay interest on our senior notes and our other indebtedness, which will reduce the funds available to us for operations and other purposes;

~~our level of indebtedness could place us at a competitive disadvantage compared to our competitors that may have proportionately less debt;~~

~~our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate may be limited;~~

~~our high level of indebtedness makes us more vulnerable to economic downturns and adverse developments in our business; and~~

~~we may be vulnerable to interest rate increases, as our borrowings under our secured revolving credit facility are at variable interest rates.~~

~~Any of the foregoing could~~would have a material adverse effect on our business, cash flows, liquidity, financial condition and results of ~~operations~~operations.

Because of the sharp decline in oil prices since early March 2020, we chose to shut in a portion of our operated low margin, liquids-weighted production during the second quarter of 2020, largely consisting of legacy vertical production in the SCOOP. We also experienced shut-ins across both the SCOOP and ~~prospects.~~

Utica from our non-operated partners. All liquids-weighted volumes on both our operated assets and those of our non-operated partners have returned to production. A sharp decline in prices or a prolonged depressed environment may result in additional future shut ins. In addition, ~~if we are unable to generate sufficient cash flow and are otherwise unable to obtain funds necessary to meet required payments~~the COVID-19 pandemic creates risks of principal, premium, if any, or interest on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants, in the instruments governing our indebtedness, we could be in default under the terms of the agreements governing such indebtedness. In the event of such default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest. More specifically, the lenders under our secured revolving credit facility could elect to terminate their commitments, cease making further loans and institute foreclosure proceedings against our assets, and we could be forced into bankruptcy or litigation.

~~Servicing our indebtedness requires a significant amount of cash, and we may not have sufficient cash flow from our business to pay our substantial indebtedness.~~

Our ability to make scheduled payments of the principal of, to pay interest on or to refinance our indebtedness, including our senior notes, depends on our future performance, which is subject to economic, financial, competitive and other factors beyond our control. Our business may not generate cash flow from operations in the future sufficient to service our debt and make necessary capital expenditures. If we are unable to generate such cash flow, we may be required to adopt one or more alternatives, such as reducing or delaying capital expenditures, selling assets, restructuring debt or obtaining additional equity capital on terms that may be onerous or highly dilutive. However, we cannot assure you that undertaking alternative financing plans, if necessary, would allow us to meet our debt obligations. In the absence of such cash flows, we could have substantial liquidity problems and might be required to sell material assets or operations to attempt to meet our debt service and other obligations. Our revolving credit facility and the indentures governing our senior notes restrict our ability to use the proceeds from asset sales. We may not be able to consummate those asset sales to raise capital or sell assets at prices that we believe are fair, and proceeds that we do receive may not be adequate to meet any debt service obligations then due. Our ability to refinance our indebtedness will depend on the capital markets and our financial condition at the time. We may not be able to engage in any of these activities or engage in these activities on desirable terms, which could result in a default on our debt obligations and have an adverse effect on our financial condition.

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delays in new drilling and completion activities that could negatively impact us, our non-operated partners or our service providers.

~~Restrictive covenants~~In June 2020, in response to the depressed commodity price environment, we announced tiered salary reductions for most employees, senior management team and our ~~secured revolving credit facility,~~Board of Directors as well as select furloughs to reduce costs and preserve liquidity. The employee salary reductions were re-instated in late September, while the ~~indentures governing~~senior management and Board of Directors reductions were re-instated at December 31, 2020. In addition, we reduced our ~~senior notes~~workforce by approximately 10% in the third quarter of 2020 to align our workforce to the current and ~~in future debt instruments may restrict our ability to pursue~~forecasted needs of operating our business ~~strategies.~~

~~Our secured revolving credit facility and the indentures governing our senior notes limit, and the terms of any future indebtedness may limit, our ability, among other things, to:~~

~~incur or guarantee additional indebtedness;~~

~~make certain investments;~~

~~declare or pay dividends or make distributions on our capital stock;~~

~~prepay subordinated indebtedness;~~

~~sell assets including capital stock of restricted subsidiaries;~~

~~agree to payment restrictions affecting our restricted subsidiaries;~~

~~consolidate, merge, sell or otherwise dispose of all or substantially all of our assets;~~

~~enter into transactions with our affiliates;~~

~~incur liens;~~

~~engage in business other than the oil and gas business; and~~

~~designate certain of our subsidiaries as unrestricted subsidiaries.~~plans.

We ~~may be prevented from taking advantage of business opportunities~~cannot predict the full impact that ~~arise because of~~COVID-19 or the ~~limitations imposed on us by~~significant disruption and volatility currently being experienced in the restrictive covenants contained in our revolving credit facility and the indentures governing our senior notes. In addition, our revolving credit facility requires us to maintain certain financial ratios and tests. The requirement that we comply with these provisions may materially adversely affect our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business.

A breach of any of these restrictive covenants could result in default under our revolving credit facility. If default occurs, the lenders under our revolving credit facility may elect to declare all borrowings outstanding, together with accrued interest and other fees, to be immediately due and payable, which would result in an event of default under the indentures governing our senior notes. The lenders will also have the right in these circumstances to terminate any commitments they have to provide further borrowings. If we are unable to repay outstanding borrowings when due, the lenders under our revolving credit facility will also have the right to proceed against the collateral granted to them to secure the indebtedness. If the indebtedness under our revolving credit facility and our senior notes were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full that indebtedness.

Any significant reduction in our borrowing base under our revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations, and we may not have sufficient funds to repay borrowings under our revolving credit facility if required as a result of a borrowing base redetermination.

Availability under our revolving credit facility is currently subject to a borrowing base of $1.4 billion, with an elected commitment of $1.0 billion. The borrowing base is subject to scheduled semiannual and other elective collateral borrowing base redeterminations based on our oil and natural gas ~~reserves~~markets will have on our business, cash flows, liquidity, financial condition and results of operations at this time, due to numerous uncertainties. The ultimate impacts will depend on future developments, including, among others, the ultimate geographic spread of the virus, the consequences of governmental and other ~~factors. As~~measures designed to prevent the spread of ~~December 31, 2018,~~the virus, the development and distribution of effective treatments and vaccines, the duration of the outbreak, actions taken by members of OPEC and other foreign, oil-exporting countries, governmental authorities, customers, suppliers and other thirds parties, workforce availability, and the timing and extent to which normal economic and operating conditions resume. While we ~~had $45.0~~have seen meaningful recovery in demand during the second half of the year, significant uncertainty remains regarding the duration and extent of the impact of the pandemic on the energy industry, including demand and commodities pricing, although we expect to see further recovery as vaccines are distributed and more normal societal activity resumes. For additional discussion regarding risks associated with the COVID-19 pandemic, see Item 1A. “Risk Factors” in this report.

2020 Operational and Financial Highlights

In the current depressed commodity price environment and period of economic uncertainty, we took the following operational and financial measures in 2020 to improve our balance sheet and preserve liquidity:

•Reduced 2020 capital spending by more than 50% as compared to 2019;

•Divested our SCOOP water infrastructure assets to a third-party water service provider for $50 million;

•Reduced long-term debt related to our senior unsecured notes by $73.3 million through discounted repurchases;

•Reduced certain corporate general and administrative costs through pay reductions, furloughs and reductions in ~~borrowings~~force;

•Evaluated economics across our portfolio and ~~$316.6 million~~shut-in certain non-economical production in the second quarter of ~~letters of credit outstanding under~~2020;

•Continued to significantly improve operational efficiencies and reduce drilling and completion costs in both our ~~revolving credit facility. Any significant reduction~~SCOOP and Utica operating areas. In the Utica, our average spud to rig release time was 18.7 days in 2020, which was a 5% improvement from 2019 levels. In the SCOOP, our ~~borrowing base as~~average spud to rig release time was 35.5 days, representing a ~~result of such borrowing base redeterminations or otherwise may negatively impact our~~35% improvement compared to 2019 levels.

Although management's actions listed above have helped to improve the company's liquidity and ~~our~~leverage profile, continued macro headwinds including the depressed state of energy capital markets and extraordinarily low commodity price environment presented significant risks to the Company's ability to fund ~~our~~its operations ~~and, as a result, may have a material adverse effect on our financial position, results of operation and cash flow. Further, if~~going forward. On October 8, 2020, the outstanding borrowings under our revolving credit facility were to exceed the borrowing base as a result of any such redetermination, we would be required to repay the excess. We may not have sufficient funds to make such repayments. If we do not have sufficient funds and we are otherwise unable to negotiate renewals of our

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~~borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.~~

~~We may still be able to incur substantial additional indebtedness in the future, which could further exacerbate the risks that we and our subsidiaries face.~~

We and our subsidiaries may be able to incur substantial additional indebtedness in the future. The terms of our revolving credit facility and the indentures governing our senior notes restrict, but in each case do not completely prohibit, us from doing so. As of December 31, 2018, our borrowing base under our revolving credit facility was ~~set at~~reduced for the second time in 2020 from $700 million to $580 million, thereby significantly reducing available liquidity. Considering the facts above, we elected not to make interest payments of $17.4 million due October 15, 2020 and $10.8 million due November 2, 2020 on our 2024 Notes and 2023 Notes, respectively. On November 13, 2020, we filed voluntary petitions for relief under Chapter 11 as discussed above.

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Results of Operations

Comparison of the Years Ended December 31, 2020 and December 31, 2019

We reported a net loss of $1.6 billion for the year ended December 31, 2020 as compared to a net loss of $2.0 billion for the year ended December 31, 2019. The graph below shows the change in the net loss from the year ended December 31, 2020 to the year ended December 31, 2019. The material changes are further discussed by category on the following pages. Some totals and changes throughout below section may not sum or recalculate due to rounding.

(1) Includes lease operating expenses, taxes other than income and midstream, gathering and processing expenses.

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Natural Gas, Oil and NGL Sales


	Years Ended December 31,
	2020		2019		change
	(In thousands, unless otherwise stated)
Natural gas (MMcf/day)

Utica production volumes	795		1,062		(25)	%
SCOOP production volumes	147		194		(24)	%
Other production volumes(3)	—		—		(64)	%
Total production volumes	943		1,255		(25)	%

Total sales	$	671,535	$	1,135,381	(41)	%

Average price without the impact of derivatives ($/Mcf)	$	1.95	$	2.48	(21)	%
Impact from settled derivatives ($/Mcf)(1)	$	0.33	$	0.23	43	%
Average price, including settled derivatives ($/Mcf)	$	2.28	$	2.71	(16)	%

Oil and condensate (MBbl/day)

Utica production volumes	1		1		59	%
SCOOP production volumes	4		4		(14)	%
Other production volumes(3)	—		1		(94)	%
Total production volumes	5		6		(18)	%

Total sales	$	62,902	$	117,937	(47)	%

Average price without the impact of derivatives ($/Bbl)	$	34.88	$	53.95	(35)	%
Impact from settled derivatives ($/Bbl)(2)	$	25.76	$	1.86	1285	%
Average price, including settled derivatives ($/Bbl)	$	60.64	$	55.81	9	%

NGL (MBbl/day)

Utica production volumes	3		5		(41)	%
SCOOP production volumes	8		9		(12)	%
Other production volumes(3)	—		—		(50)	%
Total production volumes	11		14		(22)	%

Total sales	$	66,814	$	101,448	(34)	%

Average price without the impact of derivatives ($/Bbl)	$	16.86	$	19.99	(16)	%
Impact from settled derivatives ($/Bbl)	$	(0.04)	$	2.79	(101)	%
Average price, including settled derivatives ($/Bbl)	$	16.82	$	22.78	(26)	%

Total (MMcfe/day)

Utica production volumes	820		1,095		(25)	%
SCOOP production volumes	217		274		(21)	%
Other production volumes(3)	—		6		(94)	%
Total production volumes	1,037		1,375		(25)	%

Total sales	$	801,251	$	1,354,766	(41)	%

Average price without the impact of derivatives ($/Mcfe)	$	2.11	$	2.70	(22)	%
Impact from settled derivatives ($/Mcfe)	$	0.42	$	0.24	75	%
Average price, including settled derivatives ($/Mcfe)	$	2.53	$	2.94	(14)	%

(1) In November 2020, the Company early terminated certain gas fixed price swaps 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.

(3) Includes Niobrara, Bakken and Southern Louisiana.

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In 2020, our total unhedged natural gas, oil and NGL revenues decreased approximately $553.5 million, or 41%, as compared to 2019. A 25% decrease in total production volumes accounted for $323 million of lower natural gas, oil and NGL revenues. The decrease is production was primarily related to our significantly lower capital program beginning in the fourth quarter of 2019 into 2020. The remainder of the decrease in natural gas, oil and NGL revenues is related to a significant decrease in the realized prices for each of our commodities as compared to 2019 realized prices driven by depressed commodity market conditions.

The total natural gas, oil and NGL volumes hedged for 2020 and 2019 represented approximately 70% and 96%, respectively, of our total sales volumes for the applicable year.

Natural Gas, Oil and NGL Derivatives


	Years Ended December 31,
	2020		2019
	($ In thousands)
Natural gas derivatives - fair value (losses) gains	$	(89,310)	$	89,576
Natural gas derivatives - settlement gains	113,075		104,874
Total gains on natural gas derivatives	23,765		194,450

Oil and condensate derivatives - fair value (losses) gains	(2,952)		2,952
Oil and condensate derivatives - settlement gains	46,462		4,083
Total gains on oil and condensate derivatives	43,510		7,035

NGL derivatives - fair value losses	(461)		(7,541)
NGL derivatives - settlement (losses) gains	(142)		14,173
Total (losses) gains on NGL derivatives	(603)		6,632

Contingent consideration arrangement - fair value (losses) gains	(1,381)		243
Total gains on natural gas, oil and NGL derivatives	$	65,291	$	208,360

Settlement gains (losses) in the table above represent realized cash gains or losses to the instruments described in Note 13 to our consolidated financial statements. Our hedging program provided cash settlements of $159.4 million in 2020 as compared to $123.1 million in 2019.

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Lease Operating Expenses


	Years Ended December 31,
	2020		2019		change
	($ In thousands, except per unit)
Lease operating expenses
Utica	$	40,071	$	50,832	(21)	%
SCOOP	14,156		18,249		(22)	%
Other(1)	8		4,415		(100)	%
Total lease operating expenses	$	54,235	$	73,496	(26)	%

Lease operating expenses per Mcfe
Utica	$	0.13	$	0.13	5	%
SCOOP	0.18		0.18		(3)	%
Other(1)	0.06		2.18		(97)	%
Total lease operating expenses per Mcfe	$	0.14	$	0.15	(2)	%

_____________________

(1) Includes Niobrara, Bakken and Southern Louisiana

The decrease in total LOE in 2020 was primarily driven by the 25% decrease in our production resulting from production declines from our Utica and SCOOP properties as a result of reduced development activities in addition to the divestiture of our Southern Louisiana properties as discussed in Note 3 to our consolidated financial statements. LOE on a per unit basis was slightly lower for the year ended December 31, 2020 as compared to 2019 as a result of increased focus on reducing lease operating expenses within the organization as well as the divestiture of the Southern Louisiana properties which had a higher operating cost structure relative to our other assets.

Taxes Other Than Income


	Years Ended December 31,
	2020		2019		change
	($ In thousands, except per unit)
Production taxes	$	17,511	$	28,571	(39)	%
Property taxes	$	9,510	$	9,470	—	%
Other	$	1,488	$	2,469	(40)	%
Total Taxes other than income	$	28,509	$	40,510	(30)	%
Production taxes per Mcfe	$	0.05	$	0.06	(19)	%

The decrease in production taxes in 2020 was primarily related to a decrease in revenue and production in 2020 as compared to 2019.

Midstream Gathering and Processing Expenses


	Years Ended December 31,
	2020		2019		change
	($ In thousands, except per unit)
Midstream gathering and processing expenses	$	456,318	$	508,843	(10)	%
Midstream gathering and processing expenses per Mcfe	$	1.20	$	1.01	19	%

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The decrease in midstream gathering and processing expenses in 2020 was primarily related to the 25% decrease in our production volumes. The increase in per unit midstream gathering and processing expenses in 2020 is primarily related to Utica production volumes falling below the minimum volume commitments we have on certain of our firm transportation agreements with pipeline companies and the resulting deficiency payments.

Depreciation, Depletion and Amortization


	Years Ended December 31,
	2020		2019		change
	($ In thousands, except per unit)
Depreciation, depletion and amortization of oil and gas properties	$	229,703	$	538,894	(57)	%
Depreciation, depletion and amortization of other property and equipment	$	10,041	$	11,214	(10)	%
Total Depreciation, depletion and amortization	$	239,744	$	550,108	(56)	%
Depreciation, depletion and amortization per Mcfe	$	0.63	$	1.10	(42)	%

The decrease in DD&A in 2020 was due to a decrease in the depletion rate, driven primarily by impairment charges in 2019 and 2020, which decreased the depletion base. The decrease was further driven by an approximate 25% decrease in production.

Impairment of Oil and Gas Properties. During 2020, we had $1.4 billion oil and natural gas properties impairment charges related primarily to the continued decline in commodity prices, compared to $2.0 billion impairment charges of oil and gas properties in 2019.

General and Administrative Expenses


	Years Ended December 31,
	2020		2019		change
	($ In thousands, except per unit)
General and administrative expenses, gross	$	95,904	$	86,854	10	%
Reimbursed from third parties	(11,567)		(11,173)		4	%
Capitalized general and administrative expenses	(25,008)		(30,139)		(17)	%
General and administrative expenses, net	$	59,329	$	45,542	30	%
General and administrative expenses, net per Mcfe	$	0.16	$	0.09	72	%

The increase in general and administrative expenses, gross in 2020 was primarily due to an increase in non-recurring legal and consulting charges and compensation expense as a result of cash retention incentives paid to our employees during the third quarter of 2020. See Note 8 to our consolidated financial statements for further discussion on these cash retention incentive payments. This increase was partially offset by lower salary costs resulting from the reduction in workforce that was completed in the fourth quarter of 2019 and third quarter of 2020 as well as certain furloughs and pay reductions as discussed in the overview. The decrease in capitalized general and administrative expenses in 2020 was due to lower development activities for 2020 as compared to 2019.

Restructuring and Liability Management Expenses. In the third quarter of 2020 and fourth quarter of 2019, the Company announced and completed workforce reductions representing approximately 10% and 13%, respectively, of its headcount. In connection with ~~an elected commitment~~the reduction, the Company incurred total restructuring charges of ~~$1.0 billion,~~approximately $1.5 million and $4.6 million, primarily consisting of one-time employee-related termination benefits, for 2020 and 2019, respectively. Additionally, the Company incurred charges related to financial and legal advisors engaged to assist with the evaluation of a range of liability management alternatives during 2020 prior to the filing of the Chapter 11 Cases. While we expect to continue to incur significant financial and legal advisor fees throughout the Chapter 11 process, these costs will be presented in Reorganization Items, Net in our consolidated statements of operations.

Accretion Expense. Accretion expense decreased to $3.1 million for the 2020 from $3.9 million for the 2019, primarily as a result of asset divestitures discussed in N ote 3.

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Index to Financial Statement s

Interest Expense


	Years Ended December 31,
	2020		2019
	($ In thousands, except per unit)
Interest expense on senior notes	98,528		125,687
Interest expense on pre-petition revolving credit facility	14,224		12,088
Interest expense on building loan and other	1,861		1,055
Capitalized interest	(907)		(3,372)
Interest on DIP credit facility	810		—
Amortization of loan costs	5,563		6,328
Total interest expense	$	120,079	$	141,786

Interest expense per Mcfe	$	0.32	$	0.28

Weighted average debt outstanding under revolving credit facility	$	193,182	$	161,416

The decrease in interest on senior notes in 2020 as compared to 2019 is primarily due to the Chapter 11 proceedings. As of the Petition Date, we are not paying or recognizing interest expense on any of our outstanding debt other than any post-petition amounts drawn on the Pre-Petition Revolving Credit Facility and the DIP Credit Facility.

Gain on Debt Extinguishment. In July of 2019, our Board of Directors authorized $100 million of cash to be used to repurchase its senior notes in the open market at discounted values to par. In December 2019, our Board of Directors increased the authorized size of the senior note repurchase program to $200 million in total. During 2020, we repurchased in the open market $73.3 million aggregate principal amount of our outstanding Senior Notes for $22.8 million in cash and recognized a $49.6 million gain on debt extinguishment. During 2019, we repurchased $190.1 aggregate principal amount of our outstanding Senior Notes for $138.8 million in cash and recognized a $48.6 million gain on debt extinguishment.

Equity Investments


	Years Ended December 31,
	2020		2019		change
	($ In thousands)

Loss (income) from equity method investments, net	$	11,055	$	210,148	(95)	%

For 2020, the loss from equity method investments stems primarily from a $10.6 million loss related to our investment in Mammoth Energy, with no impairments recorded. The loss from equity method investments during 2019 was primarily the result of a $160.8 million impairment loss related to our investment in Mammoth Energy and a $32.4 million impairment loss related to our investment in Grizzly. See Note 5 to our consolidated financial statements for further discussion on our equity investments.

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Index to Financial Statement s

Reorganization Items, Net. The following table summarizes the components in reorganization items, net included in our consolidated statements of operations for the year ended December 31, 2020:


	Year Ended December 31, 2020
	(in thousands)
Adjustment for allowed claims	$	104,943
Legal and professional fees	24,905
Write off of unamortized debt issuance costs	21,956
DIP credit facility financing fees	2,988
Gain on settlement of pre-petition accounts payable	(2,433)
Reorganization items, net	$	152,359

We expect to incur significant legal and professional fees related to our ongoing Chapter 11 case in 2021.

Other Expense, Net


	Years Ended December 31,
	2020		2019		change
	($ In thousands)
Other expense, net	$	21,738	$	3,725	484	%

The increase in other expense in 2020 is primarily the result of a $16.6 million loss on the change in fair value of our contingent consideration agreement related to the sale of our SCOOP water infrastructure assets to a third-party water service provider. See Note 15 to our consolidated financial statements for further discussion on our contingent consideration agreement.

Income Taxes


	Years Ended December 31,
	2020		2019		change
	($ In thousands)
Income tax expense (benefit)	$	7,290	$	(7,563)	(196)	%

The change in income tax in 2020 is primarily the result of the recognition of a valuation allowance against a state deferred tax asset. At December 31, 2020, we had ~~$45.0~~a federal net operating loss carryforward of $1.9 billion, in addition to numerous temporary differences, which gave rise to a net deferred tax asset, and a valuation allowance of $985.5 million inmaintained against the net deferred asset.

Liquidity and Capital Resources

Overview. Historically, our primary sources of capital funding and liquidity have been our operating cash flow, borrowings under ~~this facility. Total~~our Pre-Petition Revolving Credit Facility and issuances of equity and debt securities. Our ability to issue additional indebtedness, dispose of assets or access the capital markets may be substantially limited or nonexistent during the Chapter 11 Cases and will require court approval in most instances. Accordingly, our liquidity will depend mainly on cash generated from operating activities and available funds ~~available for borrowing~~ under the DIP Credit Facility as discussed below.

Filing of the Chapter 11 Cases constituted an event of default with respect to certain of our ~~revolving credit facility~~secured and unsecured debt obligations. As a result of the Chapter 11 Cases, the principal and interest due under these debt instruments became immediately due and payable. However, the creditors are stayed from taking any action as a result of the default under Section 362 of the Bankruptcy Code.

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Index to Financial Statement s

As of December 31, 2020, we had a cash balance of $89.9 million compared to $6.1 million as of December 31, ~~2018, after giving effect~~2019, and a net working capital deficit of $100.5 million as of December 31, 2020, compared to ~~$316.6~~a net working capital deficit of $145.3 million as of December 31, 2019. As of December 31, 2020, our working capital deficit includes $253.7 million of debt due in the next 12 months. Our total principal debt as of December 31, 2020 was $2.3 billion compared to $2.0 billion as of December 31, 2019. Additionally, as of December 31, 2020, we had outstanding borrowings of $157.5 million on our DIP credit facility with $105.0 million of incremental borrowing capacity. See Note 6 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of our debt obligations, including principal and carrying amounts of our notes.

We believe our cash flow from operations, borrowing capacity under the DIP Credit Facility and cash on hand will provide sufficient liquidity during the Chapter 11 process. We expect to incur significant costs related to our ongoing Chapter 11 Cases in 2021, including fees for legal, financial and restructuring advisors to the Company, certain of our creditors and royalty interest owners. Therefore, our ability to obtain confirmation of the Plan in a timely manner is critical to ensuring our liquidity is sufficient during the bankruptcy process.

Our ability to continue as a going concern is contingent on our ability to comply with the financial and other covenants contained in our DIP Credit Facility, the Bankruptcy Court's approval of the Plan and our ability to successfully implement the Plan and obtain exit financing, among other factors. As a result of the Bankruptcy Filing, the realization of assets and the satisfaction of liabilities are subject to uncertainty. While operating as debtors-in-possession under Chapter 11, we may settle liabilities, subject to the approval of the Bankruptcy Court or as otherwise permitted in the ordinary course of business (and subject to restrictions contained in the DIP Credit Facility), for amounts other than those reflected in the accompanying consolidated financial statements. Further, the Plan could materially change the amounts and classifications of assets and liabilities reported in the consolidated financial statements.

Debtor-In-Possession Credit Facility. Pursuant to the RSA, the Consenting RBL Lenders have agreed to provide the Company with a senior secured superpriority debtor-in-possession revolving credit facility in an aggregate principal amount of $262.5 million consisting of $105 million of new money and $157.5 million to roll up a portion of the existing outstanding obligations under the Pre-Petition Revolving Credit Facility. The proceeds of the DIP Credit Facility may be used for, among other things, post-petition working capital, permitted capital investments, general corporate purposes, letters of credit, ~~were $638.4 million. In addition,~~administrative costs, premiums, expenses and fees for the ~~indentures governing our senior notes allow us to issue additional notes under certain circumstances which will also be guaranteed~~transactions contemplated by the ~~guarantors. The indentures governing our senior notes also allow us to incur certain other additional secured debt~~Chapter 11 Cases and allow us to have subsidiaries that do not guarantee the senior notes and which may incur additional debt, which would be structurally senior to our senior notes. In addition, the indentures governing our senior notes do not prevent us from incurring other liabilities that do not constitute indebtedness. If we or a guarantor incur any additional indebtedness that ranks equally with our senior notes (or with the guarantees thereof), including additional unsecured indebtedness or trade payables, the holderspayment of that indebtedness will be entitled to share ratably with holders of our senior notes in any proceeds distributed in connection with any insolvency, liquidation, reorganization, dissolution or other winding-up of us or a guarantor. If new debt or other liabilities are added to our current debt levels, the related risks that we and our subsidiaries now face could intensify.court approved adequate protection obligations.

~~Our borrowings~~Advances under our ~~revolving credit facility expose us to interest rate risk.~~

Our earnings are exposed to interest rate risk associated with borrowings under our revolving credit facility. Our revolving credit facility is structured under floating rate terms, as advances under this facilityDIP Credit Facility may be in the form of either base rate loans or eurodollar loans. The interest rate for base rate loans is equal to (1) the applicable rate of 3.50%, plus (2) the base rate. The interest rate for eurodollar loans is equal to (1) the applicable rate of 4.50%, plus (2) the highest of: (a) 1% or (b) the eurodollar rate. As ~~such,~~of December 31, 2020, amounts borrowed under our DIP Credit Facility bore interest ~~expense is sensitive~~at the weighted average rate of 5.50%.

The DIP Credit Facility includes negative covenants that, subject to ~~fluctuations~~significant exceptions, limit our ability and the ability of our restricted subsidiaries to, among other things, (i) create liens on assets, property revenues, (ii) make investments, (iii) incur additional indebtedness, (iv) engage in mergers, consolidations, liquidations and dissolutions, (v) sell assets, (vi) pay dividends and distributions or repurchase capital stock, (vii) cease for any reason to be the operator of its properties, (viii) enter into letters of credit without prior written consent, (ix) enter into certain commodity hedging contracts except commodity hedging contracts with terms approved by the Bankruptcy Court in the ~~prime rates~~hedging order or certain interest rate contracts, (x) change lines of business, (xi) engage in certain transactions with affiliates and (xii) incur more than a certain amount in capital expenditures in any calendar month. The DIP Credit Facility includes certain customary representations and warranties, affirmative covenants and events of default, including but not limited to defaults on account of nonpayment, breaches of representations and warranties and covenants, certain bankruptcy-related events, certain events under ERISA, material judgments and a change in control. If an event of default occurs, the lenders under the DIP Credit Facility will be entitled to take various actions, including the acceleration of all amounts due under the DIP Credit Facility and all actions permitted to be taken under the loan documents or application of law. In addition, the DIP Credit Facility is subject to various other financial performance covenants, including compliance with certain financial metrics and adherence to a budget approved by our DIP Credit Facility lenders.

Pre-Petition Revolving Credit Facility. We have entered into a senior secured revolving credit facility agreement, as amended, with The Bank of Nova Scotia, as the lead arranger and administrative agent and certain lenders from time to time party thereto. The credit agreement provides for a maximum borrowing base amount of $580 million and matures on December 31, 2021. The $292.9 million of outstanding borrowings under the Pre-Petition Revolving Credit Facility as of December 31,

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Index to Financial Statement s

2020 that were not rolled up into the DIP Credit Facility will remain outstanding throughout the Chapter 11 Cases and will continue to accrue interest on amounts drawn after the Petition Date. Additionally, as of December 31, 2020, we had an aggregate of $147.5 million of letters of credit outstanding under our Pre-Petition Revolving Credit Facility. This facility is secured by substantially all of our assets. Our wholly-owned subsidiaries, excluding Grizzly Holdings and Mule Sky, guarantee our obligations under our revolving credit facility.

Advances under our Pre-Petition Revolving Credit Facility may be in the form of either base rate loans or eurodollar loans. The interest rate for base rate loans is equal to (1) the applicable rate, which ranges from 0.25% to 1.25%, plus (2) the highest of: (a) the federal funds rate plus 0.50%, (b) the rate of interest in effect for such day as publicly announced from time to time by the administrative agent as its “prime rate,” and (c) the eurodollar rate for an interest period of one month plus 1.00%. The interest rate for eurodollar loans is equal to (1) the applicable rate, which ranges from 1.25% to 2.25%, plus (2) the London interbank offered rate that appears on pages LIBOR01 or LIBOR02 of the Reuters screen that displays such rate for deposits in U.S. dollars, or, if such rate is not available, the ~~eurodollar rates are elected,~~rate as administered by ICE Benchmark Administration (or any other person that takes over administration of such rate) per annum equal to the ~~eurodollar rates. At~~offered rate on such other page or other service that displays an average London interbank offered rate as administered by ICE Benchmark Administration (or any other person that takes over the administration of such rate) for deposits in U.S. dollars, or, if such rate is not available, the average quotations for three major New York money center banks of whom the administrative agent shall inquire as the “London Interbank Offered Rate” for deposits in U.S. dollars. As of December 31, ~~2018,~~2020, amounts borrowed under our revolving credit facility bore interest at the weighted average rate of ~~4.23%~~3.15%.

Senior Notes. ~~A 1% increase~~In April 2015, we issued an aggregate of $350.0 million in principal amount of our 2023 Notes. Interest on these senior notes accrues at a rate of 6.625% per annum on the ~~average interest~~outstanding principal amount thereof, payable semi-annually on May 1 and November 1 of each year. As of December 31, 2020, after giving effect to open market repurchases of these 2023 Notes, $324.6 million principal amount remained outstanding. The 2023 Notes mature on May 1, 2023.

On October 14, 2016, we issued an aggregate of $650.0 million in principal amount of our 2024 Notes. Interest on the 2024 Notes accrues at a rate ~~would~~of 6.000% per annum on the outstanding principal amount thereof, payable semi-annually on April 15 and October 15 of each year. As of December 31, 2020, after giving effect to open market repurchases of these 2024 Notes, $579.6 million principal amount remained outstanding. The 2024 Notes mature on October 15, 2024.

On December 21, 2016, we issued an aggregate of $600.0 million in principal amount of our 2025 Notes. Interest on the 2025 Notes accrues at a rate of 6.375% per annum on the outstanding principal amount thereof, payable semi-annually on May 15 and November 15 of each year. As of December 31, 2020, after giving effect to open market repurchases of these 2025 Notes, $507.9 million principal amount remained outstanding. The 2025 Notes mature on May 15, 2025.

On October 11, 2017, we issued $450.0 million in aggregate principal amount of our 2026 Notes. Interest on the 2026 Notes accrues at a rate of 6.375% per annum on the outstanding principal amount thereof, payable semi-annually on January 15 and July 15 of each year. As of December 31, 2020, after giving effect to open market repurchases of these 2026 Notes, $374.6 million principal amount remained outstanding. The 2026 Notes mature on January 15, 2026.

All amounts outstanding on our Senior Notes have ~~increased our interest expense by approximately $0.8 million based~~been classified as liabilities subject to compromise on ~~outstanding~~the accompanying consolidated balance sheet as of December 31, 2020.

During the year ended December 31, 2020, we used borrowings under our revolving credit facility ~~throughout~~to repurchase in the ~~year ended~~open market approximately $73.3 million aggregate principal amount of our outstanding Notes for $22.8 million. We recognized a $49.6 million gain on debt extinguishment, which included retirement of unamortized issuance costs and fees associated with the repurchased debt.

Building Loan. On June 4, 2015, we entered into a loan for the construction of our corporate headquarters in Oklahoma City, which was substantially completed in December ~~31, 2018. An increase in our interest~~2016. Interest accrues daily on the outstanding principal balance at a fixed rate ~~at the time we have variable interest rate borrowings outstanding under our revolving credit facility will increase our costs, which may have a material adverse effect~~of 4.50% per annum. The building loan matures on ~~our results of operations and financial condition.~~June 4, 2025. As of December 31, ~~2018, we did~~2020, the total borrowings under the building loan were approximately $21.9 million, which has been classified as liabilities subject to compromise on the accompanying consolidated balance sheet as of December 31, 2020.

Supplemental Guarantor Financial Information. The 2023 Notes, 2024 Notes, 2025 Notes and 2026 Notes are guaranteed on a senior unsecured basis by all existing consolidated subsidiaries that guarantee our secured revolving credit facility or certain other debt (the “Guarantors”). The Senior Notes are not ~~hedge our interest rate risk.~~guaranteed by Grizzly Holdings or Mule Sky, LLC (the “Non-

~~If we experience liquidity concerns, we could face a downgrade in our debt ratings which could restrict our access~~

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Index to Financial Statement s

Guarantors”). The Guarantors are 100% owned by the Parent, and ~~negatively impact~~ the ~~terms~~guarantees are full, unconditional, joint and several. There are no significant restrictions on the ability of ~~current~~the Parent or ~~future financings or trade credit.~~

~~Our ability~~the Guarantors to obtain ~~financings~~funds from each other in the form of a dividend or loan. The guarantees rank equally in the right of payment with all of the senior indebtedness of the subsidiary guarantors and ~~trade credit~~senior in the right of payment to any future subordinated indebtedness of the subsidiary guarantors.The Senior Notes and the ~~terms~~guarantees are effectively subordinated to all of ~~any financings or trade~~our and the subsidiary guarantors' secured indebtedness (including all borrowings and other obligations under our amended and restated credit ~~are, in part, dependent on~~agreement) to the ~~credit ratings assigned~~extent of the value of the collateral securing such indebtedness, and structurally subordinated to ~~our debt by independent credit rating agencies. We cannot provide assurance that~~all indebtedness and other liabilities of any of our ~~current ratings will remain~~subsidiaries that do not guarantee the Notes. Effective June 1, 2019, the Parent contributed interests in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales and near-term and long-term production growth opportunities, liquidity, asset quality, cost structure, product mix and commodity pricing levels. A ratings downgrade could adversely impact our ability to access financings or trade credit and increase our borrowing costs.

~~Risks Related to Our Common Stock~~

~~If our quarterly revenues and operating results fluctuate significantly, the price of our common stock may be volatile.~~

Our revenues and operating results may in the future vary significantly from quarter to quarter. If our quarterly results fluctuate, it may cause our stock price to be volatile. We believe that a number of factors could cause these fluctuations, including:

~~changes in~~certain oil and ~~natural~~ gas ~~prices;~~

~~changes in production levels;~~

~~changes in governmental regulations~~assets and ~~taxes;~~

~~Table of Contents~~

~~geopolitical developments;~~

~~the level of foreign imports of oil and natural gas; and~~

~~conditions in the oil and natural gas industry and the overall economic environment.~~

~~Because~~certain of the ~~factors listed above, among others, we believe that our quarterly revenues, expenses~~Guarantors.

SEC Regulation S-X Rule 13-01 requires the presentation of "Summarized Financial Information" to replace the "Condensed Consolidating Financial Information" required under Rule 3-10. Rule 13-01 allows the omission of Summarized Financial Information if assets, liabilities and ~~operating~~ results ~~may vary significantly in~~of operations of the ~~future and that period-to-period comparisons of our operating results~~Guarantors are not ~~necessarily meaningful. You should not rely on~~materially different than the ~~results of one quarter as an indication of~~corresponding amounts presented in our ~~future performance. It is also possible that in some future quarters,~~consolidated financial statements. The Parent and Guarantor subsidiaries comprise our ~~operating results will fall below our expectations or the expectations of market analysts and investors. If we do not meet these expectations, the price of our common stock may decline significantly.~~

~~We do not currently pay dividends on our common stock and do not anticipate doing so in the future.~~

~~We have paid no cash dividends on our common stock, and we may not pay cash dividends on our common stock in the future. We intend to retain any earnings to fund our~~material operations. Therefore, we doconcluded that the presentation of the Summarized Financial Information is not ~~anticipate paying any cash dividends on~~required as our ~~common stock~~Summarized Financial Information of the Guarantors is not materially different from our consolidated financial statements.

Derivatives and Hedging Activities. We seek to mitigate risks related to unfavorable changes in natural gas, oil and NGL prices, which are subject to significant and often volatile fluctuation, by entering into over-the-counter fixed price swaps, basis swaps, collars and various types of option contracts. These contracts allow us to mitigate the ~~foreseeable future. In addition, the terms~~impact of declines in future natural gas, oil and NGL prices by effectively locking in floor price for a certain level of our ~~credit agreement prohibit~~production. However, these hedge contracts also limit the ~~payment~~benefit to us in periods when the future market prices of ~~any dividends to~~natural gas, oil and NGL that are higher than the ~~holders of our common stock.~~

There is no guarantee that we will repurchase shares of our common stock under our recently announced stock repurchase program at a level anticipated by our stockholders, which could reduce returns to our stockholders. Decisions to repurchase our common stock will be at the discretion of our board of directors based upon a review of relevant considerations.

In January 2018, our board of directors approved a stock repurchase program to acquire up to $100.0 million of our outstanding common stock, and in May 2018 expanded this program to acquire up to an additional $100.0 million of our common stock during 2018 for a total of up to $200.0 million. This repurchase program was authorized to extend through December 31, 2018 and was fully executed 2018. In January 2019, our board of directors approved a new stock repurchase program to acquire up to $400.0 million of our outstanding common stock within the next 24 months. The repurchase program does not require us to acquire any specific number of shares. From January 1, 2019 through February 28, 2019, we did not repurchase any shares of our common stock under our new stock repurchase program. An aggregate of $400.0 million remains available for future stock repurchases under our new stock repurchase program. Our board of director’s determination to repurchase shares of our common stock under our new stock repurchase program will depend upon market conditions, applicable legal requirements, contractual obligations and other factors that the board of directors deems relevant. Based on an evaluation of these factors, our board of directors may determine not to repurchase shares or to repurchase shares at reduced levels from those anticipated by our stockholders, any or all of which could reduce returns to our stockholders.

~~A change of control could limit our use of net operating losses.~~hedged prices.

As of December 31, ~~2018,~~2020, we had ~~a net operating loss,~~the following open natural gas derivative instruments (we had no oil or NOL, carry forward of approximately $782.7 million for federal income tax purposes. If we were to experience an “ownership change,” as determined under Section 382 of the Code, our ability to offset taxable income arising after the ownership change with NOLs generated prior to the ownership change would be limited, possibly substantially. In general, an ownership change would establish an annual limitation on the amount of our pre-change NOLs we could utilize to offset our taxable incomeNGL derivative instruments in any future taxable year to an amount generally equal to the value of our stock immediately prior to the ownership change multiplied by the long-term tax-exempt rate. In general, an ownership change will occur if there is a cumulative increase in our ownership of more than 50 percentage points by one or more “5% shareholders” (as defined in the Internal Revenue Code) at any time during a rolling three-year period.place):

~~Future sales of our common stock may depress our stock price.~~



Year	Type of Derivative Instrument	Index	Daily Volume (MMBtu/day)	Weighted Average Price
2021	Swaps	NYMEX Henry Hub	410,000	$2.75
2021	Basis Swaps	Rex Zone 3	35,000	$(0.21)
2021	Costless Collars	NYMEX Henry Hub	250,000	$2.46/$2.81
2021	Basis Swaps	Tetco M2	60,000	$(0.67)
2022	Sold Call Options	NYMEX Henry Hub	153,000	$2.90
2022	Costless Collars	NYMEX Henry Hub	20,000	$2.80/$3.40
2023	Sold Call Options	NYMEX Henry Hub	628,000	$2.90

We have registered a substantial number of shares of our common stock under a registration statement filed with the SEC for resale by certain of our stockholders. Sales of these or other shares of our common stock in the public market or the perception that these sales may occur, could cause the market price of our common stock to decline. In addition, sales by certain of our stockholders of their shares could impair our ability to raise capital through the sale of common or preferred stock. As of February 18, 2019, there were 162,986,045 shares of our common stock issued and outstanding, excluding 1,534,688 shares of unvested restricted stock awarded under our Amended and Restated 2005 Stock Incentive Plan.

See ~~Table of Contents~~

~~Index to Financial Statements~~

We could issue preferred stock which could be entitled to dividend, liquidation and other special rights and preferences not shared by holders of our common stock or which could have anti-takeover effects.

We are authorized to issue up to 5,000,000 shares of preferred stock, par value $0.01 per share. Shares of preferred stock may be issued from time to time in one or more series as our board of directors, by resolution or resolutions, may from time to time determine each such series to be distinctively designated. The voting powers, preferences and relative, participating, optional and other special rights, and the qualifications, limitations or restrictions, if any, of each such series of preferred stock may differ from those of any and all other series of preferred stock at any time outstanding, and, subject to certain limitations of our certificate of incorporation and the Delaware General Corporation Law, or DGCL, our board of directors may fix or alter, by resolution or resolutions, the designation, number, voting powers, preferences and relative, participating, optional and other special rights, and qualifications, limitations and restrictions thereof, of each such series preferred stock. The issuance of any such preferred stock could materially adversely affect the rights of holders of our common stock and, therefore, could reduce the value of our common stock.

In addition, specific rights granted to future holders of preferred stock could be used to restrict our ability to merge with, or sell our assets to, a third party. The ability of our board of directors to issue preferred stock could discourage, delay or prevent a takeover of us, thereby preserving control of the company by the current stockholders.

The existence of some provisions in our organizational documents could delay or prevent a change in control of our company, even if that change would be beneficial to our stockholders. Our certificate of incorporation and bylaws contain provisions that may make acquiring control of our company difficult.



~~ITEM 1B.~~	~~UNRESOLVED STAFF COMMENTS~~

~~None.~~



~~ITEM 2.~~	~~PROPERTIES~~

~~Additional information regarding our properties is included in Item 1. "Business" above and in~~ Note 313 of the notes to our consolidated financial statements included in Item 8 of this report ~~which information is incorporated herein by reference.~~

~~Proved Oil~~for further discussion of derivatives and ~~Natural Gas Reserves~~

~~Evaluation and Review of Reserves.~~

Reserve estimates at December 31, 2018 were prepared by NSAI with respect to our assets in the Utica Shale in Eastern Ohio (71% of our proved reserves at December 31, 2018), the SCOOP Woodford and SCOOP Springer plays in Oklahoma (29% of our proved reserves at December 31, 2018), our WCBB, Hackberry and Niobrara fields, as well as our overriding royalty and non-operated interests (less than 1% of our proved reserves at December 31, 2018). Reserve estimates at December 31, 2017 were prepared by NSAI with respect to our assets in the Utica Shale in Eastern Ohio, the SCOOP Woodford and SCOOP Springer plays in Oklahoma and our WCBB and Hackberry fields. Reserve estimates at December 31, 2016 were prepared by NSAI with respect to our assets in the Utica Shale in Eastern Ohio and our WCBB and Hackberry fields. Our personnel prepared reserve estimates with respect to our Niobrara field as well as our overriding royalty and non-operated interests at December 31, 2017 and 2016.

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 relating to our assets in the Utica Shale, SCOOP, WCBB and Hackberry fields. 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

hedging activities.

Table of Contents

Index to Financial ~~Statements~~Statement

and status of permits. Our proved reserves attributable to our other minority interests are prepared internally by our internal staff of petroleum engineers and geoscience professionals. 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 over 100 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 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.

~~The following table sets forth our estimated proved reserves at December 31, 2018, 2017 and 2016:~~

Year Ended December 31,
2018 2017 2016

Oil
(MBbls)

Natural
Gas
(MMcf)
Natural Gas Liquids (MBbls)
Oil
(MBbls)

Natural
Gas
(MMcf)
Natural Gas Liquids (MBbls)
Oil
(MBbls)

Natural
Gas
(MMcf)
Natural Gas Liquids (MBbls)
Proved developed 9,570
1,813,184
40,810
10,245
1,616,930
36,247
4,882
744,797
14,299
Proved undeveloped 11,480
2,320,705
39,710
8,912
3,208,380
39,519
664
1,422,271
5,828
Total (1) 21,050
4,133,889
80,520
19,157
4,825,310
75,766
5,546
2,167,068
20,127

Year Ended December 31,
2018 2017 2016
Total net proved oil and natural gas reserves (MMcfe) (1) 4,743,311
5,394,851
2,321,108
PV-10 value (in millions) (2) $ 3,407.3
$ 2,883.0
$ 696.0
Standardized measure (in millions) (3) $ 2,982.7
$ 2,643.6
$ 688.0

~~_____________________~~


~~(1)~~	Estimates of reserves as of year-end 2018, 2017 and 2016 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-

~~Table of Contents~~s

~~Index to Financial Statements~~

month period ended December 31, 2018, 2017 and 2016, respectively, in accordance with revised guidelines of the SEC applicable to reserves estimates as of year-end 2018, 2017 and 2016. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

~~(2)~~

Represents present value, discounted at 10% per annum, of estimated future net revenue before income tax of our estimated proven reserves. The estimated future net revenues set forth above were determined by using reserve quantities of proved reserves and the periods in which they are expected to be developed and produced based on certain prevailing economic conditions. The estimated future production in our reserve reports for the years ended December 31, 2018, 2017 and 2016 is priced based on the 12-month unweighted arithmetic average of the first-day-of-the month price for the period January through December of the applicable year, using $65.56 per barrel and $3.10 per MMBtu for 2018, $51.34 per barrel and $2.98 per MMBtu for 2017 and $42.75 per barrel and $2.48 per MMBtu for 2016, and in each case adjusted by lease for transportation fees and regional price differentials.

PV-10 is a non-GAAP measure because it excludes income tax effects. Management believes that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. PV-10 is not a measure of financial or operating performance under GAAP. PV-10 should not be considered as an alternative to the standardized measure as defined under GAAP. We have included a reconciliation of PV-10 to the most directly comparable GAAP measure-standardized measure of discounted future net cash flows.

~~The following table reconciles the standardized measure of future net cash flows to the PV-10 value:~~

December 31,
2018 2017 2016
(In thousands)
Standardized measure of discounted future net cash flows $ 2,982,725
$ 2,643,564
$ 688,040
Add: Present value of future income tax discounted at 10% 424,596
239,468
7,927
PV-10 value $ 3,407,321
$ 2,883,032
$ 695,967

~~(3)~~

The standardized measure represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, abandonment, production, and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.

~~The above table does not include proved reserves net to our interest in Tatex II, Tatex III or Grizzly. For further discussion of our interest in Tatex II, Tatex III and Grizzly, see Item 1. “Business–Our Equity Investments~~.”

As noted above, our December 31, 2018 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 2018 of $65.56 per barrel and $3.10 per MMBtu. Holding production and development costs constant, if our 2018 reserves were calculated using the December 31, 2018 price of $45.41 per barrel and $2.94 per MMBtu, our discounted future net cash flows before income taxes would have been approximately $2.5 billion, or $0.9 billion less than our actual PV-10 value of $3.4 billion at December 31, 2018.

~~The table below provides the 2018 SEC pricing of benchmark prices as well as the unweighted average of the months ended December 31, 2018 and January 31, 2019:~~

SEC Pricing 2018 2-month Average 2019
Henry Hub Natural Gas (per MMBtu) $ 3.10
$ 3.90
WTI Crude Oil (per Bbl) $ 65.56
$ 48.17

The foregoing reserves are all located within the continental United States. 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

~~Table of Contents~~

~~Index to Financial Statements~~

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 2018.~~

~~The following table summarizes the changes in our estimated proved reserves during 2018 (in Bcfe):~~



~~Proved Reserves, December 31, 2017~~	~~5,395~~
~~Sales of oil and gas reserves in place~~	~~(45~~	)
~~Extensions and discoveries~~	~~711~~
~~Revisions of prior reserve estimates~~	~~(821~~	)
~~Current production~~	~~(497~~	)
~~Proved Reserves, December 31, 2018~~	~~4,743~~

~~Sales of oil and natural gas reserves in place.~~ These are revisions to proved reserves resulting from the divestiture of minerals in place during a period. During 2018, we sold approximately 44.9 Bcfe of proved oil and natural gas reserves through various sales of non-operated interests in both our Utica and SCOOP fields.

~~Extensions and discoveries.~~ These are additions to our proved reserves that result from (i) extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery and (ii) discovery of new fields with proved reserves or of new reservoirs of proved reserves in existing fields. Extensions and discoveries of approximately 711.2 Bcfe of proved reserves were primarily attributable to the continued development of our Utica Shale and SCOOP acreage. We added 76 locations in our Utica field, 59 locations in our SCOOP field and 13 new locations in our Southern Louisiana fields. Total extensions and discoveries of approximately 569.8 Bcfe were attributed to our Utica field, which was primarily a result of our current development plan which refocuses development within our existing fields. This change reflects our ongoing efforts to optimize the development program with well selection based on economic returns, commodity mix and surface considerations.

~~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 downward revisions of approximately 1.0 Tcfe in estimated proved reserves with the exclusion of 127 PUD locations in our Utica field and 12 PUD locations in our SCOOP field, which was primarily a result of changes in our schedule which moved development of these PUD locations beyond five years of initial booking. The development plan change, as approved by our senior management and board of directors, is a result of continued focus on free cash flow generation, thereby reducing the number of wells included in our development plan. This downward revision was partially offset by upward revisions of approximately 82.4 Bcfe in estimated proved reserves in 2018 due to changes in wellbore lateral length, 67.6 Bcfe due to changes in ownership interest, 27.9 Bcfe due to an increase in pricing and 8.3 Bcfe due to changes in our well performance.

While commodity prices experienced volatility throughout 2018, the 12-month average price for natural gas increased from $2.98 per MMBtu for 2017 to $3.10 per MMBtu for 2018, the 12-month average price for NGLs increased from $18.40 per barrel for 2017 to $32.02 per barrel for 2018, and the 12-month average price for crude oil increased from $51.34 per barrel for 2017 to $65.56 per barrel for 2018.

Additional information regarding estimates of proved reserves, proved developed reserves and proved undeveloped reserves at December 31, 2018, 2017 and 2016 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 to our consolidated financial statements included in this report.~~

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~~Index to Financial Statements~~

~~Proved Undeveloped Reserves (PUDs)~~

As of December 31, 2018, our proved undeveloped reserves totaled 11,480 MBbls of oil, 2,320,705 MMcf of natural gas and 39,710 MBbls of NGLs, for a total of 2,627,845 MMcfe. Approximately 68% and 32% of our PUDs at year-end 2018 were located in our Utica field and our SCOOP field, 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.

The current development plan approved by our senior management and board of directors represents a decrease in drilling activity from our previous plans with a focus on free cash flow generation. As a result, drilling of certain previously booked PUD locations in both our Utica and SCOOP development plans has been extended beyond five years of initial booking. This change was not a result of well performance or economics.

~~The following table summarizes the changes in our estimated proved undeveloped reserves during 2018 (in Bcfe):~~



~~Proved Undeveloped Reserves, December 31, 2017~~	~~3,499~~
~~Sales of oil and natural gas reserves in place~~	~~(45~~	)
~~Extensions and discoveries~~	~~649~~
~~Conversion to proved developed reserves~~	~~(576~~	)
~~Revisions of prior reserve estimates~~	~~(899~~	)
~~Proved Undeveloped Reserves, December 31, 2018~~	~~2,628~~

~~Sales of oil and natural gas reserves in place.~~ ~~During 2018, we sold approximately 44.9 Bcfe of proved undeveloped oil and natural gas reserves associated with various non-operated interests, the majority of which were in our Utica field.~~

~~Extensions and discoveries.~~ Our extensions and discoveries of approximately 649.4 Bcfe were primarily attributed to the addition of 75 PUD locations in the Utica field and 11 PUD locations in the SCOOP field as a result of our current development plan that refocused some activity within our existing fields. This change reflects our ongoing efforts to optimize the development program with well selection based on economic returns, commodity mix and surface considerations.

~~Conversion to proved developed reserves.~~ We converted approximately 575.9 Bcfe attributable to 62 PUD locations into proved developed reserves and 16 PUD locations into proved developed not producing. These 78 PUDs represent a conversion rate of 18% for 2018.

~~Revision of prior reserve estimates.~~ We experienced negative revisions of approximately 1.0 Tcfe from the exclusion of 127 PUD locations in our Utica field and 12 PUD locations in our SCOOP field, which were primarily a result of changes in our development plan which moved development of these PUD locations beyond five years of initial booking. The development plan change, as approved by our senior management and board of directors, is a result of a focus on free cash flow generation. This negative revision was partially offset by positive revisions of 82.4 Bcfe in estimated proved reserves in 2018 due to changes in wellbore lateral length and 26.3 Bcfe due to change in our ownership interest.

~~Costs incurred relating to the development of PUDs were approximately $370.3 million in 2018.~~

~~All PUD drilling locations included in our 2018 reserve report are scheduled to be drilled within five years of initial booking.~~

~~As of December 31, 2018, 1% of our total proved reserves were classified as proved developed non-producing.~~

~~Table of Contents~~

~~Index to Financial Statements~~

As noted above, our December 31, 2018 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 2018 of $65.56 per barrel and $3.10 per MMBtu. Holding production and development costs constant, if SEC pricing were $50.00 per barrel and $2.50 per MMBtu, this would have resulted in a loss of 1.3 Tcfe of our PUD volumes at December 31, 2018. Holding production and development costs constant, if SEC pricing were $40.00 per barrel and $2.00 per MMBtu, this would have resulted in a loss of 2.3 Tcfe of our PUD volumes at December 31, 2018.

~~Production, Prices and Production Costs~~

~~The following table presents our production volumes, average prices received and average production costs during the periods indicated:~~

~~Table of Contents~~

~~Index to Financial Statements~~

2018 2017 2016
($ In thousands)
Natural gas sales
Natural gas production volumes (MMcf) 443,742
350,061
227,594

Total natural gas sales $ 1,121,815
$ 845,999
$ 420,128

Natural gas sales without the impact of derivatives ($/Mcf) $ 2.53
$ 2.42
$ 1.85
Impact from settled derivatives ($/Mcf) $ (0.04 ) $ 0.07
$ 0.60
Average natural gas sales price, including settled derivatives
($/Mcf)
$ 2.49
$ 2.49
$ 2.45

Oil and condensate sales
Oil and condensate production volumes (MBbls) 2,801
2,579
2,126

Total oil and condensate sales $ 177,793
$ 124,568
$ 81,173

Oil and condensate sales without the impact of derivatives ($/Bbl) $ 63.48
$ 48.29
$ 38.18
Impact from settled derivatives ($/Bbl) $ (9.51 ) $ 1.59
$ 5.11
Average oil and condensate sales price, including settled derivatives ($/Bbl) $ 53.97
$ 49.88
$ 43.29

Natural gas liquids sales
Natural gas liquids production volumes (MGal) 251,720
224,038
161,562

Total natural gas liquids sales $ 178,915
$ 136,057
$ 59,115

Natural gas liquids sales without the impact of derivatives ($/Gal) $ 0.71
$ 0.61
$ 0.37
Impact from settled derivatives ($/Gal) $ (0.05 ) $ (0.03 ) $ (0.01 )
Average natural gas liquids sales price, including settled derivatives ($/Gal) $ 0.66
$ 0.58
$ 0.36

Natural gas, oil and condensate and natural gas liquids sales
Natural gas equivalents (MMcfe) 496,505
397,543
263,430

Total natural gas, oil and condensate and natural gas liquids sales $ 1,478,523
$ 1,106,624
$ 560,416

Natural gas, oil and condensate and natural gas liquids sales without the impact of derivatives ($/Mcfe) $ 2.98
$ 2.78
$ 2.13
Impact from settled derivatives ($/Mcfe) $ (0.12 ) $ 0.07
$ 0.56
Average natural gas, oil and condensate and natural gas liquids sales price, including settled derivatives ($/Mcfe) $ 2.86
$ 2.85
$ 2.69

Production Costs:
Average production costs ($/Mcfe) $ 0.18
$ 0.20
$ 0.26
Average production taxes ($/Mcfe) $ 0.07
$ 0.05
$ 0.05
Average midstream gathering and processing ($/Mcfe) $ 0.58
$ 0.63
$ 0.63
Total production costs, midstream costs and production taxes ($/Mcfe) $ 0.83
$ 0.88
$ 0.94

~~Table of Contents~~

~~Index to Financial Statements~~

Year Ended December 31,
2018 2017 2016
Utica Shale
Net Production
Oil (MBbls) 299
473
870
Natural gas (MMcf) 379,417
309,450
227,447
NGL (Mgal) 113,379
139,634
161,494
Total (MMcfe) 397,406
332,238
255,740
Average Sales Price Without the Impact of Derivatives:
Oil ($/Bbl) $ 60.22
$ 44.26
$ 34.59
Natural gas ($/Mcf) $ 2.50
$ 2.38
$ 1.85
NGL ($/Gal) $ 0.67
$ 0.60
$ 0.37
Average Production Costs ($/Mcfe) $ 0.14
$ 0.15
$ 0.18

Year Ended December 31,
2018 2017 (1)
SCOOP
Net Production
Oil (MBbls) 1,710
1,083
Natural gas (MMcf) 64,258
40,501
NGL (Mgal) 138,261
84,283
Total (MMcfe) 94,268
59,038
Average Sales Price Without the Impact of Derivatives:
Oil ($/Bbl) $ 62.36
$ 48.70
Natural gas ($/Mcf) $ 2.67
$ 2.68
NGL ($/Gal) $ 0.75
$ 0.62
Average Production Costs ($/Mcfe) $ 0.20
$ 0.19

~~(1) We acquired our SCOOP assets in our SCOOP acquisition completed on February 17, 2017.~~

~~Productive Wells and Acreage~~

~~Table of Contents~~

~~Index to Financial Statements~~

Average NRI/WI (1)
Productive
Oil Wells

Productive
Gas Wells

Non-Productive
Oil Wells

Non-Productive
Gas Wells

Developed
Acreage (2)

Undeveloped
Acreage
Field Percentages Gross Net Gross Net Gross Net Gross Net Gross Net Gross Net
Utica Shale (3) 44.26/54.44 74
36.14
493
271.86
3
2.66
2
1.57
92,594
72,693
148,417
136,839
SCOOP (4) 24.34/30.20 110
18.58
466
154.69
3
2.59
30
25.24
48,658
34,532
17,625
15,517
West Cote Blanche Bay Field (5) 80.108/100 69
69
—
—
146
146
—
—
5,668
5,668
—
—
E. Hackberry Field (6) 82.33/100 14
14
—
—
130
130
—
—
2,910
2,910
1,206
1,206
W. Hackberry Field 87.50/100 2
2
—
—
7
7
—
—
727
727
306
306
Niobrara Formation (7) 34.52/48.61 3
1.46
—
—
—
—
—
—
1,998
999
3,816
1,908
Bakken Formation (8) 1.51/1.83 18
0.3
—
—
—
—
—
—
386
77
3,505
701
Overrides/Royalty Non-operated Various 673
0.9
—
—
—
—
—
—
—
—
—
—
Total 963
142.38
959
426.55
289
288.25
32
26.81
152,941
117,606
174,875
156,477


~~(1)~~	~~Net Revenue Interest (NRI)/Working Interest (WI).~~


~~(2)~~	~~Developed acres are acres spaced or assigned to productive wells. Approximately 43% of our acreage is developed acreage and has been perpetuated by production.~~

~~(3)~~

With respect to our total undeveloped Utica Shale acreage as of December 31, 2018, leases representing 11%, 10%, 9% and 32% are currently scheduled to expire in 2019, 2020, 2021 and thereafter, respectively. Our Utica Shale leases generally grant us the right to extend these leases for an additional five-year period. NRI/WI is from wells that have been drilled or in which we have elected to participate. Includes 216 gross (38.12 net) gas wells and 29 gross (3.32 net) oil wells drilled by other operators on our acreage.

(4) With respect to our total undeveloped SCOOP acreage as of December 31, 2018, leases representing 53%, 5% and 1% are currently scheduled to expire in 2019, 2020 and 2021, respectively. NRI/WI is from wells that have been drilled or in which we have elected to participate. Includes 296 gross (22.20 net) gas well and 96 gross (7.82 net) oil 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.~~

~~(7)~~

The leases relating to our Niobrara Formation acreage will expire at the end of their respective primary terms unless the applicable leases are renewed or extended, we have commenced the necessary operations required by the terms of the applicable leases or we have obtained actual production from acreage subject to the applicable leases, in which event they will remain in effect until the cessation of production. Leases representing 66% of our total Niobrara undeveloped acreage are currently scheduled to expire in 2019 .


~~(8)~~	~~NRI/WI is from wells that have been drilled or in which we have elected to participate.~~

~~Completed and Present Drilling and Recompletion Activities~~

The following table sets forth information with respect to operated wells completed 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, whether or not they produce a reasonable rate of return.

~~Table of Contents~~

~~Index to Financial Statements~~

2018 2017 2016
Gross Net Gross Net Gross Net
Recompletions:
Productive 47
47
81
81
77
77
Dry —
—
—
—
—
—
Total 47
47
81
81
77
77
Development:
Productive 34
30
124
115.4
49
42.5
Dry —
—
2
2
1
1.0
Total 34
30
126
117.4
50
43.5
Exploratory:
Productive 2
1.5
—
—
—
—
Dry —
—
—
—
—
—
Total 2
1.5
—
—
—
—

~~Title to Oil and Natural Gas Properties~~

It is customary in the oil and natural gas industry to make only a cursory 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.



~~ITEM 3.~~	~~LEGAL PROCEEDINGS~~

In two separate complaints, one filed by the State of Louisiana and the Parish of Cameron in the 38th Judicial District Court for the Parish of Cameron on February 9, 2016 and the other filed by the State of Louisiana and the District Attorney for the 15^th ~~Judicial District of the State of Louisiana in the 15~~^th Judicial District Court for the Parish of Vermilion on July 29, 2016, we were named as a defendant, among 26 oil and gas companies, in the Cameron Parish complaint and among more than 40 oil and gas companies in the Vermilion Parish complaint, or the Complaints. The Complaints were filed under the State and Local Coastal Resources Management Act of 1978, as amended, and the rules, regulations, orders and ordinances adopted thereunder, which we referred to collectively as the CZM Laws, and allege that certain of the defendants’ oil and gas exploration, production and transportation operations associated with the development of the East Hackberry and West Hackberry oil and gas fields, in the case of the Cameron Parish complaint, and the Tigre Lagoon oil and gas field, in the case of the Vermilion Parish complaint, were conducted in violation of the CZM Laws. The Complaints allege that such activities caused substantial damage to land and waterbodies located in the coastal zone of the relevant Parish, including due to defendants’ design, construction and use of waste pits and the alleged failure to properly close the waste pits and to clear, re-vegetate, detoxify and return the property affected to its original condition, as well as the defendants’ alleged discharge of waste into the coastal zone. The Complaints also allege that the defendants’ oil and gas activities have resulted in the dredging of numerous canals, which had a direct and significant impact on the state coastal waters within the relevant Parish and that the defendants, among other things, failed to design, construct and maintain these canals using the best practical techniques to prevent bank slumping, erosion and saltwater intrusion and to minimize the potential for inland movement of storm-generated surges, which activities allegedly have resulted in the erosion of marshes and the degradation of terrestrial and aquatic life therein. The Complaints also allege that the defendants failed to re-vegetate, refill, clean, detoxify and otherwise restore these canals to their original condition. In these two petitions, the plaintiffs seek damages and other appropriate relief under the CZM Laws, including the payment of costs necessary to clear, re-vegetate, detoxify and otherwise restore the affected coastal zone of the relevant Parish to its original condition, actual restoration of such coastal zone to its original condition, and the payment of reasonable attorney fees and legal expenses and pre-judgment and post judgment interest.

We were served with the Cameron complaint in early May 2016 and with the Vermilion complaint in early September 2016. The Louisiana Attorney General and the Louisiana Department of Natural Resources intervened in both the Cameron Parish suit and the Vermilion Parish suit. Shortly after the Complaints were filed, certain defendants removed the cases to the United States District Court for the Western District of Louisiana. In both cases, the plaintiffs filed motions to remand the

~~Table of Contents~~

~~Index to Financial Statements~~

lawsuits to state court, which were ultimately granted by the district courts. However, on May 23, 2018, a group of defendants again removed the Cameron Parish and Vermilion Parish lawsuits to federal court. In response, the plaintiffs again filed motions to remand the cases to state court. The removing defendants have opposed plaintiffs' motions to remand. On January 16, 2019, the federal district court held a hearing on plaintiff's motion to remand. The court took the matter under advisement and has not yet issued a ruling. Further action in the cases will be stayed until the courts rule on the motions to remand. Also, shortly after the May 23, 2018 removal, the removing defendants filed motions with the United States Judicial Panel on Multidistrict Litigation, or the MDL Panel, requesting that the Cameron Parish and Vermilion Parish lawsuits be consolidated with 40 similar lawsuits so that pre-trial proceedings in the cases could be coordinated. The MDL Panel denied the motion to consolidate the lawsuits. Due to the procedural posture of the lawsuits, the cases are still in their early stages and the parties have conducted very little discovery. As a result, we have not had the opportunity to evaluate the applicability of the allegations made in plaintiffs' complaints to our operations and management cannot determine the amount of loss, if any, that may result.

In addition, due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities. While the outcome of the pending litigation, disputes or claims cannot be predicted with certainty, in the opinion of our management, none of these matters, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.



~~ITEM 4.~~	~~MINE SAFETY DISCLOSURES~~

~~Not applicable.~~

~~PART II~~



~~ITEM 5.~~	~~MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES~~

~~Price Range of Common Stock~~

~~Our common stock is quoted on the Nasdaq Global Select Market under the symbol “GPOR.” The following table sets forth the high and low sale prices of our common stock for the periods presented:~~

Price Range of
Common Stock
High Low
2017
First Quarter $ 22.35
$ 15.66
Second Quarter 17.82
12.47
Third Quarter 15.09
10.90
Fourth Quarter 15.08
11.73
2018
First Quarter $ 13.74
$ 8.11
Second Quarter 12.70
8.60
Third Quarter 13.41
10.07
Fourth Quarter 11.67
6.18

~~Unregistered Sales of Equity Securities and Use of Proceeds~~

~~None.~~

~~Issuer Repurchases of Equity Securities~~

~~Our common stock repurchase activity for the three months ended December 31, 2018 was as follows:~~

~~Table of Contents~~

~~Index to Financial Statements~~

Period
Total number of shares purchased⁽²⁾
Average price paid per share
Total number of shares purchased as part of publicly announced plans or programs ⁽²⁾

Approximate maximum dollar value of shares that may yet be purchased under the plans or programs ⁽¹⁾
October 2018 —
$ —
—
$ 90,003,000
November 2018 28,584
$ 8.81
—
$ 90,003,000
December 2018 10,212,483
$ 8.81
10,212,483
$ —
Total 10,241,067
$ 8.81
10,212,483



~~(1)~~		In January 2018, our board of directors approved a stock repurchase program to acquire up to $100.0 million of our outstanding common stock, and in May 2018 expanded this program authorizing us to acquire up to an additional $100.0 million of our outstanding common stock during 2018 for a total of up to $200.0 million. This repurchase program was authorized to extend through December 31, 2018 and was fully executed in December 2018.
~~(2)~~	In November 2018, we repurchased and canceled 28,584 shares at a weighted average price of $8.81 to satisfy tax withholding requirements incurred upon the vesting of restricted stock. Additionally, in December 2018, we repurchased and canceled approximately 10,212,483 shares under the repurchase program at a weighted average price of $8.81 per share.

~~In January 2019,~~Subsequent to December 31, 2020 and as of March 1, 2021, we entered into the following natural gas, oil, and NGL derivative contracts as we work toward fulfilling minimum hedging requirements as provided for in the RSA:

Period

Type of Derivative Instrument

Index

Daily Volume(1)

Weighted
Average Price

July 2021 - December 2021

Swaps

NYMEX WTI

2,250

$53.07

July 2021 - December 2021

Swaps

Mont Belvieu C3

3,100

$27.80

January 2022 - June 2022

Swaps

Mont Belvieu C3

1,000

$27.30

April 2021 - May 2021

Basis Swaps

Tetco M2

36,443

$(0.61)

February 2021 - October 2021

Basis Swaps

Rex Zone 3

94,505

$(0.22)

July 2021 - December 2021

Costless Collars

NYMEX Henry Hub

210,000

$2.67/$3.15

January 2022 - March 2022

Costless Collars

NYMEX Henry Hub

340,000

$2.82/$3.40

(1) Volume units for gas instruments are presented as MMBtu/day while oil and NGL is presented in Bbls/day.

Contractual and Commercial Obligations. The following table sets forth our ~~board of directors approved a new stock repurchase program to acquire up to $400.0 million~~contractual and commercial obligations at December 31, 2020:


	Payment due by period
Contractual Obligations	Total		2021		2022-2023		2024-2025		2026 and Thereafter
	(In thousands)
Long-term debt(1):
Principal	$	2,258,962	$	451,159	$	326,003	$	1,107,183	$	374,617
Interest(2)	518,752		184,106		212,606		121,111		929
Firm transportation and gathering contracts(3)	3,774,725		370,343		760,150		631,113		2,013,119
Operating lease liabilities(4)	342		117		195		30		—
Total contractual cash obligations(5)	$	6,552,781	$	1,005,725	$	1,298,954	$	1,859,437	$	2,388,665

_____________________

(1) The maturities of our ~~outstanding common stock within~~debt obligations and associated interest reflect their original expiration dates and do not reflect any acceleration due to any events of default pertaining to these obligations. See Note 6 of the ~~next 24 months. Our board~~notes to our consolidated financial statements included in Item 8 of ~~director’s determination to repurchase shares~~this report for a description of our ~~common stock~~long-term debt.

(2) Includes all contractual interest on amounts classified as liabilities subject to compromise, including interest accrued on Senior Notes as of the Petition Date.

(3) Our commitments under our ~~new stock repurchase program will depend upon market conditions, applicable legal requirements, contractual obligations~~firm transportation and ~~other factors that~~gathering contracts do not reflect contracts expected to be rejected through our Chapter 11 proceedings. See Note 17 of the board of directors deems relevant. Based on an evaluation of these factors, our board of directors may determine not to repurchase shares or to repurchase shares at reduced levels from those anticipated by our stockholders, any or all of which could reduce returnsnotes to our ~~stockholders.~~

~~Holders~~consolidated financial statements included in Item 8 of ~~Record~~

~~At the close of business on February 18, 2019, there were 319 stockholders of record holding 162,986,045 shares~~this report for a description of our ~~outstanding common stock. There were approximately 20,540 beneficial owners~~firm transportation and gathering contracts.

(4) See Note 10 of the notes to our consolidated financial statements included in Item 8 of this report for a description of our ~~common stock~~operating lease liabilities.

(5) This table does not include derivative liabilities or the estimated discounted cost for future abandonment of oil and natural gas properties. See Notes 13 and 4 of the notes to our consolidated financial statements included in Item 8 of this report, respectively.

~~Dividend Policy~~

~~We have never paid dividends~~financial assurance on certain firm transportation agreements. There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our common stock. We currently intend to retain all earnings to fund our operations. Therefore, we do not intend to pay any cash dividends on the common stock in the foreseeable future. In addition, the termsliquidity or availability of our ~~credit facility restrict the payment~~capital resources.

Table of ~~any dividends~~Contents

Index to ~~the holders of our common stock.~~

Financial Statement s



~~ITEM 6.~~			~~SELECTED FINANCIAL DATA~~

~~You should read the following selected consolidated financial data in conjunction with Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations”~~ ~~and the consolidated financial statements and the related notes appearing elsewhere in this report. The selected consolidated statements of operations data~~Capital Expenditures. Our capital commitments have been primarily for the ~~fiscal years ended December 31, 2018, December 31, 2017~~execution of our operations. Our capital investment strategy is focused on prudently developing our existing properties in an effort to generate sustainable cash flow considering current and ~~December 31, 2016~~forecasted commodity prices.

We continually monitor market conditions and are prepared to adjust our development program if commodity prices dictate. We believe our cash flow from operations, borrowing capacity under the ~~selected consolidated balance sheet data at December 31, 2018~~DIP Credit Facility and ~~December 31, 2017 are derived from~~cash on hand will provide sufficient liquidity during the Chapter 11 process. We expect to incur significant costs associated with our ~~audited consolidated~~ongoing Chapter 11 Cases in 2021, including fees for legal, financial ~~statements appearing elsewhere in this report. The selected consolidated statements~~and restructuring advisors to the Company, certain of ~~operations data for the fiscal years ended December 31, 2015~~our creditors and ~~December 31, 2014 and the selected consolidated balance sheet data at December 31, 2016, December 31, 2015 and December 31, 2014 are derived from~~royalty interest owners. Therefore, our audited consolidated financial statements that are not included in this report. The historical data presented below is not indicative of future results. We did not pay any cash dividends on our common stock during anyability to obtain confirmation of the ~~periods set forth~~Plan in a timely manner is critical to ensuring our liquidity is sufficient during the ~~following table.~~bankruptcy process.

~~Table~~Commodity Price Risk. The volatility of ~~Contents~~

~~Index~~the energy markets makes it extremely difficult to ~~Financial Statements~~

Fiscal Year Ended December 31,
2018 2017 2016 2015 2014
(In thousands, except share data)
Selected Consolidated Statements of Operations Data:
Revenues $ 1,355,044
$ 1,320,303
$ 385,910
$ 708,990
$ 670,762
Costs and expenses:
Lease operating expenses 91,640
80,246
68,877
69,475
52,191
Production taxes 33,480
21,126
13,276
14,740
24,006
Midstream gathering and processing 290,188
248,995
165,972
138,590
64,467
Depreciation, depletion and amortization 486,664
364,629
245,974
337,694
265,431
Impairment of oil and natural gas properties

—
—
715,495
1,440,418
—
General and administrative 56,633
52,938
43,409
41,967
38,290
Accretion expense 4,119
1,611
1,057
820
761
Acquisition expense —
2,392
—
—
—
Gain on sale of assets —
—
—
—
(11 )
962,724
771,937
1,254,060
2,043,704
445,135
Income (Loss) from Operations 392,320
548,366
(868,150 ) (1,334,714 ) 225,627
Other (Income) Expense:
Interest expense 135,273
108,198
63,530
51,221
23,986
Interest income (314 ) (1,009 ) (1,230 ) (643 ) (195 )
Litigation settlement 1,075
—
—
—
25,500
Insurance proceeds (231 ) —
(5,718 ) (10,015 ) —
Loss on debt extinguishment —
—
23,776
—
—
Gain on contribution of investments —
—
—
—
(84,470 )
Gain on sale of equity method investments (124,768 ) (12,523 ) (3,391 ) —
—
(Income) loss from equity method investments (49,904 ) 17,780
37,376
106,093
(139,434 )
Other expense (income) 698
(1,041 ) 129
(485 ) (504 )
(38,171 ) 111,405
114,472
146,171
(175,117 )
Income (Loss) from Continuing Operations before Income Taxes 430,491
436,961
(982,622 ) (1,480,885 ) 400,744
Income Tax (Benefit) Expense (69 ) 1,809
(2,913 ) (256,001 ) 153,341
Income (Loss) from Continuing Operations 430,560
435,152
(979,709 ) (1,224,884 ) 247,403
Net Income (Loss) Available to Common Stockholders $ 430,560
$ 435,152
$ (979,709 ) $ (1,224,884 ) $ 247,403
Net Income (Loss) Per Common Share—Basic: $ 2.46
$ 2.42
$ (7.97 ) $ (12.27 ) $ 2.90
Net Income (Loss) Per Common Share—Diluted: $ 2.45
$ 2.41
$ (7.97 ) $ (12.27 ) $ 2.88

~~Table of Contents~~

~~Index to Financial Statements~~

At December 31,
2018 2017 2016 2015 2014
(In thousands)
Selected Consolidated Balance Sheet Data:
Total assets $ 6,051,036
$ 5,807,752
$ 4,223,145
$ 3,334,734
$ 3,619,473
Total debt, including current maturities $ 2,087,416
$ 2,038,943
$ 1,593,875
$ 946,263
$ 703,564
Total liabilities $ 2,723,268
$ 2,706,138
$ 2,039,253
$ 1,295,897
$ 1,323,177
Stockholders’ equity $ 3,327,768
$ 3,101,614
$ 2,183,892
$ 2,038,837
$ 2,296,296



~~ITEM 7.~~	~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

The following discussion and analysis should be read in conjunction with the consolidated financial statements and related notes included elsewhere in this Annual Report on Form 10-K. This discussion contains forward-looking statements reflecting our current expectations, estimates and assumptions concerning events and financial trends that may affect ourpredict future operating results or financial position. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors, including those discussed in Item 1A. "Risk Factors” and the section entitled “Cautionary Note Regarding Forward-Looking Statements” appearing elsewhere in this Annual Report on Form 10-K.

~~Overview~~

~~We are an independent~~ oil and natural gas ~~exploration~~price movements with any certainty. During 2019, WTI prices ranged from $46.31 to $66.24 per barrel and ~~production company focused on~~ the ~~exploration, exploitation, acquisition and production~~Henry Hub spot market price of natural gas ranged from $1.75 to $4.25 per MMBtu. During 2020, WTI prices ranged from $(36.98) to $63.27 per barrel and the Henry Hub spot market price of natural gas ~~liquids and crude oil in~~ranged from $1.33 to $3.14 per MMBtu. If the United States. Our principal properties are located in the Utica Shale primarily in Eastern Ohio and the SCOOP Woodford and SCOOP Springer plans 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, an oil field services company listed on the Nasdaq Global Select Market (TUSK).

~~Prices for~~prices of oil and natural gas ~~have historically been volatile~~decline further, our operations, financial condition and ~~subject~~level of expenditures for the development of our oil and natural gas reserves may be materially and adversely affected. In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to ~~significant fluctuation in response~~make substantial downward adjustments to ~~changes in supply~~our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development activities are curtailed, full cost accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and ~~demand, market uncertainty and a variety of other factors beyond our control. During the last four years, particularly in light of the continued downturn~~natural gas properties. Reductions in commodity prices ~~we focused on operational efficiencies in an effort~~and/or our reserves could also negatively impact the borrowing base under our revolving credit facility, which could limit our liquidity and ability to ~~reduce~~fund development activities.

See Item 7A. "Quantitative and Qualitative Disclosures about Market Risk" for information regarding our overall well costs and deliver better results in a more economical manner, all while growing our production base each year. In response to current declining forward natural gas prices, we are shifting to building an organization that is focused on disciplined capital allocation,open fixed price swaps at December 31, 2020.

Cash Flow from Operating Activities. Net cash flow generation and a commitment to executing a thoughtful, clearly communicated business plan that enhances value for all of our shareholders. We plan to maximize results with the core assets in our portfolio today and focus on returns that will allow us to operate within our cash flow in 2019.

~~2018 and 2019 Year to Date Highlights~~

~~Production increased 25% to approximately 496,505 MMcfe~~provided by operating activities was $95.3 million for the year ended December 31, ~~2018~~2020 as compared to $724.0 million for 2019. This decrease was primarily the result of a decrease in cash receipts from our oil and natural gas purchasers due to a 41% decrease in net natural gas, oil and NGL sales excluding the impact of derivatives and, to a lesser extent, reorganization items related to our Chapter 11 Cases.

Divestitures. During 2020, we divested certain non-core assets and interests in operated and non-operated oil and natural gas properties for approximately ~~397,543 MMcfe~~cash proceeds of $51.0 million. Proceeds from these transactions were primarily used to repay debt and fund our development program. See Note 3 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion.

Uses of Funds. The following table presents the uses of our cash and cash equivalents for the ~~year~~years ended December 31, ~~2017.~~2020 and 2019:

Table of Contents

Index to Financial Statement s


	Years Ended December 31,
	2020		2019
	(In thousands)
Oil and Natural Gas Property Expenditures:
Drilling and completion costs	$	321,811	$	654,407
Leasehold acquisitions	18,135		39,664
Other	27,341		25,986
Total oil and natural gas property expenditures	$	367,287	$	720,057
Other Uses of Cash and Cash Equivalents

Cash paid to repurchase senior notes	22,827		138,786
Cash paid to repurchase common stock	—		30,000
Additions to other property and equipment	799		5,021
DIP credit facility financing fees	2,988		—
Other	738		720
Total other uses of cash and cash equivalents	$	27,352	$	174,527
Total uses of cash and cash equivalents	$	394,639	$	894,584

Drilling and Completion Costs. During ~~2018,~~2020, we spud 3616 gross (~~31.6~~(16 net) wells and commenced sales from 25 gross (23.8 net) wells in the Utica for a total cost of approximately $192.2 million.

During 2020, we spud 10 gross (8.4 net) and commenced sales from 4 gross (3.8 net) wells in the SCOOP for a total cost of approximately $53.9 million. In addition, 19 gross (0.05 net) wells were spud and 12 gross (0.04 net) wells were turned to sales50 ~~gross (47.8~~ ~~net) operated wells, participated in an additional~~ 68~~gross (7.5~~ ~~net) wells that were drilled~~ by other operators on our ~~Utica Shale and~~ SCOOP acreage ~~and recompleted 47 existing wells in our Southern Louisiana fields. Of our 36 new wells spud~~ during ~~2018, seven were completed as producing wells and, at year end, 29 were in various stages of completion.~~

~~Oil and natural gas revenues, before the impact of derivatives, increased 36% to $1.5 billion for the year ended December 31, 2018 from $1.1 billion for the year ended December 31, 2017.~~

~~During the year ended December 31, 2018, we reduced our unit lease operating expense by 10% to $0.18 per Mcfe from $0.20 per Mcfe during the year ended December 31, 2017.~~

~~Table of Contents~~

~~Index to Financial Statements~~

~~During the year ended December 31, 2018, we reduced our unit general and administrative expense by 15% to $0.11 per Mcfe from $0.13 per Mcfe during the year ended December 31, 2017.~~

~~During the year ended December 31, 2018, we reduced our unit midstream gathering and processing expense by 8% to $0.58 per Mcfe from $0.63 per Mcfe during the year ended December 31, 2017.~~

~~On May 1, 2018, we sold our 25% equity interest in Strike Force Midstream LLC, or Strike Force, to EQT Midstream Partners, LP for $175.0 million in cash.~~

On June 29, 2018, we sold 1,235,600 shares, and on July 30, 2018, we sold an additional 118,974 shares, of our Mammoth Energy common stock in an underwritten public offering and related partial exercise of the underwriters' option to purchase additional shares for an aggregate net proceedscost to us of approximately ~~$51.5~~$0.6 million. ~~Following the sale~~

Drilling and completion costs presented in this section reflect incurred costs while drilling and completion costs presented above in Uses of ~~these shares, we owned 9,829,548 shares, or 21.9% at December 31, 2018, of Mammoth Energy’s outstanding common stock.~~Funds section reflect cash payments for drilling and completions.

~~During 2019 (through February 15, 2019), we spud seven gross (5.3 net) wells. As of February 15, 2019, three wells were waiting on completion and four were still being drilled.~~

In January 2019, our board of directors approved a stock repurchase program to acquire up to $400.0 million of our outstanding common stock within the next 24 months, which we believe underscores the confidence we have in our business model, financial performance and asset base.

~~Critical Accounting Policies and Estimates~~Results of Operations

~~Our disc~~ussion and analysis of our financial condition and results of operations are based upon consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. We have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management. We analyze our estimates including those related to oil and natural gas properties, revenue recognition, income taxes and commitments and contingencies, and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements:

~~Oil and Natural Gas Properties~~. We use the full cost method of accounting for oil and natural gas operations. Accordingly, all costs, including non-productive costs and certain general and administrative costs directly associated with acquisition, exploration and development of oil and natural gas properties, are capitalized. Companies that use the full cost method of accounting for oil and gas properties are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book valueComparison of the oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the 12-month unweighted average of the first-day-of-the-month price for the prior twelve months, adjusted for any contract provisions or financial derivatives, if any, that hedge our oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or noncash writedown is required. Such capitalized costs, including the estimated future development costs and site remediation costs of proved undeveloped properties are depleted by an equivalent units-of-production method, converting gas to barrels at the ratio of six Mcf of gas to one barrel of oil. No gain or loss is recognized upon the disposal of oil and natural gas properties, unless such dispositions significantly alter the relationship between capitalized costs and proven oil and natural gas reserves. Oil and natural gas properties not subject to amortization consist of the cost of undeveloped leaseholds and

~~Table of Contents~~

~~Index to Financial Statements~~

~~totaled $2.9 billion at both~~Years Ended December 31, ~~2018~~2020 and December 31, ~~2017. These costs are reviewed quarterly by management for impairment, with the impairment provision included in the cost~~2019

We reported a net loss of oil and natural gas properties subject to amortization. Factors considered by management in its impairment assessment include our drilling results and those of other operators, the terms of oil and natural gas leases not held by production and available funds for exploration and development.

~~Ceiling Test~~. Companies that use the full cost method of accounting for oil and gas properties are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling (as defined in the preceding paragraph). If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or noncash writedown is required. Ceiling test impairment can give us a significant loss for a particular period; however, future depletion expense would be reduced. A decline in oil and gas prices may result in an impairment of oil and gas properties. As a result of the decline in commodity prices, we recognized a ceiling test impairment of $715.5 million$1.6 billion for the year ended December 31, ~~2016. No ceiling test impairment was recognized by us~~2020 as compared to a net loss of $2.0 billion for the ~~years~~year ended December 31, ~~2018~~2019. The graph below shows the change in the net loss from the year ended December 31, 2020 to the year ended December 31, 2019. The material changes are further discussed by category on the following pages. Some totals and ~~2017. If prices~~changes throughout below section may not sum or recalculate due to rounding.

(1) Includes lease operating expenses, taxes other than income and midstream, gathering and processing expenses.

Table of Contents

Index to Financial Statement s

Natural Gas, Oil and NGL Sales


	Years Ended December 31,
	2020		2019		change
	(In thousands, unless otherwise stated)
Natural gas (MMcf/day)

Utica production volumes	795		1,062		(25)	%
SCOOP production volumes	147		194		(24)	%
Other production volumes(3)	—		—		(64)	%
Total production volumes	943		1,255		(25)	%

Total sales	$	671,535	$	1,135,381	(41)	%

Average price without the impact of derivatives ($/Mcf)	$	1.95	$	2.48	(21)	%
Impact from settled derivatives ($/Mcf)(1)	$	0.33	$	0.23	43	%
Average price, including settled derivatives ($/Mcf)	$	2.28	$	2.71	(16)	%

Oil and condensate (MBbl/day)

Utica production volumes	1		1		59	%
SCOOP production volumes	4		4		(14)	%
Other production volumes(3)	—		1		(94)	%
Total production volumes	5		6		(18)	%

Total sales	$	62,902	$	117,937	(47)	%

Average price without the impact of derivatives ($/Bbl)	$	34.88	$	53.95	(35)	%
Impact from settled derivatives ($/Bbl)(2)	$	25.76	$	1.86	1285	%
Average price, including settled derivatives ($/Bbl)	$	60.64	$	55.81	9	%

NGL (MBbl/day)

Utica production volumes	3		5		(41)	%
SCOOP production volumes	8		9		(12)	%
Other production volumes(3)	—		—		(50)	%
Total production volumes	11		14		(22)	%

Total sales	$	66,814	$	101,448	(34)	%

Average price without the impact of derivatives ($/Bbl)	$	16.86	$	19.99	(16)	%
Impact from settled derivatives ($/Bbl)	$	(0.04)	$	2.79	(101)	%
Average price, including settled derivatives ($/Bbl)	$	16.82	$	22.78	(26)	%

Total (MMcfe/day)

Utica production volumes	820		1,095		(25)	%
SCOOP production volumes	217		274		(21)	%
Other production volumes(3)	—		6		(94)	%
Total production volumes	1,037		1,375		(25)	%

Total sales	$	801,251	$	1,354,766	(41)	%

Average price without the impact of derivatives ($/Mcfe)	$	2.11	$	2.70	(22)	%
Impact from settled derivatives ($/Mcfe)	$	0.42	$	0.24	75	%
Average price, including settled derivatives ($/Mcfe)	$	2.53	$	2.94	(14)	%

(1) In November 2020, the Company early terminated certain gas fixed price swaps 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.

(3) Includes Niobrara, Bakken and Southern Louisiana.

Table of Contents

Index to Financial Statement s

In 2020, our total unhedged natural gas, oil and NGL revenues decreased approximately $553.5 million, or 41%, as compared to 2019. A 25% decrease in total production volumes accounted for $323 million of lower natural gas, ~~liquids decline~~oil and NGL revenues. The decrease is production was primarily related to our significantly lower capital program beginning in the ~~future,~~fourth quarter of 2019 into 2020. The remainder of the decrease in natural gas, oil and NGL revenues is related to a significant decrease in the realized prices for each of our commodities as compared to 2019 realized prices driven by depressed commodity market conditions.

The total natural gas, oil and NGL volumes hedged for 2020 and 2019 represented approximately 70% and 96%, respectively, of our total sales volumes for the applicable year.

Natural Gas, Oil and NGL Derivatives


	Years Ended December 31,
	2020		2019
	($ In thousands)
Natural gas derivatives - fair value (losses) gains	$	(89,310)	$	89,576
Natural gas derivatives - settlement gains	113,075		104,874
Total gains on natural gas derivatives	23,765		194,450

Oil and condensate derivatives - fair value (losses) gains	(2,952)		2,952
Oil and condensate derivatives - settlement gains	46,462		4,083
Total gains on oil and condensate derivatives	43,510		7,035

NGL derivatives - fair value losses	(461)		(7,541)
NGL derivatives - settlement (losses) gains	(142)		14,173
Total (losses) gains on NGL derivatives	(603)		6,632

Contingent consideration arrangement - fair value (losses) gains	(1,381)		243
Total gains on natural gas, oil and NGL derivatives	$	65,291	$	208,360

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Index to Financial Statement s

Lease Operating Expenses


	Years Ended December 31,
	2020		2019		change
	($ In thousands, except per unit)
Lease operating expenses
Utica	$	40,071	$	50,832	(21)	%
SCOOP	14,156		18,249		(22)	%
Other(1)	8		4,415		(100)	%
Total lease operating expenses	$	54,235	$	73,496	(26)	%

Lease operating expenses per Mcfe
Utica	$	0.13	$	0.13	5	%
SCOOP	0.18		0.18		(3)	%
Other(1)	0.06		2.18		(97)	%
Total lease operating expenses per Mcfe	$	0.14	$	0.15	(2)	%

_____________________

(1) Includes Niobrara, Bakken and Southern Louisiana

Taxes Other Than Income


	Years Ended December 31,
	2020		2019		change
	($ In thousands, except per unit)
Production taxes	$	17,511	$	28,571	(39)	%
Property taxes	$	9,510	$	9,470	—	%
Other	$	1,488	$	2,469	(40)	%
Total Taxes other than income	$	28,509	$	40,510	(30)	%
Production taxes per Mcfe	$	0.05	$	0.06	(19)	%

The decrease in production taxes in 2020 was primarily related to a decrease in revenue and production in 2020 as compared to 2019.

Midstream Gathering and Processing Expenses


	Years Ended December 31,
	2020		2019		change
	($ In thousands, except per unit)
Midstream gathering and processing expenses	$	456,318	$	508,843	(10)	%
Midstream gathering and processing expenses per Mcfe	$	1.20	$	1.01	19	%

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Index to Financial Statement s

The decrease in midstream gathering and processing expenses in 2020 was primarily related to the 25% decrease in our production volumes. The increase in per unit midstream gathering and processing expenses in 2020 is primarily related to Utica production volumes falling below the minimum volume commitments we ~~may be required~~have on certain of our firm transportation agreements with pipeline companies and the resulting deficiency payments.

Depreciation, Depletion and Amortization


	Years Ended December 31,
	2020		2019		change
	($ In thousands, except per unit)
Depreciation, depletion and amortization of oil and gas properties	$	229,703	$	538,894	(57)	%
Depreciation, depletion and amortization of other property and equipment	$	10,041	$	11,214	(10)	%
Total Depreciation, depletion and amortization	$	239,744	$	550,108	(56)	%
Depreciation, depletion and amortization per Mcfe	$	0.63	$	1.10	(42)	%

The decrease in DD&A in 2020 was due to a decrease in the depletion rate, driven primarily by impairment charges in 2019 and 2020, which decreased the depletion base. The decrease was further ~~write down the value~~driven by an approximate 25% decrease in production.

Impairment of ~~our~~Oil and Gas Properties. During 2020, we had $1.4 billion oil and natural gas properties ~~which could negatively affect our results of operations.~~

~~Asset Retirement Obligations. We have obligations~~impairment charges related primarily to ~~remove equipment and restore land at~~ the ~~end~~continued decline in commodity prices, compared to $2.0 billion impairment charges of oil and gas ~~production operations. Our removal~~properties in 2019.

General and ~~restoration obligations are~~Administrative Expenses


	Years Ended December 31,
	2020		2019		change
	($ In thousands, except per unit)
General and administrative expenses, gross	$	95,904	$	86,854	10	%
Reimbursed from third parties	(11,567)		(11,173)		4	%
Capitalized general and administrative expenses	(25,008)		(30,139)		(17)	%
General and administrative expenses, net	$	59,329	$	45,542	30	%
General and administrative expenses, net per Mcfe	$	0.16	$	0.09	72	%

The increase in general and administrative expenses, gross in 2020 was primarily ~~associated~~due to an increase in non-recurring legal and consulting charges and compensation expense as a result of cash retention incentives paid to our employees during the third quarter of 2020. See Note 8 to our consolidated financial statements for further discussion on these cash retention incentive payments. This increase was partially offset by lower salary costs resulting from the reduction in workforce that was completed in the fourth quarter of 2019 and third quarter of 2020 as well as certain furloughs and pay reductions as discussed in the overview. The decrease in capitalized general and administrative expenses in 2020 was due to lower development activities for 2020 as compared to 2019.

~~We record~~2019, respectively. Additionally, the Company incurred charges related to financial and legal advisors engaged to assist with the evaluation of a range of liability ~~equal~~management alternatives during 2020 prior to the ~~fair value~~filing of the ~~estimated cost~~Chapter 11 Cases. While we expect to ~~retire an asset. The asset retirement liability is recorded in~~continue to incur significant financial and legal advisor fees throughout the period in which the obligation meets the definition of a liability, which is generally when the asset is placed into service. When the liability is initially recorded, we increase the carrying amount of the related long-lived asset by an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related long-lived asset. Upon settlement of the liability or the sale of the well, the liability is reversed. These liability amounts may change because of changes in asset lives, estimated costs of abandonment or legal or statutory remediation requirements.

The fair value of the liability associated with these retirement obligations is determined using significant assumptions, including current estimates of the plugging and abandonment or retirement, annual inflation ofChapter 11 process, these costs will be presented in Reorganization Items, Net in our consolidated statements of operations.

Accretion Expense. Accretion expense decreased to $3.1 million for the ~~productive life of~~2020 from $3.9 million for the asset and our risk adjusted cost to settle such obligations discounted using our credit adjusted risk free interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Revisions to the asset retirement obligation are recorded with an offsetting change to the carrying amount of the related long-lived asset, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long life of most of our oil and natural gas assets, the costs to ultimately retire these assets may vary significantly from previous estimates.

~~Oil and Gas Reserve Quantities~~. Our estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analysis demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Netherland, Sewell & Associates, Inc. has prepared reserve reports of our reserve estimates at December 31, 2018 on a well-by-well basis for our properties.

~~Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As~~2019, primarily as a result adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Our reserve estimates and the projected cash flows derived from these reserve estimates have been preparedof asset divestitures discussed in ~~accordance with the guidelines of the Securities and Exchange Commission, or SEC. The accuracy of our reserve estimates is a function of many factors including the following:~~

~~the quality and quantity of available data;~~

~~the interpretation of that data;~~

~~the accuracy of various mandated economic assumptions; and~~

~~the judgments of the individuals preparing the estimates.~~

N ote 3.

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Index to Financial ~~Statements~~Statement s

Interest Expense

~~Our proved reserve estimates~~


	Years Ended December 31,
	2020		2019
	($ In thousands, except per unit)
Interest expense on senior notes	98,528		125,687
Interest expense on pre-petition revolving credit facility	14,224		12,088
Interest expense on building loan and other	1,861		1,055
Capitalized interest	(907)		(3,372)
Interest on DIP credit facility	810		—
Amortization of loan costs	5,563		6,328
Total interest expense	$	120,079	$	141,786

Interest expense per Mcfe	$	0.32	$	0.28

Weighted average debt outstanding under revolving credit facility	$	193,182	$	161,416

The decrease in interest on senior notes in 2020 as compared to 2019 is primarily due to the Chapter 11 proceedings. As of the Petition Date, we are ~~a function~~not paying or recognizing interest expense on any of ~~many assumptions, all of which could deviate significantly from actual results. Therefore, reserve estimates may materially vary from~~our outstanding debt other than any post-petition amounts drawn on the ~~ultimate quantities of oil and natural gas eventually recovered.~~

~~Income Taxes~~. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amountsPre-Petition Revolving Credit Facility and the ~~tax basis~~DIP Credit Facility.

Gain on Debt Extinguishment. In July of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected2019, our Board of Directors authorized $100 million of cash to be ~~recovered or settled.~~used to repurchase its senior notes in the open market at discounted values to par. In December 2019, our Board of Directors increased the authorized size of the senior note repurchase program to $200 million in total. During 2020, we repurchased in the open market $73.3 million aggregate principal amount of our outstanding Senior Notes for $22.8 million in cash and recognized a $49.6 million gain on debt extinguishment. During 2019, we repurchased $190.1 aggregate principal amount of our outstanding Senior Notes for $138.8 million in cash and recognized a $48.6 million gain on debt extinguishment.

Equity Investments


	Years Ended December 31,
	2020		2019		change
	($ In thousands)

Loss (income) from equity method investments, net	$	11,055	$	210,148	(95)	%

For 2020, the loss from equity method investments stems primarily from a $10.6 million loss related to our investment in Mammoth Energy, with no impairments recorded. The ~~effect~~loss from equity method investments during 2019 was primarily the result of a change in tax rates on deferred tax assets and liabilities is recognized in income during the period the rate change is enacted. Deferred tax assets are recognized in the year in which realization becomes determinable. Quarterly, management performs a forecast of its taxable income to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established, if in management's opinion, it is more likely than not that some portion will not be realized. At December 31, 2018, a valuation allowance of $212.0$160.8 million had been established for the net deferred tax asset. On December 22, 2018, we finalized the provisional accounting for the Tax Cuts and Jobs Act, which was enacted in 2017. Further information on the tax impacts of the Tax Cut and Jobs Act is included in Note 11 of our consolidated financial statements.

~~Revenue Recognition~~. We derive almost all of our revenue from the sale of crude oil, natural gas and natural gas liquids produced from our oil and natural gas properties. Revenue is recorded in the month the product is delivered to the purchaser. We receive payment on substantially all of these sales from one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers that month and the price we will receive. Variances between our estimated revenue and actual payment received for all prior months are recorded at the end of the quarter after payment is received. Historically, our actual payments have not significantly deviated from our accruals.

~~Investments—Equity Method.~~ Investments in entities greater than 20% and less than 50% and/or investments in which we have significant influence are accounted for under the equity method. Under the equity method, our share of investees’ earnings or loss is recognized in the statement of operations.

We review our investments to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, we recognize an impairment provision. For the year ended December 31, 2016, we recognized an impairment loss related to our investment in ~~Grizzly~~Mammoth Energy and a $32.4 million impairment loss related to our investment in Grizzly. See Note 5 to our consolidated financial statements for further discussion on our equity investments.

Table of ~~approximately $23.1 million.~~Contents

~~Commitments~~Index to Financial Statement s

Reorganization Items, Net. The following table summarizes the components in reorganization items, net included in our consolidated statements of operations for the year ended December 31, 2020:


	Year Ended December 31, 2020
	(in thousands)
Adjustment for allowed claims	$	104,943
Legal and professional fees	24,905
Write off of unamortized debt issuance costs	21,956
DIP credit facility financing fees	2,988
Gain on settlement of pre-petition accounts payable	(2,433)
Reorganization items, net	$	152,359

We expect to incur significant legal and ~~Contingencies~~professional fees related to our ongoing Chapter 11 case in 2021.

Other Expense, Net


	Years Ended December 31,
	2020		2019		change
	($ In thousands)
Other expense, net	$	21,738	$	3,725	484	%

Income Taxes


	Years Ended December 31,
	2020		2019		change
	($ In thousands)
Income tax expense (benefit)	$	7,290	$	(7,563)	(196)	%

The change in income tax in 2020 is primarily the result of the recognition of a valuation allowance against a state deferred tax asset. At December 31, 2020, we had a federal net operating loss carryforward of $1.9 billion, in addition to numerous temporary differences, which gave rise to a net deferred tax asset, and a valuation allowance of $985.5 million maintained against the net deferred asset.

Liquidity and Capital Resources

Overview. ~~Liabilities~~Historically, our primary sources of capital funding and liquidity have been our operating cash flow, borrowings under our Pre-Petition Revolving Credit Facility and issuances of equity and debt securities. Our ability to issue additional indebtedness, dispose of assets or access the capital markets may be substantially limited or nonexistent during the Chapter 11 Cases and will require court approval in most instances. Accordingly, our liquidity will depend mainly on cash generated from operating activities and available funds under the DIP Credit Facility as discussed below.

Filing of the Chapter 11 Cases constituted an event of default with respect to certain of our secured and unsecured debt obligations. As a result of the Chapter 11 Cases, the principal and interest due under these debt instruments became immediately due and payable. However, the creditors are stayed from taking any action as a result of the default under Section 362 of the Bankruptcy Code.

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Index to Financial Statement s

As of December 31, 2020, we had a cash balance of $89.9 million compared to $6.1 million as of December 31, 2019, and a net working capital deficit of $100.5 million as of December 31, 2020, compared to a net working capital deficit of $145.3 million as of December 31, 2019. As of December 31, 2020, our working capital deficit includes $253.7 million of debt due in the next 12 months. Our total principal debt as of December 31, 2020 was $2.3 billion compared to $2.0 billion as of December 31, 2019. Additionally, as of December 31, 2020, we had outstanding borrowings of $157.5 million on our DIP credit facility with $105.0 million of incremental borrowing capacity. See Note 6 of the notes to our consolidated financial statements included in Item 8 of this report for ~~loss contingencies arising~~further discussion of our debt obligations, including principal and carrying amounts of our notes.

We believe our cash flow from ~~claims, assessments, litigation or~~operations, borrowing capacity under the DIP Credit Facility and cash on hand will provide sufficient liquidity during the Chapter 11 process. We expect to incur significant costs related to our ongoing Chapter 11 Cases in 2021, including fees for legal, financial and restructuring advisors to the Company, certain of our creditors and royalty interest owners. Therefore, our ability to obtain confirmation of the Plan in a timely manner is critical to ensuring our liquidity is sufficient during the bankruptcy process.

Our ability to continue as a going concern is contingent on our ability to comply with the financial and other ~~sources are recorded when it is probable that~~covenants contained in our DIP Credit Facility, the Bankruptcy Court's approval of the Plan and our ability to successfully implement the Plan and obtain exit financing, among other factors. As a ~~liability has been incurred~~result of the Bankruptcy Filing, the realization of assets and the ~~amount can be reasonably estimated. We~~satisfaction of liabilities are ~~involved in certain litigation for which~~subject to uncertainty. While operating as debtors-in-possession under Chapter 11, we may settle liabilities, subject to the ~~outcome is uncertain. Changes~~approval of the Bankruptcy Court or as otherwise permitted in the ~~certainty~~ordinary course of business (and subject to restrictions contained in the DIP Credit Facility), for amounts other than those reflected in the accompanying consolidated financial statements. Further, the Plan could materially change the amounts and classifications of assets and liabilities reported in the consolidated financial statements.

Advances under our DIP Credit Facility may be in the form of either base rate loans or eurodollar loans. The interest rate for base rate loans is equal to (1) the applicable rate of 3.50%, plus (2) the base rate. The interest rate for eurodollar loans is equal to (1) the applicable rate of 4.50%, plus (2) the highest of: (a) 1% or (b) the eurodollar rate. As of December 31, 2020, amounts borrowed under our DIP Credit Facility bore interest at the weighted average rate of 5.50%.

The DIP Credit Facility includes negative covenants that, subject to significant exceptions, limit our ability and the ability of our restricted subsidiaries to, ~~reasonably estimate a loss amount, if~~among other things, (i) create liens on assets, property revenues, (ii) make investments, (iii) incur additional indebtedness, (iv) engage in mergers, consolidations, liquidations and dissolutions, (v) sell assets, (vi) pay dividends and distributions or repurchase capital stock, (vii) cease for any ~~may result~~reason to be the operator of its properties, (viii) enter into letters of credit without prior written consent, (ix) enter into certain commodity hedging contracts except commodity hedging contracts with terms approved by the Bankruptcy Court in the ~~recognition~~hedging order or certain interest rate contracts, (x) change lines of business, (xi) engage in certain transactions with affiliates and ~~subsequent~~(xii) incur more than a certain amount in capital expenditures in any calendar month. The DIP Credit Facility includes certain customary representations and warranties, affirmative covenants and events of default, including but not limited to defaults on account of nonpayment, breaches of representations and warranties and covenants, certain bankruptcy-related events, certain events under ERISA, material judgments and a change in control. If an event of default occurs, the lenders under the DIP Credit Facility will be entitled to take various actions, including the acceleration of all amounts due under the DIP Credit Facility and all actions permitted to be taken under the loan documents or application of law. In addition, the DIP Credit Facility is subject to various other financial performance covenants, including compliance with certain financial metrics and adherence to a budget approved by our DIP Credit Facility lenders.

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Index to Financial Statement s

2020 that were not rolled up into the DIP Credit Facility will remain outstanding throughout the Chapter 11 Cases and will continue to accrue interest on amounts drawn after the Petition Date. Additionally, as of December 31, 2020, we had an aggregate of $147.5 million of letters of credit outstanding under our Pre-Petition Revolving Credit Facility. This facility is secured by substantially all of our assets. Our wholly-owned subsidiaries, excluding Grizzly Holdings and Mule Sky, guarantee our obligations under our revolving credit facility.

Advances under our Pre-Petition Revolving Credit Facility may be in the form of either base rate loans or eurodollar loans. The interest rate for base rate loans is equal to (1) the applicable rate, which ranges from 0.25% to 1.25%, plus (2) the highest of: (a) the federal funds rate plus 0.50%, (b) the rate of interest in effect for such day as publicly announced from time to time by the administrative agent as its “prime rate,” and (c) the eurodollar rate for an interest period of one month plus 1.00%. The interest rate for eurodollar loans is equal to (1) the applicable rate, which ranges from 1.25% to 2.25%, plus (2) the London interbank offered rate that appears on pages LIBOR01 or LIBOR02 of the Reuters screen that displays such rate for deposits in U.S. dollars, or, if such rate is not available, the rate as administered by ICE Benchmark Administration (or any other person that takes over administration of such rate) per annum equal to the offered rate on such other page or other service that displays an average London interbank offered rate as administered by ICE Benchmark Administration (or any other person that takes over the administration of such rate) for deposits in U.S. dollars, or, if such rate is not available, the average quotations for three major New York money center banks of whom the administrative agent shall inquire as the “London Interbank Offered Rate” for deposits in U.S. dollars. As of December 31, 2020, amounts borrowed under our revolving credit facility bore interest at the weighted average rate of 3.15%.

Senior Notes. In April 2015, we issued an aggregate of $350.0 million in principal amount of our 2023 Notes. Interest on these senior notes accrues at a rate of 6.625% per annum on the outstanding principal amount thereof, payable semi-annually on May 1 and November 1 of each year. As of December 31, 2020, after giving effect to open market repurchases of these 2023 Notes, $324.6 million principal amount remained outstanding. The 2023 Notes mature on May 1, 2023.

On October 14, 2016, we issued an aggregate of $650.0 million in principal amount of our 2024 Notes. Interest on the 2024 Notes accrues at a rate of 6.000% per annum on the outstanding principal amount thereof, payable semi-annually on April 15 and October 15 of each year. As of December 31, 2020, after giving effect to open market repurchases of these 2024 Notes, $579.6 million principal amount remained outstanding. The 2024 Notes mature on October 15, 2024.

All amounts outstanding on our Senior Notes have been classified as liabilities subject to compromise on the accompanying consolidated balance sheet as of December 31, 2020.

During the year ended December 31, 2020, we used borrowings under our revolving credit facility to repurchase in the open market approximately $73.3 million aggregate principal amount of our outstanding Notes for $22.8 million. We recognized a $49.6 million gain on debt extinguishment, which included retirement of unamortized issuance costs and fees associated with the repurchased debt.

Building Loan. On June 4, 2015, we entered into a loan for the construction of our corporate headquarters in Oklahoma City, which was substantially completed in December 2016. Interest accrues daily on the outstanding principal balance at a fixed rate of 4.50% per annum. The building loan matures on June 4, 2025. As of December 31, 2020, the total borrowings under the building loan were approximately $21.9 million, which has been classified as liabilities subject to compromise on the accompanying consolidated balance sheet as of December 31, 2020.

Supplemental Guarantor Financial Information. The 2023 Notes, 2024 Notes, 2025 Notes and 2026 Notes are guaranteed on a senior unsecured basis by all existing consolidated subsidiaries that guarantee our secured revolving credit facility or certain other debt (the “Guarantors”). The Senior Notes are not guaranteed by Grizzly Holdings or Mule Sky, LLC (the “Non-

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Index to Financial Statement s

Guarantors”). The Guarantors are 100% owned by the Parent, and the guarantees are full, unconditional, joint and several. There are no significant restrictions on the ability of the Parent or the Guarantors to obtain funds from each other in the form of a dividend or loan. The guarantees rank equally in the right of payment with all of ~~legal liabilities.~~the senior indebtedness of the subsidiary guarantors and senior in the right of payment to any future subordinated indebtedness of the subsidiary guarantors.The Senior Notes and the guarantees are effectively subordinated to all of our and the subsidiary guarantors' secured indebtedness (including all borrowings and other obligations under our amended and restated credit agreement) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated to all indebtedness and other liabilities of any of our subsidiaries that do not guarantee the Notes. Effective June 1, 2019, the Parent contributed interests in certain oil and gas assets and related liabilities to certain of the Guarantors.

~~Derivative Instruments~~

SEC Regulation S-X Rule 13-01 requires the presentation of "Summarized Financial Information" to replace the "Condensed Consolidating Financial Information" required under Rule 3-10. Rule 13-01 allows the omission of Summarized Financial Information if assets, liabilities and results of operations of the Guarantors are not materially different than the corresponding amounts presented in our consolidated financial statements. The Parent and Guarantor subsidiaries comprise our material operations. Therefore, we concluded that the presentation of the Summarized Financial Information is not required as our Summarized Financial Information of the Guarantors is not materially different from our consolidated financial statements.

Derivatives and Hedging Activities. We seek to ~~reduce our exposure~~mitigate risks related to unfavorable changes in ~~oil,~~ natural gas, oil and ~~natural gas liquids~~NGL prices, which are subject to significant and often volatile fluctuation, by entering into over-the-counter fixed price swaps, basis swaps, collars and various types of option contracts. ~~All~~These contracts allow us to mitigate the impact of declines in future natural gas, oil and NGL prices by effectively locking in floor price for a certain level of our production. However, these hedge contracts also limit the benefit to us in periods when the future market prices of natural gas, oil and NGL that are higher than the hedged prices.

As of December 31, 2020, we had the following open natural gas derivative instruments ~~are recognized as assets~~(we had no oil or liabilities in the balance sheet, measured at fair value. We estimate the fair value of all derivative instruments using industry-standard models that considered various assumptions including current market and contractual prices for the underlying instruments, implied volatility, time value, nonperformance risk, as well as other relevant economic measures.

The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. Our current commodity derivative instruments are not designated as hedges for accounting purposes. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities.

~~See Item 7. "Commodity Price Risk" for a summary of our~~NGL derivative instruments in ~~place~~place):



Year	Type of Derivative Instrument	Index	Daily Volume (MMBtu/day)	Weighted Average Price
2021	Swaps	NYMEX Henry Hub	410,000	$2.75
2021	Basis Swaps	Rex Zone 3	35,000	$(0.21)
2021	Costless Collars	NYMEX Henry Hub	250,000	$2.46/$2.81
2021	Basis Swaps	Tetco M2	60,000	$(0.67)
2022	Sold Call Options	NYMEX Henry Hub	153,000	$2.90
2022	Costless Collars	NYMEX Henry Hub	20,000	$2.80/$3.40
2023	Sold Call Options	NYMEX Henry Hub	628,000	$2.90

See Note 13 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of derivatives and hedging activities.

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Index to Financial Statement s

Subsequent to December 31, 2020 and as of March 1, 2021, we entered into the following natural gas, oil, and NGL derivative contracts as we work toward fulfilling minimum hedging requirements as provided for in the RSA:

Period

Type of Derivative Instrument

Index

Daily Volume(1)

Weighted
Average Price

July 2021 - December 2021

Swaps

NYMEX WTI

2,250

$53.07

July 2021 - December 2021

Swaps

Mont Belvieu C3

3,100

$27.80

January 2022 - June 2022

Swaps

Mont Belvieu C3

1,000

$27.30

April 2021 - May 2021

Basis Swaps

Tetco M2

36,443

$(0.61)

February 2021 - October 2021

Basis Swaps

Rex Zone 3

94,505

$(0.22)

July 2021 - December 2021

Costless Collars

NYMEX Henry Hub

210,000

$2.67/$3.15

January 2022 - March 2022

Costless Collars

NYMEX Henry Hub

340,000

$2.82/$3.40

(1) Volume units for gas instruments are presented as MMBtu/day while oil and NGL is presented in Bbls/day.

Contractual and Commercial Obligations. The following table sets forth our contractual and commercial obligations at December 31, 2020:


	Payment due by period
Contractual Obligations	Total		2021		2022-2023		2024-2025		2026 and Thereafter
	(In thousands)
Long-term debt(1):
Principal	$	2,258,962	$	451,159	$	326,003	$	1,107,183	$	374,617
Interest(2)	518,752		184,106		212,606		121,111		929
Firm transportation and gathering contracts(3)	3,774,725		370,343		760,150		631,113		2,013,119
Operating lease liabilities(4)	342		117		195		30		—
Total contractual cash obligations(5)	$	6,552,781	$	1,005,725	$	1,298,954	$	1,859,437	$	2,388,665

_____________________

(1) The maturities of our debt obligations and associated interest reflect their original expiration dates and do not reflect any acceleration due to any events of default pertaining to these obligations. See Note 6 of the notes to our consolidated financial statements included in Item 8 of this report for a description of our long-term debt.

(2) Includes all contractual interest on amounts classified as liabilities subject to compromise, including interest accrued on Senior Notes as of the Petition Date.

(3) Our commitments under our firm transportation and gathering contracts do not reflect contracts expected to be rejected through our Chapter 11 proceedings. See Note 17 of the notes to our consolidated financial statements included in Item 8 of this report for a description of our firm transportation and gathering contracts.

(4) See Note 10 of the notes to our consolidated financial statements included in Item 8 of this report for a description of our operating lease liabilities.

Off-balance Sheet Arrangements. We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, ~~2018.~~2020, our material off-balance sheet arrangements and transactions include $147.5 million in letters of credit outstanding against our revolving credit facility and $111.4 million in surety bonds issued. Both the letters of credit and surety bonds are being used as financial assurance on certain firm transportation agreements. There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital resources.

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~~RESULTS OF OPERATIONS~~Index to Financial Statement s

Capital Expenditures. Our capital commitments have been primarily for the execution of our operations. Our capital investment strategy is focused on prudently developing our existing properties in an effort to generate sustainable cash flow considering current and forecasted commodity prices.

We continually monitor market conditions and are prepared to adjust our development program if commodity prices dictate. We believe our cash flow from operations, borrowing capacity under the DIP Credit Facility and cash on hand will provide sufficient liquidity during the Chapter 11 process. We expect to incur significant costs associated with our ongoing Chapter 11 Cases in 2021, including fees for legal, financial and restructuring advisors to the Company, certain of our creditors and royalty interest owners. Therefore, our ability to obtain confirmation of the Plan in a timely manner is critical to ensuring our liquidity is sufficient during the bankruptcy process.

Commodity Price Risk. The volatility of the energy markets makes it extremely difficult to predict future oil and natural gas price movements with any certainty. During 2019, WTI prices ranged from $46.31 to $66.24 per barrel and the Henry Hub spot market price of natural gas ranged from $1.75 to $4.25 per MMBtu. During 2020, WTI prices ranged from $(36.98) to $63.27 per barrel and the Henry Hub spot market price of natural gas ranged from $1.33 to $3.14 per MMBtu. If the prices of oil and natural gas decline further, our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves may be materially and adversely affected. In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development activities are curtailed, full cost accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. Reductions in commodity prices and/or our reserves could also negatively impact the borrowing base under our revolving credit facility, which could limit our liquidity and ability to fund development activities.

See Item 7A. "Quantitative and Qualitative Disclosures about Market Risk" for information regarding our open fixed price swaps at December 31, 2020.

Cash Flow from Operating Activities. Net cash flow provided by operating activities was $95.3 million for the year ended December 31, 2020 as compared to $724.0 million for 2019. This decrease was primarily the result of a decrease in cash receipts from our oil and natural gas purchasers due to a 41% decrease in net natural gas, oil and NGL sales excluding the impact of derivatives and, to a lesser extent, reorganization items related to our Chapter 11 Cases.

Divestitures. During 2020, we divested certain non-core assets and interests in operated and non-operated oil and natural gas properties for approximately cash proceeds of $51.0 million. Proceeds from these transactions were primarily used to repay debt and fund our development program. See Note 3 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion.

Uses of Funds. The following table presents the uses of our cash and cash equivalents for the years ended December 31, 2020 and 2019:

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Index to Financial Statement s


	Years Ended December 31,
	2020		2019
	(In thousands)
Oil and Natural Gas Property Expenditures:
Drilling and completion costs	$	321,811	$	654,407
Leasehold acquisitions	18,135		39,664
Other	27,341		25,986
Total oil and natural gas property expenditures	$	367,287	$	720,057
Other Uses of Cash and Cash Equivalents

Cash paid to repurchase senior notes	22,827		138,786
Cash paid to repurchase common stock	—		30,000
Additions to other property and equipment	799		5,021
DIP credit facility financing fees	2,988		—
Other	738		720
Total other uses of cash and cash equivalents	$	27,352	$	174,527
Total uses of cash and cash equivalents	$	394,639	$	894,584

Drilling and Completion Costs. During 2020, we spud 16 gross (16 net) wells and commenced sales from 25 gross (23.8 net) wells in the Utica for a total cost of approximately $192.2 million.

During 2020, we spud 10 gross (8.4 net) and commenced sales from 4 gross (3.8 net) wells in the SCOOP for a total cost of approximately $53.9 million. In addition, 19 gross (0.05 net) wells were spud and 12 gross (0.04 net) wells were turned to sales by other operators on our SCOOP acreage during 2020 for a total cost to us of approximately $0.6 million.

Drilling and completion costs presented in this section reflect incurred costs while drilling and completion costs presented above in Uses of Funds section reflect cash payments for drilling and completions.

Results of Operations

Comparison of the Years Ended December 31, 2020 and December 31, 2019

We reported a net loss of $1.6 billion for the year ended December 31, 2020 as compared to a net loss of $2.0 billion for the year ended December 31, 2019. The ~~markets for oil~~graph below shows the change in the net loss from the year ended December 31, 2020 to the year ended December 31, 2019. The material changes are further discussed by category on the following pages. Some totals and ~~natural gas have historically been,~~changes throughout below section may not sum or recalculate due to rounding.

(1) Includes lease operating expenses, taxes other than income and ~~will continue to be, volatile. Prices for oil~~midstream, gathering and ~~natural gas may fluctuate in response to relatively minor changes in supply and demand, market uncertainty and a variety of factors beyond our control.~~processing expenses.

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Index to Financial ~~Statements~~Statement s

Natural Gas, Oil and NGL Sales

~~The following table presents our production volumes, average prices received~~


	Years Ended December 31,
	2020		2019		change
	(In thousands, unless otherwise stated)
Natural gas (MMcf/day)

Utica production volumes	795		1,062		(25)	%
SCOOP production volumes	147		194		(24)	%
Other production volumes(3)	—		—		(64)	%
Total production volumes	943		1,255		(25)	%

Total sales	$	671,535	$	1,135,381	(41)	%

Average price without the impact of derivatives ($/Mcf)	$	1.95	$	2.48	(21)	%
Impact from settled derivatives ($/Mcf)(1)	$	0.33	$	0.23	43	%
Average price, including settled derivatives ($/Mcf)	$	2.28	$	2.71	(16)	%

Oil and condensate (MBbl/day)

Utica production volumes	1		1		59	%
SCOOP production volumes	4		4		(14)	%
Other production volumes(3)	—		1		(94)	%
Total production volumes	5		6		(18)	%

Total sales	$	62,902	$	117,937	(47)	%

Average price without the impact of derivatives ($/Bbl)	$	34.88	$	53.95	(35)	%
Impact from settled derivatives ($/Bbl)(2)	$	25.76	$	1.86	1285	%
Average price, including settled derivatives ($/Bbl)	$	60.64	$	55.81	9	%

NGL (MBbl/day)

Utica production volumes	3		5		(41)	%
SCOOP production volumes	8		9		(12)	%
Other production volumes(3)	—		—		(50)	%
Total production volumes	11		14		(22)	%

Total sales	$	66,814	$	101,448	(34)	%

Average price without the impact of derivatives ($/Bbl)	$	16.86	$	19.99	(16)	%
Impact from settled derivatives ($/Bbl)	$	(0.04)	$	2.79	(101)	%
Average price, including settled derivatives ($/Bbl)	$	16.82	$	22.78	(26)	%

Total (MMcfe/day)

Utica production volumes	820		1,095		(25)	%
SCOOP production volumes	217		274		(21)	%
Other production volumes(3)	—		6		(94)	%
Total production volumes	1,037		1,375		(25)	%

Total sales	$	801,251	$	1,354,766	(41)	%

Average price without the impact of derivatives ($/Mcfe)	$	2.11	$	2.70	(22)	%
Impact from settled derivatives ($/Mcfe)	$	0.42	$	0.24	75	%
Average price, including settled derivatives ($/Mcfe)	$	2.53	$	2.94	(14)	%

(1) In November 2020, the Company early terminated certain gas fixed price swaps 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.

(3) Includes Niobrara, Bakken and ~~average production costs during the periods indicated:~~

2018 2017 2016
($ In thousands)
Natural gas sales
Natural gas production volumes (MMcf) 443,742
350,061
227,594

Total natural gas sales $ 1,121,815
$ 845,999
$ 420,128

Natural gas sales without the impact of derivatives ($/Mcf) $ 2.53
$ 2.42
$ 1.85
Impact from settled derivatives ($/Mcf) $ (0.04 ) $ 0.07
$ 0.60
Average natural gas sales price, including settled derivatives ($/Mcf) $ 2.49
$ 2.49
$ 2.45

Oil and condensate sales
Oil and condensate production volumes (MBbls) 2,801
2,579
2,126

Total oil and condensate sales $ 177,793
$ 124,568
$ 81,173

Oil and condensate sales without the impact of derivatives ($/Bbl) $ 63.48
$ 48.29
$ 38.18
Impact from settled derivatives ($/Bbl) $ (9.51 ) $ 1.59
$ 5.11
Average oil and condensate sales price, including settled derivatives ($/Bbl) $ 53.97
$ 49.88
$ 43.29

Natural gas liquids sales
Natural gas liquids production volumes (MGal) 251,720
224,038
161,562

Total natural gas liquids sales $ 178,915
$ 136,057
$ 59,115

Natural gas liquids sales without the impact of derivatives ($/Gal) $ 0.71
$ 0.61
$ 0.37
Impact from settled derivatives ($/Gal) $ (0.05 ) $ (0.03 ) $ (0.01 )
Average natural gas liquids sales price, including settled derivatives ($/Gal) $ 0.66
$ 0.58
$ 0.36

Natural gas, oil and condensate and natural gas liquids sales
Natural gas equivalents (MMcfe) 496,505
397,543
263,430

Total natural gas, oil and condensate and natural gas liquids sales $ 1,478,523
$ 1,106,624
$ 560,416

Natural gas, oil and condensate and natural gas liquids sales without the impact of derivatives ($/Mcfe) $ 2.98
$ 2.78
$ 2.13
Impact from settled derivatives ($/Mcfe) $ (0.12 ) $ 0.07
$ 0.56
Average natural gas, oil and condensate and natural gas liquids sales price, including settled derivatives ($/Mcfe) $ 2.86
$ 2.85
$ 2.69

Production Costs:
Average production costs ($/Mcfe) $ 0.18
$ 0.20
$ 0.26
Average production taxes ($/Mcfe) $ 0.07
$ 0.05
$ 0.05
Average midstream gathering and processing ($/Mcfe) $ 0.58
$ 0.63
$ 0.63
Total production costs, midstream costs and production taxes ($/Mcfe) $ 0.83
$ 0.88
$ 0.94

Southern Louisiana.

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Index to Financial ~~Statements~~Statement s

The total ~~volume~~natural gas, oil and NGL volumes hedged for ~~2018, 2017~~2020 and ~~2016~~2019 represented approximately ~~78%, 68%~~70% and ~~77%~~96%, respectively, of our total sales volumes for the applicable year.

~~From 2017~~Natural Gas, Oil and NGL Derivatives


	Years Ended December 31,
	2020		2019
	($ In thousands)
Natural gas derivatives - fair value (losses) gains	$	(89,310)	$	89,576
Natural gas derivatives - settlement gains	113,075		104,874
Total gains on natural gas derivatives	23,765		194,450

Oil and condensate derivatives - fair value (losses) gains	(2,952)		2,952
Oil and condensate derivatives - settlement gains	46,462		4,083
Total gains on oil and condensate derivatives	43,510		7,035

NGL derivatives - fair value losses	(461)		(7,541)
NGL derivatives - settlement (losses) gains	(142)		14,173
Total (losses) gains on NGL derivatives	(603)		6,632

Contingent consideration arrangement - fair value (losses) gains	(1,381)		243
Total gains on natural gas, oil and NGL derivatives	$	65,291	$	208,360

Settlement gains (losses) in the table above represent realized cash gains or losses to ~~2018,~~the instruments described in Note 13 to our ~~net equivalent gas~~consolidated financial statements. Our hedging program provided cash settlements of $159.4 million in 2020 as compared to $123.1 million in 2019.

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Index to Financial Statement s

Lease Operating Expenses


	Years Ended December 31,
	2020		2019		change
	($ In thousands, except per unit)
Lease operating expenses
Utica	$	40,071	$	50,832	(21)	%
SCOOP	14,156		18,249		(22)	%
Other(1)	8		4,415		(100)	%
Total lease operating expenses	$	54,235	$	73,496	(26)	%

Lease operating expenses per Mcfe
Utica	$	0.13	$	0.13	5	%
SCOOP	0.18		0.18		(3)	%
Other(1)	0.06		2.18		(97)	%
Total lease operating expenses per Mcfe	$	0.14	$	0.15	(2)	%

_____________________

(1) Includes Niobrara, Bakken and Southern Louisiana

The decrease in total LOE in 2020 was primarily driven by the 25% decrease in our production ~~increased 25%~~resulting from ~~397,543 MMcfe to 496,505 MMcfe primarily~~production declines from our Utica and SCOOP properties as a result of reduced development activities in addition to the ~~continued development~~divestiture of our ~~Utica Shale and SCOOP acreage. From 2016~~Southern Louisiana properties as discussed in Note 3 to ~~2017,~~ our ~~net equivalent gas production increased 51% from 263,430 MMcfe to 397,543 MMcfe primarily as~~consolidated financial statements. LOE on a result of the continued development of our Utica Shale acreage and the acquisition of our SCOOP acreage. We currently estimate that our 2019 production will be between 496,400 and 511,000 MMcfe. However, our actual production may be different due to changes in our currently anticipated drilling and recompletion activities, changing economic climate, adverse weather conditions or other unforeseen events. See Item 1A. "Risk Factors."

~~Comparison of the Years Ended December 31, 2018 and December 31, 2017~~

~~We reported net income of $430.6 million~~per unit basis was slightly lower for the year ended December 31, ~~2018~~2020 as compared to 2019 as a result of increased focus on reducing lease operating expenses within the organization as well as the divestiture of the Southern Louisiana properties which had a higher operating cost structure relative to our other assets.

Taxes Other Than Income


	Years Ended December 31,
	2020		2019		change
	($ In thousands, except per unit)
Production taxes	$	17,511	$	28,571	(39)	%
Property taxes	$	9,510	$	9,470	—	%
Other	$	1,488	$	2,469	(40)	%
Total Taxes other than income	$	28,509	$	40,510	(30)	%
Production taxes per Mcfe	$	0.05	$	0.06	(19)	%

The decrease in production taxes in 2020 was primarily related to a decrease in revenue and production in 2020 as compared to 2019.

Midstream Gathering and Processing Expenses


	Years Ended December 31,
	2020		2019		change
	($ In thousands, except per unit)
Midstream gathering and processing expenses	$	456,318	$	508,843	(10)	%
Midstream gathering and processing expenses per Mcfe	$	1.20	$	1.01	19	%

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Index to Financial Statement s

Depreciation, Depletion and Amortization


	Years Ended December 31,
	2020		2019		change
	($ In thousands, except per unit)
Depreciation, depletion and amortization of oil and gas properties	$	229,703	$	538,894	(57)	%
Depreciation, depletion and amortization of other property and equipment	$	10,041	$	11,214	(10)	%
Total Depreciation, depletion and amortization	$	239,744	$	550,108	(56)	%
Depreciation, depletion and amortization per Mcfe	$	0.63	$	1.10	(42)	%

General and Administrative Expenses


	Years Ended December 31,
	2020		2019		change
	($ In thousands, except per unit)
General and administrative expenses, gross	$	95,904	$	86,854	10	%
Reimbursed from third parties	(11,567)		(11,173)		4	%
Capitalized general and administrative expenses	(25,008)		(30,139)		(17)	%
General and administrative expenses, net	$	59,329	$	45,542	30	%
General and administrative expenses, net per Mcfe	$	0.16	$	0.09	72	%

Restructuring and Liability Management Expenses. In the third quarter of 2020 and fourth quarter of 2019, the Company announced and completed workforce reductions representing approximately 10% and 13%, respectively, of its headcount. In connection with the reduction, the Company incurred total restructuring charges of approximately $1.5 million and $4.6 million, primarily consisting of one-time employee-related termination benefits, for 2020 and 2019, respectively. Additionally, the Company incurred charges related to financial and legal advisors engaged to assist with the evaluation of a range of liability management alternatives during 2020 prior to the filing of the Chapter 11 Cases. While we expect to continue to incur significant financial and legal advisor fees throughout the Chapter 11 process, these costs will be presented in Reorganization Items, Net in our consolidated statements of operations.

Accretion Expense. Accretion expense decreased to $3.1 million for the 2020 from $3.9 million for the 2019, primarily as a result of asset divestitures discussed in N ote 3.

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Index to Financial Statement s

Interest Expense


	Years Ended December 31,
	2020		2019
	($ In thousands, except per unit)
Interest expense on senior notes	98,528		125,687
Interest expense on pre-petition revolving credit facility	14,224		12,088
Interest expense on building loan and other	1,861		1,055
Capitalized interest	(907)		(3,372)
Interest on DIP credit facility	810		—
Amortization of loan costs	5,563		6,328
Total interest expense	$	120,079	$	141,786

Interest expense per Mcfe	$	0.32	$	0.28

Weighted average debt outstanding under revolving credit facility	$	193,182	$	161,416

Equity Investments


	Years Ended December 31,
	2020		2019		change
	($ In thousands)

Loss (income) from equity method investments, net	$	11,055	$	210,148	(95)	%

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Index to Financial Statement s

Reorganization Items, Net. The following table summarizes the components in reorganization items, net ~~income~~included in our consolidated statements of ~~$435.2 million~~operations for the year ended December 31, ~~2017. This decrease~~2020:


	Year Ended December 31, 2020
	(in thousands)
Adjustment for allowed claims	$	104,943
Legal and professional fees	24,905
Write off of unamortized debt issuance costs	21,956
DIP credit facility financing fees	2,988
Gain on settlement of pre-petition accounts payable	(2,433)
Reorganization items, net	$	152,359

We expect to incur significant legal and professional fees related to our ongoing Chapter 11 case in ~~period-to-period net income was due primarily to a $41.2 million~~2021.

Other Expense, Net


	Years Ended December 31,
	2020		2019		change
	($ In thousands)
Other expense, net	$	21,738	$	3,725	484	%

The increase in ~~midstream gathering and processing expenses,~~other expense in 2020 is primarily the result of a ~~$122.0~~$16.6 million increase in depreciation, depletion and amortization expense and a $27.1 million increase in interest expense, partially offset by a $34.7 million increase in oil and natural gas revenues, a $112.2 million increase in gainloss on ~~sale of equity method investments and a $67.7 million increase in income from equity method investments for~~ the ~~year ended December 31, 2018, as compared to the year ended December 31, 2017.~~

~~Oil and Natural Gas Revenues~~. For the year ended December 31, 2018, we reported oil and natural gas revenues of $1.4 billion as compared to oil and natural gas revenues of $1.3 billion during 2017. This $34.7 million, or 3%, increase in revenues was primarily attributable to the following:

~~A $275.8 million increase in natural gas sales without the impact of derivatives due to a 27% increase in natural gas sales volumes and a 5% increase in natural gas market prices.~~

~~A $53.2 million increase in oil and condensate sales without the impact of derivatives due to a 9% increase in oil and condensate sales volumes and a 32% increase in oil and condensate market prices.~~

A $42.9 million increase in natural gas liquids sales without the impact of derivatives due to a 12% increase in natural gas liquids sales volumes and a 17% increase in natural gas liquids market prices.

~~A $337.2 million decrease in natural gas and oil sales due to an unfavorable~~ change in ~~gains and losses from derivative instruments. Of the total change, $253.9 million was due to unfavorable changes in the~~ fair value of our ~~open derivative positions in each period and $83.3 million was due~~contingent consideration agreement related to ~~an unfavorable~~the sale of our SCOOP water infrastructure assets to a third-party water service provider. See Note 15 to our consolidated financial statements for further discussion on our contingent consideration agreement.

Income Taxes


	Years Ended December 31,
	2020		2019		change
	($ In thousands)
Income tax expense (benefit)	$	7,290	$	(7,563)	(196)	%

The change in ~~settlements related to our derivative positions.~~

~~Lease Operating Expenses~~. Lease operating expenses, or LOE, not including production taxes increased to $91.6 million for the year ended December 31, 2018 from $80.2 million for the year ended December 31, 2017. This increase was mainly the result of an increaseincome tax in expenses related to overhead, water hauling and disposal and ad valorem taxes, partially offset by decreases in road, location and equipment repairs, surface rentals and compression. However, due to increased efficiencies and a 25% increase in our production volumes for the year ended December 31, 2018 as compared to the year ended December 31, 2017, our per unit LOE decreased by 10% from $0.20 per Mcfe to $0.18 per Mcfe.

~~Production Taxes~~. Production taxes increased to $33.5 million for the year ended December 31, 2018 from $21.1 million for 2017. This increase was primarily related to an increase in realized prices and production volumes.

~~Midstream Gathering and Processing Expenses. Midstream gathering and processing expenses increased by $41.2 million to $290.2 million for the year ended December 31, 2018 from $249.0 million for 2017. This increase was~~2020 is primarily the result of ~~midstream expenses related to our increased production volumes in~~ the ~~Utica Shale and SCOOP resulting from our 2018 and 2017 drilling activities.~~

~~Depreciation, Depletion and Amortization. Depreciation, depletion and amortization, or DD&A, expense increased to $486.7 million for the year ended~~recognition of a valuation allowance against a state deferred tax asset. At December 31, ~~2018, and consisted of $476.4 million in depletion of oil and natural gas properties and $10.3 million in depreciation of other property and equipment, as compared to total DD&A expense of $364.6~~

~~Table of Contents~~

~~Index to Financial Statements~~

~~million for 2017. This increase was due to an increase in our production and our full cost pool and a decrease in our total proved reserves volume used to calculate our total DD&A expense.~~

~~General and Administrative Expenses~~. Net general and administrative expenses increased to $56.6 million for the year ended December 31, 2018 from $52.9 million for the year ended December 31, 2017. This $3.7 million increase was due to an increase in salaries, benefits and employee stock compensation expense resulting from an increased number of employees, legal fees and computer support, partially offset by a decrease in consulting fees. However, during the year ended December 31, 2018, we decreased our per unit general and administrative expense by 15% to $0.11 per Mcfe from $0.13 per Mcfe during the year ended December 31, 2017 as a result of increases in production.

~~Accretion Expense~~. Accretion expense increased to $4.1 million for the years ended December 31, 2018 from $1.6 million for the year ended December 31, 2017, primarily as a result of changes in our asset retirement obligation assumptions during 2017.

~~Interest Expense~~. Interest expense increased to $135.3 million for the year ended December 31, 2018 from $108.2 million for the year ended December 31, 2017 due primarily to the issuance of $450.0 million of the 2026 Notes in October 2017. In addition, total weighted debt outstanding under our revolving credit facility was $83.6 million for the year ended December 31, 2018 as compared to $119.2 million outstanding under such facility for 2017. Additionally, we capitalized approximately $4.5 million and $9.5 million in interest expense to undeveloped oil and natural gas properties during the years ended December 31, 2018 and December 31, 2017, respectively. This decrease in capitalized interest in the 2018 period was primarily the result of changes to our development plan for our oil and natural gas properties.

~~Income Taxes. As of December 31, 2018,~~2020, we had a federal net operating loss ~~carry forward~~carryforward of ~~approximately $782.7 million,~~$1.9 billion, in addition to numerous temporary differences, which gave rise to a net deferred tax ~~asset. Quarterly, management performs a forecast of our taxable income to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive~~asset, and negative factors. A valuation allowance for our deferred tax assets is established if, in management's opinion, it is more likely than not that some portion will not be realized. At December 31, 2018, a valuation allowance of ~~$212.0~~$985.5 million ~~had been provided~~maintained against the net deferred tax asset, with the exception of certain state net operating losses that we expect to be able to utilize with NOL carrybacks. We recognized an income tax benefit from continuing operations of $0.1 million for the year ended December 31, 2018.asset.

~~Comparison of the Years Ended December 31, 2017 and December 31, 2016~~

We reported net income of $435.2 million for the year ended December 31, 2017 as compared to a net loss of $979.7 million for the year ended December 31, 2016. This increase in period-to-period net income was due primarily to no impairment charge for the year ended December 31, 2017 as compared to a $715.5 million impairment of oil and natural gas properties for the year ended December 31, 2016 and a $934.4 million increase in oil and natural gas revenues, partially offset by an $83.0 million increase in midstream gathering and processing expenses, a $118.7 million increase in depreciation, depletion and amortization expense and a $44.7 million increase in interest expense for the year ended December 31, 2017, as compared to the year ended December 31, 2016.

~~Oil and Gas Revenues~~. For the year ended December 31, 2017, we reported oil and natural gas revenues of $1.3 billion as compared to oil and natural gas revenues of $385.9 million during 2016. This $934.4 million, or 242%, increase in revenues was primarily attributable to the following:

A $388.2 million increase in natural gas and oil sales due to a favorable change in gains and losses from derivative instruments. Of the total change, $512.1 million was due to favorable changes in the fair value of our open derivative positions in each period and $123.9 million was due to an unfavorable change in settlements related to our derivative positions.

~~A $425.9 million increase in natural gas sales without the impact of derivatives due to a 54% increase in natural gas sales volumes and a 31% increase in natural gas market prices.~~

~~a $43.4 million increase in oil and condensate sales without the impact of derivatives due to a 21% increase in oil and condensate sales volumes and a 26% increase in oil and condensate market prices.~~

A $76.9 million increase in natural gas liquids sales without the impact of derivatives due to a 39% increase in natural gas liquids sales volumes and a 66% increase in natural gas liquids market prices.

~~Table of Contents~~

~~Index to Financial Statements~~

~~Lease Operating Expenses~~. Lease operating expenses, or LOE, not including production taxes increased to $80.2 million for the year ended December 31, 2017 from $68.9 million for the year ended December 31, 2016. This increase was mainly the result of an increase in expenses related to supervision and labor, overhead, surface rentals, water hauling and treatment, chemicals, ad valorem taxes and road, location and equipment repairs, partially offset by decreases in compression and water disposal. However, due to increased efficiencies and a 51% increase in our production volumes for the year ended December 31, 2017 as compared to the year ended December 31, 2016, our per unit LOE decreased by 23% from $0.26 per Mcfe to $0.20 per Mcfe.

~~Production Taxes~~. Production taxes increased to $21.1 million for the year ended December 31, 2017 from $13.3 million for 2016. This increase was primarily related to an increase in realized prices and production volumes.

~~Midstream Gathering and Processing Expenses.~~ Midstream gathering and processing expenses increased by $83.0 million to $249.0 million for the year ended December 31, 2017 from $166.0 million for 2016. This increase was primarily the result of midstream expenses related to our increased production volumes in the Utica Shale resulting from our 2017 and 2016 drilling activities, as well as production volumes resulting from our SCOOP acquisition in February 2017.

~~Depreciation, Depletion and Amortization~~. Depreciation, depletion and amortization, or DD&A, expense increased to $364.6 million for the year ended December 31, 2017, and consisted of $358.8 million in depletion of oil and natural gas properties and $5.8 million in depreciation of other property and equipment, as compared to total DD&A expense of $246.0 million for 2016. This increase was due to an increase in our full cost pool as a result of our SCOOP acquisition and an increase in our production, partially offset by an increase in our total proved reserves volume used to calculate our total DD&A expense.

~~General and Administrative Expenses~~. Net general and administrative expenses increased to $52.9 million for the year ended December 31, 2017 from $43.4 million for the year ended December 31, 2016. This $9.5 million increase was due to an increase in salaries and benefits resulting from an increased number of employees, consulting fees, bank service charges, computer support and franchise taxes, partially offset by a decrease in employee stock compensation expense and legal fees. However, during the year ended December 31, 2017, we decreased our per unit general and administrative expense by 19% to $0.13 per Mcfe from $0.16 per Mcfe during the year ended December 31, 2016.

~~Accretion Expense. Accretion expense increased to $1.6 million for the year ended December 31, 2017 from $1.1 million for the year ended December 31, 2016, primarily as a result of our SCOOP acquisition.~~

~~Interest Expense~~. Interest expense increased to $108.2 million for the year ended December 31, 2017 from $63.5 million for the year ended December 31, 2016 due primarily to the issuance of $450.0 million of the 2026 Notes in October 2017 and the issuance of $600.0 million of the 2025 Notes in December 2016, partially offset by our repurchase or redemption of our 7.75% Senior Notes due 2020, which we refer to as the 2020 Notes, of which $600.0 million in aggregate principal amount was then outstanding, in October 2016 with the net proceeds from our issuance of $650.0 million of the 2024 Notes. In addition, total weighted debt outstanding under our revolving credit facility was $119.2 million for the year ended December 31, 2017 as compared to $0.2 million outstanding under such facility for 2016. Additionally, we capitalized approximately $9.5 million and $8.7 million in interest expense to undeveloped oil and natural gas properties during the years ended December 31, 2017 and December 31, 2016, respectively. This increase in capitalized interest in the 2017 period was primarily the result of our SCOOP acquisition and the development of this acreage.

~~Income Taxes~~. As of December 31, 2017, we had a net operating loss carry forward of approximately $574.4 million, in addition to numerous temporary differences, which gave rise to a net deferred tax asset. Periodically, management performs a forecast of our taxable income to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established if, in management's opinion, it is more likely than not that some portion will not be realized. At December 31, 2017, a valuation allowance of $298.8 million had been provided against the net deferred tax asset, with the exception of certain state net operating losses that we expect to be able to utilize with NOL carrybacks. We recognized an income tax expense from continuing operations of $1.8 million for the year ended December 31, 2017.

Liquidity and Capital Resources

Overview. Historically, our primary sources of ~~funds~~capital funding and liquidity have been our operating cash flow, ~~from our producing oil and natural gas properties,~~ borrowings under our ~~credit facility~~Pre-Petition Revolving Credit Facility and issuances of equity and debt securities. Our ability to issue additional indebtedness, dispose of assets or access the capital markets may be substantially limited or nonexistent during the Chapter 11 Cases and will require court approval in most instances. Accordingly, our liquidity will depend mainly on cash generated from operating activities and available funds under the DIP Credit Facility as discussed below.

Filing of the Chapter 11 Cases constituted an event of default with respect to certain of our secured and unsecured debt obligations. As a result of the Chapter 11 Cases, the principal and interest due under these debt instruments became immediately due and payable. However, the creditors are stayed from taking any action as a result of ~~these sources~~the default under Section 362 of ~~funds can be significantly impacted by decreases in oil and natural gas prices or oil and natural gas production.~~

the Bankruptcy Code.

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As of December 31, 2020, we had a cash balance of $89.9 million compared to $6.1 million as of December 31, 2019, and a net working capital deficit of $100.5 million as of December 31, 2020, compared to a net working capital deficit of $145.3 million as of December 31, 2019. As of December 31, 2020, our working capital deficit includes $253.7 million of debt due in the next 12 months. Our ~~primary uses~~total principal debt as of ~~cash are~~December 31, 2020 was $2.3 billion compared to $2.0 billion as of December 31, 2019. Additionally, as of December 31, 2020, we had outstanding borrowings of $157.5 million on our DIP credit facility with $105.0 million of incremental borrowing capacity. See Note 6 of the notes to our consolidated financial statements included in Item 8 of this report for ~~ongoing business operations, repayments~~further discussion of our debt ~~capital expenditures, investments~~obligations, including principal and ~~acquisitions. During 2018, we initiated a stock repurchase program to purchase shares~~carrying amounts of our ~~common stock. During 2019, we intend~~notes.

We believe our cash flow from operations, borrowing capacity under the DIP Credit Facility and cash on hand will provide sufficient liquidity during the Chapter 11 process. We expect to ~~purchase additional shares~~incur significant costs related to our ongoing Chapter 11 Cases in 2021, including fees for legal, financial and restructuring advisors to the Company, certain of our ~~common stock under~~creditors and royalty interest owners. Therefore, our ~~recently announced stock repurchase program opportunistically~~ability to obtain confirmation of the Plan in a timely manner is critical to ensuring our liquidity is sufficient during the bankruptcy process.

Our ability to continue as a going concern is contingent on our ability to comply with ~~available funds or non-core asset sales while maintaining sufficient liquidity~~the financial and other covenants contained in our DIP Credit Facility, the Bankruptcy Court's approval of the Plan and our ability to ~~fund our 2019 capital development program.~~

~~Net cash flow provided by operating activities was $752.5 million for~~successfully implement the ~~year ended December 31, 2018 as compared to net cash flow provided by operating activities of $679.9 million for 2017. This increase was primarily the~~Plan and obtain exit financing, among other factors. As a result of ~~an increase in cash receipts from our oil~~the Bankruptcy Filing, the realization of assets and ~~natural gas purchasers due~~the satisfaction of liabilities are subject to ~~a 26% increase in net revenues after giving effect to settled derivative instruments, partially offset by an increase in our~~uncertainty. While operating ~~expenses.~~

~~Net cash flow provided by operating activities was $679.9 million for the year ended December 31, 2017~~ as compared to net cash flow provided by operating activities of $337.8 million for 2016. This increase was primarily the result of an increase in cash receipts from our oil and natural gas purchasers due to a 60% increase in net revenues after giving effect to settled derivative instruments, partially offset by an increase in our operating expenses.

~~Net cash used in investing activities for the year ended December 31, 2018 was $643.1 million as compared to $2.5 billion for 2017. During the year ended December 31, 2018,~~debtors-in-possession under Chapter 11, we ~~spent $865.3 million in additions to oil and natural gas properties, of which $461.8 million was spent on our 2018 drilling and recompletion programs, $193.9 million was spent on expenses attributable~~may settle liabilities, subject to the ~~wells spud, completed and recompleted during 2017, $125.6 million was spent on lease related costs, primarily~~approval of the ~~acquisition of leases~~Bankruptcy Court or as otherwise permitted in the ~~Utica Shale, $2.6 million was spent on facility enhancements and $2.1 million was spent on plugging costs, with the remainder attributable mainly~~ordinary course of business (and subject to future location development and capitalized general and administrative expenses. During the year ended December 31, 2018, we received $175.0 million from the sale of our equity investment in Strike Force and $51.5 million from the sale of Mammoth Energy's common stock. In addition, we invested $2.3 million in Grizzly, and we received $0.4 million in distributions from our investment in Timber Wolf during the year ended December 31, 2018.We did not make any material investments in our other equity investments during the year ended December 31, 2018. During the year ended December 31, 2018, we used cash from operations and proceeds from sales of our investments to fund our investing activities.

Net cash used in investing activities for the year ended December 31, 2017 was $2.5 billion as compared to $720.6 million for 2016. During the year ended December 31, 2017, we spent $1.1 billion in additions to oil and natural gas properties, of which $750.6 million was spent on our 2017 drilling and recompletion programs, $119.8 million was spent on lease related costs, primarily the acquisition of leasesrestrictions contained in the ~~Utica Shale~~DIP Credit Facility), for amounts other than those reflected in the accompanying consolidated financial statements. Further, the Plan could materially change the amounts and classifications of assets and liabilities reported in the ~~SCOOP, $97.4 million was spent on expenses attributable~~consolidated financial statements.

Debtor-In-Possession Credit Facility. Pursuant to the ~~wells spud, completed~~RSA, the Consenting RBL Lenders have agreed to provide the Company with a senior secured superpriority debtor-in-possession revolving credit facility in an aggregate principal amount of $262.5 million consisting of $105 million of new money and ~~recompleted during 2016, $7.2~~$157.5 million ~~was spent on seismic, $4.3 million was spent on plugging costs and $1.5 million was spent on facility enhancements, with the remainder attributable mainly~~ to ~~future location development and capitalized general and administrative expenses. We also spent $1.3 billion to fund the cash~~roll up a portion of the ~~purchase price~~existing outstanding obligations under the Pre-Petition Revolving Credit Facility. The proceeds of the DIP Credit Facility may be used for, among other things, post-petition working capital, permitted capital investments, general corporate purposes, letters of credit, administrative costs, premiums, expenses and fees for the transactions contemplated by the Chapter 11 Cases and payment of court approved adequate protection obligations.

Advances under our ~~SCOOP acquisition.~~DIP Credit Facility may be in the form of either base rate loans or eurodollar loans. The interest rate for base rate loans is equal to (1) the applicable rate of 3.50%, plus (2) the base rate. The interest rate for eurodollar loans is equal to (1) the applicable rate of 4.50%, plus (2) the highest of: (a) 1% or (b) the eurodollar rate. As of December 31, 2020, amounts borrowed under our DIP Credit Facility bore interest at the weighted average rate of 5.50%.

The DIP Credit Facility includes negative covenants that, subject to significant exceptions, limit our ability and the ability of our restricted subsidiaries to, among other things, (i) create liens on assets, property revenues, (ii) make investments, (iii) incur additional indebtedness, (iv) engage in mergers, consolidations, liquidations and dissolutions, (v) sell assets, (vi) pay dividends and distributions or repurchase capital stock, (vii) cease for any reason to be the operator of its properties, (viii) enter into letters of credit without prior written consent, (ix) enter into certain commodity hedging contracts except commodity hedging contracts with terms approved by the Bankruptcy Court in the hedging order or certain interest rate contracts, (x) change lines of business, (xi) engage in certain transactions with affiliates and (xii) incur more than a certain amount in capital expenditures in any calendar month. The DIP Credit Facility includes certain customary representations and warranties, affirmative covenants and events of default, including but not limited to defaults on account of nonpayment, breaches of representations and warranties and covenants, certain bankruptcy-related events, certain events under ERISA, material judgments and a change in control. If an event of default occurs, the lenders under the DIP Credit Facility will be entitled to take various actions, including the acceleration of all amounts due under the DIP Credit Facility and all actions permitted to be taken under the loan documents or application of law. In addition, ~~$2.3 million was invested in Grizzly~~the DIP Credit Facility is subject to various other financial performance covenants, including compliance with certain financial metrics and ~~$46.1 million was invested in Strike Force (prior~~adherence to a budget approved by our sale of our equity interest in Strike Force in May 2018), net of distributions. We did not make any material investments in our other equity investments during the year ended December 31, 2017. During the year ended December 31, 2017, we used cash from operations and proceeds from our 2016 equity and debt offerings and our 2017 debt offering for our investing activities.

Net cash used in financing activities for the year ended December 31, 2018 was $156.7 million as compared to net cash provided by financing activities of $433.0 million for 2017. The 2018 amount used by financing activities is primarily attributable to repurchases under our stock repurchase program of approximately $200.0 million, partially offset by net borrowings under our credit facility.

Net cash provided by financing activities for the year ended December 31, 2017 was $433.0 million as compared to net cash provided by financing activities of $1.7 billion for 2016. The 2017 amount provided by financing activities is primarily attributable to the net proceeds of $444.3 million from our 2017 debt offering.

DIP Credit Facility lenders.

Pre-Petition Revolving Credit Facility. We have entered into a senior secured revolving credit facility agreement, as amended, with The Bank of Nova Scotia, as the lead arranger and administrative agent and certain lenders from time to time party thereto. The credit agreement provides for a maximum ~~facility~~borrowing base amount of ~~$1.5 billion~~$580 million and matures on December ~~13,~~31, 2021. AsThe $292.9 million of outstanding borrowings under the Pre-Petition Revolving Credit Facility as of December 31, ~~2018,~~

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2020 that were not rolled up into the DIP Credit Facility will remain outstanding throughout the Chapter 11 Cases and will continue to accrue interest on amounts drawn after the Petition Date. Additionally, as of December 31, 2020, we had a borrowing base of $1.4 billion, with an elected commitment of $1.0 billion, and $45.0 million in borrowings outstanding under our revolving credit facility. Total funds available for borrowing, after giving effect to an aggregate of ~~$316.6~~$147.5 million of letters of credit ~~were $638.4 million.~~outstanding under our Pre-Petition Revolving Credit Facility. This facility is secured by substantially all of our assets. Our wholly-owned subsidiaries, excluding Grizzly Holdings and Mule Sky, guarantee our obligations under our revolving credit facility.

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~~Index to Financial Statements~~

Advances under our ~~revolving credit facility~~Pre-Petition Revolving Credit Facility may be in the form of either base rate loans or eurodollar loans. The interest rate for base rate loans is equal to (1) the applicable rate, which ranges from 0.25% to 1.25%, plus (2) the highest of: (a) the federal funds rate plus 0.50%, (b) the rate of interest in effect for such day as publicly announced from time to time by the administrative agent as its “prime rate,” and (c) the eurodollar rate for an interest period of one month plus 1.00%. The interest rate for eurodollar loans is equal to (1) the applicable rate, which ranges from 1.25% to 2.25%, plus (2) the London interbank offered rate that appears on pages LIBOR01 or LIBOR02 of the Reuters screen that displays such rate for deposits in U.S. dollars, or, if such rate is not available, the rate as administered by ICE Benchmark Administration (or any other person that takes over administration of such rate) per annum equal to the offered rate on such other page or other service that displays an average London interbank offered rate as administered by ICE Benchmark Administration (or any other person that takes over the administration of such rate) for deposits in U.S. dollars, or, if such rate is not available, the average quotations for three major New York money center banks of whom the administrative agent shall inquire as the “London Interbank Offered Rate” for deposits in U.S. dollars. As of December 31, ~~2018,~~2020, amounts borrowed under our revolving credit facility bore interest at the weighted average rate of ~~4.23%~~3.15%.

Our revolving credit facility contains customary negative covenants including, but not limited to, restrictions on our and our subsidiaries' ability to: incur indebtedness; grant liens; pay dividends and make other restricted payments; make investments; make fundamental changes; enter into swap contracts; dispose of assets; change the nature of their business; and enter into transactions with their affiliates. The negative covenants are subject to certain exceptions as specified in our revolving credit facility. Our revolving credit facility also contains certain affirmative covenants, including, but not limited to the following financial covenants: (1) the ratio of net funded debt to EBITDAX (net income, excluding (i) any non-cash revenue or expense associated with swap contracts resulting from ASC 815 and (ii) any cash or non-cash revenue or expense attributable to minority investment plus without duplication and, in the case of expenses, to the extent deducted from revenues in determining net income, the sum of (a) the aggregate amount of consolidated interest expense for such period, (b) the aggregate amount of income, franchise, capital or similar tax expense (other than ad valorem taxes) for such period, (c) all amounts attributable to depletion, depreciation, amortization and asset or goodwill impairment or writedown for such period, (d) all other non-cash charges, (e) exploration costs deducted in determining net income under successful efforts accounting, (f) actual cash distributions received from minority investments, (g) to the extent actually reimbursed by insurance, expenses with respect to liability on casualty events or business interruption, and (h) all reasonable transaction expenses related to dispositions and acquisitions of assets, investments and debt and equity offerings (provided that expenses related to any unsuccessful dispositions will be limited to $3.0 million in the aggregate) for a twelve-month period may not be greater than 4.00 to 1.00; and (2) the ratio of EBITDAX to interest expense for a twelve-month period may not be less than 3.00 to 1.00. We were in compliance with these financial covenants at December 31, 2018.

Senior Notes. In April 2015, we issued an aggregate of $350.0 million in principal amount of our ~~Senior Notes due 2023, or the~~ 2023 Notes. Interest on ~~the 2023 Notes~~these senior notes accrues at a rate of 6.625% per annum on the outstanding principal amount thereof, ~~from April 21, 2015,~~ payable semi-annually on May 1 and November 1 of each ~~year, commencing on November 1, 2015.~~year. As of December 31, 2020, after giving effect to open market repurchases of these 2023 Notes, $324.6 million principal amount remained outstanding. The 2023 Notes ~~will~~ mature on May 1, 2023.

On October 14, 2016, we issued an aggregate of $650.0 million in principal amount of our ~~Senior Notes due 2024, or the~~ 2024 Notes. Interest on the 2024 Notes accrues at a rate of 6.000% per annum on the outstanding principal amount thereof, payable semi-annually on April 15 and October 15 of each ~~year, commencing on April 15, 2017.~~year. As of December 31, 2020, after giving effect to open market repurchases of these 2024 Notes, $579.6 million principal amount remained outstanding. The 2024 Notes ~~will~~ mature on October 15, 2024.

On December 21, 2016, we issued an aggregate of $600.0 million in principal amount of our ~~Senior Notes due 2025, or the~~ 2025 Notes. Interest on the 2025 Notes accrues at a rate of 6.375% per annum on the outstanding principal amount thereof, payable semi-annually on May 15 and November 15 of each ~~year, commencing on May 15, 2017.~~year. As of December 31, 2020, after giving effect to open market repurchases of these 2025 Notes, $507.9 million principal amount remained outstanding. The 2025 Notes ~~will~~ mature on May 15, 2025.

On October 11, 2017, we issued $450.0 million in aggregate principal amount of our 2026 Notes. Interest on the 2026 Notes accrues at a rate of 6.375% per annum on the outstanding principal amount thereof, payable semi-annually on January 15 and July 15 of each ~~year, commencing on January 15, 2018.~~year. As of December 31, 2020, after giving effect to open market repurchases of these 2026 Notes, $374.6 million principal amount remained outstanding. The 2026 Notes ~~will~~ mature on January 15, 2026. ~~We received~~

All amounts outstanding on our Senior Notes have been classified as liabilities subject to compromise on the accompanying consolidated balance sheet as of December 31, 2020.

During the year ended December 31, 2020, we used borrowings under our revolving credit facility to repurchase in the open market approximately ~~$444.1~~$73.3 million ~~in net proceeds from the offering of the 2026 Notes, a portion of which was used to repay all~~aggregate principal amount of our outstanding Notes for $22.8 million. We recognized a $49.6 million gain on debt extinguishment, which included retirement of unamortized issuance costs and fees associated with the repurchased debt.

Building Loan. On June 4, 2015, we entered into a loan for the construction of our corporate headquarters in Oklahoma City, which was substantially completed in December 2016. Interest accrues daily on the outstanding principal balance at a fixed rate of 4.50% per annum. The building loan matures on June 4, 2025. As of December 31, 2020, the total borrowings under ~~our secured revolving credit facility~~the building loan were approximately $21.9 million, which has been classified as liabilities subject to compromise on ~~October 11, 2017~~the accompanying consolidated balance sheet as of December 31, 2020.

Supplemental Guarantor Financial Information. The 2023 Notes, 2024 Notes, 2025 Notes and ~~the balance was used to fund the remaining outspend related to our 2017 capital development plans.~~

~~All of our~~2026 Notes are guaranteed on a senior unsecured basis by all existing ~~and future restricted~~consolidated subsidiaries that guarantee our secured revolving credit facility or certain other debt ~~guarantee the 2023 Notes, 2024 Notes, 2025 Notes and the 2026 Notes, provided, however, that the 2023 Notes, 2024 Notes, 2025 Notes and 2026~~(the “Guarantors”). The Senior Notes are not guaranteed by Grizzly Holdings ~~Inc. and will not be guaranteed by any of our future~~

or Mule Sky, LLC (the “Non-

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Index to Financial ~~Statements~~Statement s

~~unrestricted subsidiaries.~~Guarantors”). The Guarantors are 100% owned by the Parent, and the guarantees are full, unconditional, joint and several. There are no significant restrictions on the ability of the Parent or the Guarantors to obtain funds from each other in the form of a dividend or loan. The guarantees rank equally in the right of payment with all of the senior indebtedness of the subsidiary guarantors and senior in the right of payment to any future subordinated indebtedness of the subsidiary guarantors.The ~~2023 Notes, 2024 Notes, 2025 Notes and 2026~~Senior Notes and the guarantees are effectively subordinated to all of our and the subsidiary guarantors' secured indebtedness (including all borrowings and other obligations under our amended and restated credit agreement) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated to all indebtedness and other liabilities of any of our subsidiaries that do not guarantee the ~~2023 Notes, 2024 Notes, 2025 Notes and 2026~~ Notes.

~~If we experience a change of control (as defined~~ Effective June 1, 2019, the Parent contributed interests in the senior note indentures relating to the 2023 Notes, 2024 Notes, 2025 Notes and 2026 Notes), we will be required to make an offer to repurchase the 2023 Notes, 2024 Notes, 2025 Notes and 2026 Notes and at a price equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of repurchase. If we sell certain assets and fail to use the proceeds in a manner specified in our senior note indentures, we will be required to use the remaining proceeds to make an offer to repurchase the 2023 Notes, 2024 Notes, 2025 Notes and 2026 Notes at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of repurchase. The senior note indentures relating to the 2023 Notes, 2024 Notes, 2025 Notes and 2026 Notes contain certain covenants that, subject to certain exceptions and qualifications, among other things, limit our ability and the ability of our restricted subsidiaries to incur or guarantee additional indebtedness, make certain investments, declare or pay dividends or make distributions on capital stock, prepay subordinated indebtedness, sell assets including capital stock of restricted subsidiaries, agree to payment restrictions affecting our restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of our assets, enter into transactions with affiliates, incur liens, engage in business other than the oil and gas ~~business~~assets and ~~designate~~related liabilities to certain of the Guarantors.

SEC Regulation S-X Rule 13-01 requires the presentation of "Summarized Financial Information" to replace the "Condensed Consolidating Financial Information" required under Rule 3-10. Rule 13-01 allows the omission of Summarized Financial Information if assets, liabilities and results of operations of the Guarantors are not materially different than the corresponding amounts presented in our consolidated financial statements. The Parent and Guarantor subsidiaries comprise our material operations. Therefore, we concluded that the presentation of the Summarized Financial Information is not required as ~~unrestricted subsidiaries. Under~~our Summarized Financial Information of the ~~indenture relating~~Guarantors is not materially different from our consolidated financial statements.

Derivatives and Hedging Activities. We seek to ~~the 2023 Notes, 2024 Notes, 2025 Notes~~mitigate risks related to unfavorable changes in natural gas, oil and ~~2026 Notes, certain of these covenants~~NGL prices, which are subject to ~~termination upon~~significant and often volatile fluctuation, by entering into over-the-counter fixed price swaps, basis swaps, collars and various types of option contracts. These contracts allow us to mitigate the ~~occurrence~~impact of declines in future natural gas, oil and NGL prices by effectively locking in floor price for a certain ~~events, including in the event the 2023 Notes, 2024 Notes, 2025 Notes and 2026 Notes are ranked as "investment grade" by Standard & Poor's and Moody's.~~

~~Construction Loan.~~ ~~On June 4, 2015, we entered into a construction loan agreement, or the construction loan, with InterBank for the construction~~level of our ~~new corporate headquarters~~production. However, these hedge contracts also limit the benefit to us in ~~Oklahoma City, which was substantially completed in December 2016. The construction loan allows for maximum principal borrowings~~periods when the future market prices of ~~$24.5 million~~natural gas, oil and ~~required us to fund 30% of~~NGL that are higher than the cost of the construction before any funds could be drawn, which occurred in January 2016. Interest accrues daily on the outstanding principal balance at a fixed rate of 4.50% per annum and was payable on the last day of the month through May 31, 2017, after which date we began making monthly payments of interest and principal. The final payment is due June 4, 2025. hedged prices.

As of December 31, ~~2018,~~2020, we had the ~~total borrowings~~following open natural gas derivative instruments (we had no oil or NGL derivative instruments in place):



Year	Type of Derivative Instrument	Index	Daily Volume (MMBtu/day)	Weighted Average Price
2021	Swaps	NYMEX Henry Hub	410,000	$2.75
2021	Basis Swaps	Rex Zone 3	35,000	$(0.21)
2021	Costless Collars	NYMEX Henry Hub	250,000	$2.46/$2.81
2021	Basis Swaps	Tetco M2	60,000	$(0.67)
2022	Sold Call Options	NYMEX Henry Hub	153,000	$2.90
2022	Costless Collars	NYMEX Henry Hub	20,000	$2.80/$3.40
2023	Sold Call Options	NYMEX Henry Hub	628,000	$2.90

See Note 13 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of derivatives and hedging activities.

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Index to Financial Statement s

Period

Type of Derivative Instrument

Index

Daily Volume(1)

Weighted
Average Price

July 2021 - December 2021

Swaps

NYMEX WTI

2,250

$53.07

July 2021 - December 2021

Swaps

Mont Belvieu C3

3,100

$27.80

January 2022 - June 2022

Swaps

Mont Belvieu C3

1,000

$27.30

April 2021 - May 2021

Basis Swaps

Tetco M2

36,443

$(0.61)

February 2021 - October 2021

Basis Swaps

Rex Zone 3

94,505

$(0.22)

July 2021 - December 2021

Costless Collars

NYMEX Henry Hub

210,000

$2.67/$3.15

January 2022 - March 2022

Costless Collars

NYMEX Henry Hub

340,000

$2.82/$3.40

(1) Volume units for gas instruments are presented as MMBtu/day while oil and NGL is presented in Bbls/day.

Contractual and Commercial Obligations. The following table sets forth our contractual and commercial obligations at December 31, 2020:


	Payment due by period
Contractual Obligations	Total		2021		2022-2023		2024-2025		2026 and Thereafter
	(In thousands)
Long-term debt(1):
Principal	$	2,258,962	$	451,159	$	326,003	$	1,107,183	$	374,617
Interest(2)	518,752		184,106		212,606		121,111		929
Firm transportation and gathering contracts(3)	3,774,725		370,343		760,150		631,113		2,013,119
Operating lease liabilities(4)	342		117		195		30		—
Total contractual cash obligations(5)	$	6,552,781	$	1,005,725	$	1,298,954	$	1,859,437	$	2,388,665

_____________________

(2) Includes all contractual interest on amounts classified as liabilities subject to compromise, including interest accrued on Senior Notes as of the Petition Date.

(3) Our commitments under our firm transportation and gathering contracts do not reflect contracts expected to be rejected through our Chapter 11 proceedings. See Note 17 of the ~~construction loan were approximately $23.1 million.~~notes to our consolidated financial statements included in Item 8 of this report for a description of our firm transportation and gathering contracts.

(4) See Note 10 of the notes to our consolidated financial statements included in Item 8 of this report for a description of our operating lease liabilities.

Off-balance Sheet Arrangements. We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2020, our material off-balance sheet arrangements and transactions include $147.5 million in letters of credit outstanding against our revolving credit facility and $111.4 million in surety bonds issued. Both the letters of credit and surety bonds are being used as financial assurance on certain firm transportation agreements. There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital resources.

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Index to Financial Statement s

Capital Expenditures. Our ~~recent~~ capital commitments have been primarily for the execution of our ~~drilling programs, acquisitions in the Utica Shale, our SCOOP acquisition in 2017 and for investments in entities that may provide services to facilitate the development of our acreage.~~operations. Our capital investment strategy is ~~to continue to (1) increase cash flow generated from our operations by undertaking new drilling, workover, sidetrack and recompletion projects to exploit~~focused on prudently developing our existing properties ~~subject to economic and industry conditions, (2) pursue acquisition and disposition opportunities and (3) pursue business integration opportunities.~~

Of our net reserves at December 31, 2018, 55.4% were categorized as proved undeveloped. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved developed reserves, or both. To realize reserves and increase production, we must continue our exploratory drilling, undertake other replacement activities or use third parties to accomplish those activities.

~~During 2018, we spud 23 gross (19.5 net) and commenced sales from 35 gross and net wells~~ in the Utica Shale for a total cost of approximately $305.8 million. In addition, 28 gross (4.4 net) wells were drilled and 32 gross (9.4 net) wells were turned to sales by other operators on our Utica Shale acreage during 2018 for a total cost to us of approximately ~~$90.1 million.~~ We currently expect to drill 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. As of February 15, 2019, we had two operated horizontal rig drilling in the play. We plan to run on average one operated horizontal rig in the Utica Shale during 2019. We also anticipate an additional two to three net horizontal wells will be drilled, and sales commenced from two to three net horizontal wells, on our Utica Shale acreage by other operators.

~~During 2018, we spud 13 gross (12.1 net) and commenced sales from 15 gross (12.8 net) wells in the SCOOP for a total cost of approximately~~ ~~$141.3 million~~. In addition, 40 gross (3.1 net) wells were drilled and 47 gross (3.6 net) wells were turned to sales by other operators on our SCOOP acreage during 2018 for a total cost to us of approximately $39.0 million. During 2019, we currently expect to drill nine to 10 gross (seven to eight net) horizontal wells and commence sales from 15 to

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17 gross (14 to 15 net) wells on our SCOOP acreage. We also anticipate one to two net wells will be drilled, and sales commenced from one to two net wells on our SCOOP acreage by other operators. As of February 15, 2019, we had two operated horizontal drilling rigs in the play. We plan to run on average approximately 1.5 operated horizontal rigs in the SCOOP in 2019.

~~During 2018, we recompleted 32 existing wells and spud~~ no ~~new wells at our WCBB field and recompleted~~ 15 ~~existing wells and spud no new wells in our Hackberry fields for a total aggregate cost of approximately~~ ~~$7.9 million. During 2019, we do not anticipate any activities in our Southern Louisiana fields.~~

~~During 2018, no new wells were spud on our Niobrara Formation acreage. We do not currently anticipate any capital expenditures in the Niobrara Formation in 2019.~~

During the third quarter of 2006, we purchased a 24.9% interest in Grizzly. As of December 31, 2018, our net investment in Grizzly was approximately $44.3 million. Our capital requirements in 2018 for Grizzly were approximately $2.3 million. We do not currently anticipate any material capital expenditures in 2019 related to Grizzly's activities.

We had no material capital expenditures during the during the year ended December 31, 2018 related to our interests in Thailand. We do not currently anticipate any capital expenditures in Thailand in 2019.

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. See Item 1.~~ ~~"Business–Our Equity Investments"~~ and Note 4 to our consolidated financial statements included elsewhere in this report for additional information regarding these other investments. During the years ended December 31, 2018 and 2017, we did not make any additional investments in these entities, and we do not currently anticipate any capital expenditures related to these entities in 2019. 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. On October 19, 2016, Mammoth Energy completed its 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. Following the IPO, we owned an approximate 24.2% interest in Mammoth Energy. On June 5, 2017, we acquired approximately 2.0 million shares of Mammoth Energy common stock in connection with our contribution of all of our membership interests in Sturgeon, Stingray Energy and Stingray Cementing, bringing our equity interest in Mammoth Energy to approximately 25.1%. On June 29, 2018, we sold 1,235,600 shares, and on July 30, 2018, we sold an additional 118,974 shares, of our Mammoth Energy common stock in an underwritten public offering and related partial exercise of the underwriters' option to purchase additional shares for net proceeds to us of approximately $47.0 million and $4.5 million, respectively. Following the sale of these shares, we owned 9,829,548 shares, or 21.9% at December 31, 2018, of Mammoth Energy’s outstanding common stock.

In February 2016, we, through our wholly-owned subsidiary Midstream Holdings, entered into an agreement with Rice to develop natural gas gathering assets in eastern Belmont County and Monroe County, Ohio, which we refer to as the dedicated areas, through an entity called 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 in Strike Force. Strike Force's gathering assets provide gathering services for wells operated by Gulfport and other operators and connectivity of existing dry gas gathering systems. During the year ended December 31, 2017, we paid $46.1 million in net cash calls related to Strike Force. On May 1, 2018, we sold our 25% equity interest in Strike Force to EQT Midstream Partners, LP for $175.0 million in cash.

~~In response to current declining forward natural gas prices, we are shifting to building an organization that is focused on disciplined capital allocation,~~generate sustainable cash flow ~~generation~~considering current and a commitment to executing a thoughtful, clearly communicated business plan that enhances value for all of our shareholders. We plan to maximize results with the core assets in our portfolio today and focus on returns that will allow us to operate within our cash flow in 2019. As a result, we currently expect to reduce our planned capital expenditures by approximately 29% as compared to 2018.

Our total capital expenditures for 2019 are currently estimated to be in the range of $525.0 million to $550.0 million for drilling and completion expenditures. In addition, we currently expect to spend $40.0 million to $50.0 million in 2019 for non-drilling and completion expenditures, which includes acreage expenses, primarily lease extensions in the Utica Shale. The 2019 range of capital expenditures is lower than the $814.7 million spent in 2018, primarily due to the decrease in currentforecasted commodity

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~~prices, specifically natural gas prices, and our desire to fund our capital development program within cash flow, as well as to generate free cash flow.~~

In January 2019, our board of directors approved a stock repurchase program to acquire up to $400.0 million of our outstanding common stock within the next 24 months. We intend to purchase shares under the repurchase program opportunistically with available funds primarily from cash flow from operations and sale of non-core assets while maintaining sufficient liquidity to fund our capital development programs. prices.

We continually monitor market conditions and are prepared to adjust our ~~drilling~~development program if commodity prices dictate. ~~Currently, we~~We believe ~~that~~ our cash flow from operations, borrowing capacity under the DIP Credit Facility and cash on hand will provide sufficient liquidity during the Chapter 11 process. We expect to incur significant costs associated with our ongoing Chapter 11 Cases in 2021, including fees for legal, financial and ~~borrowings under~~restructuring advisors to the Company, certain of our ~~loan agreements will be sufficient to meet~~creditors and royalty interest owners. Therefore, our normal recurring operating needs and capital requirements for the next twelve months. We believe that our strong liquidity position, hedge portfolio and conservative balance sheet position us well to react quickly to changing commodity prices and accelerate or decelerate our activity within the Utica Basin and the SCOOP as the market conditions warrant. Notwithstanding the foregoing, in the event commodity prices decline from current levels, our capital or other costs increase, our equity investments require additional contributions and/or we pursue additional equity method investments or acquisitions, we may be requiredability to obtain ~~additional funds which we would seek~~confirmation of the Plan in a timely manner is critical to ~~do through traditional borrowings, offerings of debt or equity securities or other means, including~~ensuring our liquidity is sufficient during the sale of assets. We regularly evaluate new acquisition opportunities. Needed capital may not be available to us on acceptable terms or at all. Further, if we are unable to obtain funds when needed or on acceptable terms, we may be required to delay or curtail implementation of our business plan or not be able to complete acquisitions that may be favorable to us. If the current low commodity price environment worsens, our revenues, cash flows, results of operations, liquidity and reserves may be materially and adversely affected.bankruptcy process.

Commodity Price ~~Risk~~

Risk. The volatility of the energy markets makes it extremely difficult to predict future oil and natural gas price movements with any certainty. During ~~2017,~~2019, WTI prices ranged from ~~$42.48~~$46.31 to ~~$60.46~~$66.24 per barrel and the Henry Hub spot market price of natural gas ranged from ~~$2.44~~$1.75 to ~~$3.71~~$4.25 per MMBtu. During ~~2018,~~2020, WTI prices ranged from ~~$44.48~~$(36.98) to ~~$77.41~~$63.27 per barrel and the Henry Hub spot market price of natural gas ranged from ~~$2.49~~$1.33 to ~~$6.24~~$3.14 per MMBtu. If the prices of oil and natural gas decline further, our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves may be materially and adversely affected. In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development activities are curtailed, full cost accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. Reductions in commodity prices and/or our reserves could also negatively impact the borrowing base under our revolving credit facility, which could ~~further~~ limit our liquidity and ability to ~~conduct additional exploration and~~fund development activities.

See Item 7A. "Quantitative and Qualitative Disclosures about Market Risk" for information regarding our open fixed price swaps at December 31, ~~2018.~~2020.

~~Commitments~~

In connection with our acquisition in 1997 of the remaining 50% interest in the WCBB properties, we assumed the seller's (Chevron) obligation to contribute approximately $18,000 per month through March 2004, to a plugging and abandonment trust and the obligation to plug a minimum of 20 wells per year for 20 years commencing March 11, 1997. Chevron retained a security interest in productionCash Flow from these properties until abandonment obligations to Chevron have been fulfilled. Beginning in 2009, we can access the trust for use in plugging and abandonment charges associated with the property. As of December 31, 2018, the plugging and abandonment trust totaled approximately $3.1 million. At December 31, 2018, we have plugged 555 wells at WCBB since we began our plugging program in 1997, which management believes fulfills our current minimum plugging obligation.

In January 2018, our board of directors approved a stock repurchase program to acquire up to $100.0 million of our outstanding common stock during 2018, and in May 2018 expanded this program authorizing us to acquire up to an additional $100.0 million of our outstanding common stock during 2018 for a total of up to $200.0 million. The Company fully executed the program during the year ended December 31, 2018, and repurchased 20.7 million shares for a cost of approximately $200.0 million. In January 2019, our board of directors approved a stock repurchase program to acquire up to $400.0 million of our outstanding common stock within the next 24 months. Purchases under the repurchase program may be made from time to time in open market or privately negotiated transactions, and will be subject to market conditions, applicable legal requirements, contractual obligations and other factors. The repurchase program does not require the Company to acquire any specific

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number of shares. The Company intends to purchase shares under the repurchase program opportunistically with available funds while maintaining sufficient liquidity to fund its 2019 capital development program. This repurchase program is authorized to extend through December 31, 2020 and may be suspended from time to time, modified, extended or discontinued by the board of directors of the Company at any time. We did not make any purchases of our common stock during the year ended December 31, 2017 under any stock repurchase program or otherwise.

~~Contractual and Commercial Obligations~~

~~The following table sets forth our contractual and commercial obligations at December 31, 2018:~~

Payment due by period
Contractual Obligations Total Less than 1 year 1-3 years 3-5 years
More than 5
years
(In thousands)
Revolving credit agreement (1) $ 45,000
$ —
$ 45,000
$ —
$ —
6.625% senior unsecured notes due 2023 (2) 454,344
23,188
46,375
384,781
—
6.000% senior unsecured notes due 2024 (3) 884,101
39,000
78,000
78,000
689,101
6.375% senior unsecured notes due 2025 (4) 848,748
38,250
76,500
76,500
657,498
6.375% senior unsecured notes due 2026 (5) 665,156
28,687
57,375
57,375
521,719
Asset retirement obligations (6) 79,952
—
—
—
79,952
Building loan (7) 23,149
651
1,290
1,416
19,792
Firm transportation contracts 3,504,318
251,644
494,201
490,972
2,267,501
Drilling and purchase obligations (8) 204,969
89,022
115,947
—
—
Operating leases 271
144
127
—
—
Total $ 6,710,008
$ 470,586
$ 914,815
$ 1,089,044
$ 4,235,563

~~_____________________~~

(1) Does not include future loan advances, repayments, commitment fees or other fees on our revolving credit facility as we cannot determine with accuracy the timing of such items. Additionally, this table does not include interest expense as it is a floating rate instrument and we cannot determine with accuracy the future interest rates to be charge.

~~(2) Includes estimated interest of $23.2 million due in less than one year; $46.4 million due in 1-3 years and $34.8 million due in 3-5 years.~~

~~(3) Includes estimated interest of $39.0 million due in less than one year; $78.0 million due in 1-3 years; $78.0 million due in 3-5 years and $39.1 million due thereafter.~~

~~(4) Includes estimated interest of $38.3 million due in less than one year; $76.5 million due in 1-3 years; $76.5 million due in 3-5 years and $57.5 million due thereafter.~~

~~(5) Includes estimated interest of $28.7 million due in less than one year; $57.4 million due in 1-3 years; $57.4 million due in 3-5 years and $71.7 million due thereafter.~~


~~(6)~~	Amount represents the estimated discounted cost for future abandonment of oil and natural gas properties. Due to the uncertainty in timing of the obligation and no current contractual obligation, the liability is included in the "More than 5 years" category.


~~(7)~~	~~Does not include estimated interest of $1.0 million due in less than one year; $2.0 million due in 1-3 years: $1.9 million due in 3-5 years and $1.3 million due thereafter.~~


~~(8)~~	Drilling and purchasing obligations reported above represent our minimum financial commitment pursuant to the terms of these contracts. A portion of these future costs will be borne by other interest owners.

~~Off-balance Sheet Arrangements~~

~~We had no off-balance sheet arrangements as of December 31, 2018.~~

~~New Accounting Pronouncements~~

~~In May 2014, the FASB issued Accounting Standards Update, or ASU, No. 2014-09,~~ ~~Revenue from Contracts with Customers, which supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-~~

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specific guidance with Topic 606. Subsequent to ASU 2014-09, the FASB issued several related ASU's to clarify the application of the revenue recognition standard. The core principle of the new standard is for the recognition of revenue to depict the transfer of goods or services to customers in amounts that reflect the payment to which the company expects to be entitled in exchange for those goods or services. We adopted ASC 606 as of January 1, 2018 using the modified retrospective transition method applied to contracts that were not completed as of that date. Results for reporting periods beginning after January 1, 2018 are presented under the new revenue standard. Under the modified retrospective method, we recognize the cumulative effect of initially applying the new revenue standard as an adjustment to the opening balance of retained earnings; however, no adjustment was required as a result of adopting the new revenue standard. The comparative information has not been restated and continues to be reported under the historic accounting standards in effect for those periods. The impact of the adoption of the new revenue standard is not expected to be material to our net income on an ongoing basis. See Note 10 to our consolidated financial statements for further discussion of the revenue standard.

~~In February 2016, the FASB issued ASU No. 2016-02,~~ ~~Leases (Topic 842)~~Operating Activities. The standard supersedes the previous lease guidance by requiring lessees to recognize a right-to-use asset and lease liability on the balance sheet for all leases with lease terms of greater than one year while maintaining substantially similar classifications for financing and operating leases. The guidance is effective for periods after December 15, 2018, and we will adopt beginning January 1, 2018 using the transition method permitted by ASU No. 2018-11, ~~Leases (Topic 842): Targeted Improvements~~, issued in August 2018, which permits an entity to recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption with no adjustment made to the comparative periods presented in the consolidated financial statements. We will also utilize the practical expedientNet cash flow provided by ASU 2018-11 to not separate non-lease components from the associated lease component and, instead, to account for those components as a single component if the non-lease components would be accounted for under ASC 606 and other conditions are met.

We have identified our portfolio of leased assets under the new standard and has evaluated the impact of this guidance on our consolidated financial statements and related disclosures. Offsetting right-of-use assets and corresponding lease liabilities recognized by us on the adoption date totaled approximately $110 million, representing minimum payment obligations associated with identified leases with contractual durations longer than one year. Adoption of the new standard will not result in a material impact to the consolidated statement of operations. We have implemented processes and controls needed to comply with the requirements of the new standard, which includes the implementation of a lease accounting software solution to support lease portfolio management and accounting and disclosures.

~~Additionally, in January 2018, the FASB issued ASU No. 2018-01,~~ ~~Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842~~. The amendments in this update provide an optional expedient to not evaluate existing or expired land easements that were not previously accounted for under current leases guidance in Topic 840. An entity that elects this practical expedient should evaluate new or modified land easements beginning at the date of adoption. We do not currently account for any land easements under Topic 840 and plan to utilize this practical expedient in conjunction with the adoption of ASU 2016-02.

~~In June 2016, the FASB issued ASU No. 2016-13,~~ ~~Financial Instruments-Credit Losses: Measurement of Credit Losses on Financial Instruments~~. This ASU amends guidance on reporting credit losses for assets held at amortized cost basis and available for sale debt securities. For assets held at amortized cost basis, this ASU eliminates the probable initial recognition threshold in current GAAP and instead, requires an entity to reflect its current estimate of all expected credit losses. The amendments affect loans, debt securities, trade receivables, net investments in leases, off balance sheet credit exposure, reinsurance receivables and any other financial assets not excluded from the scope that have the contractual right to receive cash. The guidance is effective for periods after December 15, 2019, with early adoption permitted. We are currently evaluating the impact this standard will have on our financial statements and related disclosures and do not anticipate it to have a material effect.

~~In August 2016, the FASB issued ASU No. 2016-15,~~ ~~Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments.~~ This ASU clarifies how certain cash receipts and cash payments should be classified and presented in the statement of cash flows. We adopted this standard in the first quarter of 2018 and have made an accounting policy election to classify distributions received from equity method investees using the nature of the distribution approach, which classifies distributions received from investees as either cash inflows from operating activities ~~or cash inflows from investing activities in the statement of cash flows based on the nature of the activities of the investee that generated the distribution. The impact of adopting this ASU~~ was ~~not material to prior periods presented.~~

~~In November 2016, the FASB issued ASU No. 2016-18,~~ ~~Statement of Cash Flows (Topic 230): Restricted Cash. This ASU requires that amounts generally described as restricted cash and restricted cash equivalents be included with cash and cash~~

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equivalents when reconciling the beginning-of-period and end-of-period amounts shown on the statement of cash flows and to provide a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. We adopted this standard in the first quarter of 2018 using the retrospective transition method. The adoption of this standard had no impact on the statement of cash flows$95.3 million for the year ended December 31, ~~2018. As a~~2020 as compared to $724.0 million for 2019. This decrease was primarily the result of a decrease in cash receipts from our oil and natural gas purchasers due to a 41% decrease in net natural gas, oil and NGL sales excluding the ~~adoption, $185.0 million~~impact of derivatives and, to a lesser extent, reorganization items related to our Chapter 11 Cases.

Divestitures. During 2020, we divested certain non-core assets and interests in ~~restricted~~operated and non-operated oil and natural gas properties for approximately cash ~~was removed~~proceeds of $51.0 million. Proceeds from ~~net~~these transactions were primarily used to repay debt and fund our development program. See Note 3 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion.

Uses of Funds. The following table presents the uses of our cash ~~used~~and cash equivalents for the years ended December 31, 2020 and 2019:

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	Years Ended December 31,
	2020		2019
	(In thousands)
Oil and Natural Gas Property Expenditures:
Drilling and completion costs	$	321,811	$	654,407
Leasehold acquisitions	18,135		39,664
Other	27,341		25,986
Total oil and natural gas property expenditures	$	367,287	$	720,057
Other Uses of Cash and Cash Equivalents

Cash paid to repurchase senior notes	22,827		138,786
Cash paid to repurchase common stock	—		30,000
Additions to other property and equipment	799		5,021
DIP credit facility financing fees	2,988		—
Other	738		720
Total other uses of cash and cash equivalents	$	27,352	$	174,527
Total uses of cash and cash equivalents	$	394,639	$	894,584

Drilling and Completion Costs. During 2020, we spud 16 gross (16 net) wells and commenced sales from 25 gross (23.8 net) wells in ~~investing resulting~~the Utica for a total cost of approximately $192.2 million.

During 2020, we spud 10 gross (8.4 net) and commenced sales from 4 gross (3.8 net) wells in ~~an increase~~the SCOOP for a total cost of approximately $53.9 million. In addition, 19 gross (0.05 net) wells were spud and 12 gross (0.04 net) wells were turned to sales by other operators on our SCOOP acreage during 2020 for a total cost to us of approximately $0.6 million.

Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the United States require us to make estimates and assumptions. The accounting estimates and assumptions we consider to be most significant to our financial statements are discussed below. Our management has discussed each critical accounting estimate with the Audit Committee of our Board of Directors.

The Company has applied FASB ASC Topic 852 - Reorganizations ("ASC 852") in preparing the consolidated financial statements, which specifies the accounting and financial reporting requirements for entities reorganizing through Chapter 11 bankruptcy proceedings. These requirements include distinguishing transactions associated with the reorganization separate from activities related to the ~~ending cash~~ongoing operations of the business. Accordingly, pre-petition liabilities that may be impacted by the Chapter 11 proceedings have been classified as liabilities subject to compromise on the consolidated balance sheet as of December 31, 2020. Additionally, certain expenses, realized gains and losses and provisions for losses that are realized or incurred during the Chapter 11 Cases, including adjustments to the carrying value of certain indebtedness are recorded as reorganization items, net in the consolidated statements of operations for the year ended December 31, ~~2016. The adoption also resulted in an addition of $185.0 million in restricted cash~~2020. Refer to ~~the net cash used in investing activities~~Note 2 for the year ended December 31, 2017. This addition and the resulting decrease to ending cash was offset by the increase to beginning cash balance of $185.0 million due to the changes at December 31, 2016. Therefore, there was no net impactmore information on the ~~statement~~events of ~~cash flows~~the bankruptcy proceedings as well as the accounting and reporting impacts of ~~December 31, 2017.~~the reorganization.

~~In January 2017,~~Oil and Natural Gas Properties. We use the ~~FASB issued ASU No. 2017-01,~~ ~~Clarifying the Definition~~full cost method of ~~a Business~~. accounting for oil and natural gas operations. Accordingly, all costs, including non-productive costs and certain general and administrative costs directly associated with acquisition, exploration and development of oil and natural gas properties, are capitalized.

Under the ~~current business combination guidance, there~~full cost method, capitalized costs are ~~three elements~~amortized on a composite unit-of-production method based on proved oil and natural gas reserves. If we maintain the same level of ~~a business: inputs, processes~~production year over year, the depreciation, depletion and ~~outputs. The revised guidance adds an initial screen test~~amortization expense may be significantly different if our estimate of remaining reserves or future development costs changes significantly.

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Index to determine if substantially all of the fair value of the gross assets acquired is concentrated in a single asset or group of similar assets. If that screen is met, the set of assets is not a business. The new framework also specifies the minimum required inputs and processes necessary to be a business. We adopted this standard in the first quarter of 2018 with no significant effect on our financial statements or related disclosures.

~~In February 2018, the FASB issued ASU No. 2018-02,~~ ~~Income statement - Reporting Comprehensive Income (Topic 220) - Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income~~, which allows a reclassification from accumulated other comprehensive income to retained earnings for standard tax effects resulting from the Tax Cuts and Jobs Act of 2017. The amendment will be effective for reporting periods beginning after December 15, 2018, and early adoption is permitted. We assessed the impact of the ASU on our consolidated financial statements and related disclosures, and determined there was no material impact.

~~In August 2018, the FASB issued ASU No. 2018-13,~~ ~~Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement,~~ which removes, modifies, and adds certain disclosure requirements on fair value measurements. The amendment will be effective for reporting periods beginning after December 15, 2019, and early adoption is permitted. We are currently assessing the impact of the ASU on our consolidated financial statements and related disclosures

~~In August 2018, the FASB also issued ASU No. 2018-15,~~ ~~Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract~~, which aligns the accounting for costs associated with implementing a cloud computing arrangement in a hosting arrangement that is a service contract with the accounting for implementation costs incurred to develop or obtain internal-use software. The amendment will be effective for reporting periods beginning after December 15, 2019, and early adoption is permitted. We are currently assessing the impact of the ASU on our consolidated financial statements and related disclosures.

~~In August 2018, the Securities and Exchange Commission ("SEC") issued Final Rule Release No. 33-10532,~~ ~~Disclosure Update and Simplification~~, which amends certain disclosure requirements that were redundant, duplicative, overlapping or superseded. Under these amendments, the annual disclosure requirements on the analysis of stockholders' equity is extended to interim financial statements. We will present an analysis of changes in stockholders' equity for the current and comparative year-to-date interim periods. The final rule is effective November 5, 2018, and we will begin presenting this analysis beginning with the quarter ended March 31, 2019.

~~In November 2018, the FASB also issued ASU No. 2018-18,~~ ~~Collaborative Arrangements (Topic 808): Clarifying the Interaction Between Topic 808 and Topic 606~~, which provides guidance on how to assess whether certain transactions between participants in a collaborative arrangement should be accounted for within the ASU No. 2014-09 revenue recognition standard discussed above. The amendment will be effective for reporting periods beginning after December 15, 2019, and early adoption is permitted. We are currently assessing the impact of the ASU on its consolidated financial statements and related disclosures.

Financial Statement s



~~ITEM 7A.~~			~~QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK~~

~~Our revenues, operating results, profitability, future rate of growth and~~We review the carrying value of our oil and natural gas properties ~~depend primarily upon~~under the ~~prevailing~~full cost method of accounting prescribed by the SEC on a quarterly basis. This quarterly review is referred to as a ceiling test.

Two primary factors impacting this test are reserve estimates and the unweighted arithmetic average of the prices ~~for oil and natural gas. Historically,~~on the first day of each month within the 12-month period ended December 31, 2020. Downward revisions to estimates of oil and natural gas reserves and/or unfavorable prices can have ~~been~~a material impact on the present value of estimated future net revenues. Any excess of the net book value, less deferred income taxes, is generally written off as an expense. During the year ended December 31, 2020 we recorded impairments of our oil and natural gas properties in the amount of $1.4 billion compared to $2.0 billion during the year ended December 31, 2019. See Oil and Natural Gas Properties in Note 1 of the notes to our consolidated financial statements included in Item 8 of this report for further information on the full cost method of accounting.

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~~volatile~~Oil, Natural Gas and ~~are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors, including: worldwide and domestic supplies~~NGL Reserves. Estimates of oil and natural ~~gas;~~gas reserves and their values, future production rates, future development costs and commodity pricing differentials are the ~~level~~most significant of our estimates. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, recent commodity prices, operating costs and ~~expectations about~~other factors. These revisions could materially affect our financial statements. The volatility of commodity prices results in increased uncertainty inherent in these estimates and assumptions. Changes in natural gas, oil or NGL prices could result in actual results differing significantly from our estimates. See Note 19 included in Item 8 of this report for further information.

Income Taxes. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future ~~prices,~~tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income during the period the rate change is enacted. Deferred tax assets are recognized in the year in which realization becomes determinable. Quarterly, management performs a forecast of its taxable income to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established, if in management's opinion, it is more likely than not that some portion will not be realized. At December 31, 2020, a valuation allowance of $985.5 million had been established to fully offset our net deferred tax asset on our accompanying consolidated balance sheet.

Revenue Recognition. We derive almost all of our revenue from the sale of natural gas, crude oil and natural gas; the cost of exploring for, developing, producing and delivering oil and natural gas; the expected rates of declining current production; weather conditions, including hurricanes, that can affectNGL produced from our oil and natural gas ~~operations over a wide area;~~properties. Revenue is recorded in the ~~level~~month the product is delivered to the purchaser. We receive payment on substantially all of ~~consumer demand;~~these sales from one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers that month and the price we will receive. Variances between our estimated revenue and ~~availability of alternative fuels; technical advances affecting energy consumption; risks associated with operating drilling rigs;~~actual payment received for all prior months are recorded at the ~~availability of pipeline capacity; the price and level of foreign imports; domestic and foreign governmental regulations and taxes; the ability~~end of the ~~members~~quarter after payment is received. Historically, our actual payments received have not significantly deviated from our accruals.

Derivative Instruments. We seek to reduce our exposure to unfavorable changes in natural gas, oil and NGL prices, which are subject to significant and often volatile fluctuation, by entering into over-the-counter fixed price swaps, basis swaps, costless collars and various types of option contracts. All derivative instruments are recognized as assets or liabilities in the balance sheet, measured at fair value. We estimate the fair value of all derivative instruments using industry-standard models that considered various assumptions including current market and contractual prices for the underlying instruments, implied volatility, time value, nonperformance risk, as well as other relevant economic measures.

See Item 7A. "Natural Gas, Oil and NGL Derivatives" for a summary of our derivative instruments in place as of December 31, 2020.

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Index to Financial Statement s

Disclosures About Effects of Transactions with Related parties

Our equity method investees are considered related parties. See Notes 5, 10 and 16 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of transactions with our equity method investees.


ITEM 7A.			QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk. Our results of operations and cash flows are impacted by changes in market prices for oil, natural gas and NGL, which have been historically volatile and are even more volatile as a result of COVID-19 and decisions of the Organization of Petroleum Exporting Countries and other high oil-exporting countries ("OPEC+") discussed in this Form 10-K. To mitigate a portion of our exposure to ~~agree~~adverse price changes, we enter into various derivative instruments, we have entered into various derivative instruments. Our natural gas, oil and NGL derivative activities, when combined with our sales of natural gas, oil and NGL, allow us to predict with greater certainty the revenue we will receive. We believe our derivative instruments continue to be highly effective in achieving our risk management objectives.

Our general strategy for protecting short-term cash flow and ~~maintain~~attempting to mitigate exposure to adverse natural gas, oil and NGL price changes is to hedge into strengthening natural gas, oil and ~~production controls; political instability~~NGL futures markets when prices reach levels that management believes are unsustainable for the long term, have material downside risk in the short term or ~~armed conflict~~provide reasonable rates of return on our invested capital. Information we consider in forming an opinion about future prices includes general economic conditions, industrial output levels and expectations, producer breakeven cost structures, liquefied natural gas trends, oil and natural gas ~~producing regions;~~storage inventory levels, industry decline rates for base production and weather trends. Executive management is involved in all risk management activities and the ~~overall economic environment.~~Board of Directors reviews our derivative program at its quarterly board meetings. We believe we have sufficient internal controls to prevent unauthorized trading.

~~These factors~~We use derivative instruments to achieve our risk management objectives, including swaps and ~~the volatility~~options. All of these are described in more detail below. We typically use swaps for a large portion of the ~~energy markets make it extremely difficult to predict future~~ oil and natural gas price ~~movements~~risk we hedge. We have also sold calls, taking advantage of premiums associated with ~~any certainty. During 2017, WTI prices ranged from $42.48 to $60.46 per barrel and the Henry Hub spot~~ market price volatility.

We determine the notional volume potentially subject to derivative contracts by reviewing our overall estimated future production levels, which are derived from extensive examination of ~~natural gas ranged~~existing producing reserve estimates and estimates of likely production from ~~$2.44~~new drilling. Production forecasts are updated at least monthly and adjusted if necessary to ~~$3.71 per MMBtu. During 2018, WTI prices ranged from $44.48 to $77.41 per barrel~~actual results and ~~the Henry Hub spot market price of natural gas ranged from $2.49 to $6.24 per MMBtu. If the prices of oil and natural gas decline further, our operations, financial condition and level of expenditures~~activity levels. We do not enter into derivative contracts for ~~the development~~volumes in excess of our ~~oil~~share of forecasted production, and natural gas reserves may be materially and adversely affected. In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if ~~our~~ production estimates ~~change or~~were lowered for future periods and derivative instruments are already executed for some volume above the new production forecasts, the positions would be reversed. The actual fixed price on our ~~exploration or development activities are curtailed, full cost accounting rules may require us to write down,~~derivative instruments is derived from the reference NYMEX price, as ~~a non-cash charge to earnings, the carrying value~~reflected in current NYMEX trading. The pricing dates of our oil and natural gas properties. Reductions in our reserves could also negatively impact the borrowing base under our revolving credit facility, which could further limit our liquidity and ability to conduct additional exploration and development activities.

~~To mitigate the effects of commodity price fluctuations on our oil and natural gas production, we had the following open fixed price swap positions as of December 31, 2018.~~

Location Daily Volume (MMBtu/day)
Weighted
Average Price
2019 NYMEX Henry Hub 1,254,000
$ 2.83
2020 NYMEX Henry Hub 204,000
$ 2.77

Location Daily Volume (Bbls/day)
Weighted
Average Price
2019 Mont Belvieu C2 1,000

$ 18.48
2019 Mont Belvieu C3 4,000
$ 28.87
2019 Mont Belvieu C5 500
$ 54.08

~~During the fourth quarter of 2018, we early terminated all~~derivative contracts follow NYMEX futures. All of our ~~fixed price swaps for oil~~commodity derivative instruments are net settled based on both Argus Louisiana Light Sweet Crude and NYMEX West Texas Intermediate scheduled to settle during 2019 covering 5,000 Bbls/day. These early terminations resulted in approximately $0.4 million of settlement losses which is included in net (loss) gain on natural gas, oil, and NGL derivatives in the accompanying consolidated statement of operations.

We sold call options and used the associated premiums to enhance the fixed price for a portion of the fixed price natural gas swaps listed above. Each short call option has an established ceiling price. When the referenced settlement price is above the price ceiling established by these short call options, we pay our counterparty an amount equal to the difference between the ~~referenced settlement price and the price ceiling multiplied by the hedged contract volumes.~~

Location Daily Volume (MMBtu/day)
Weighted
Average Price
January 2019 - March 2019 NYMEX Henry Hub 50,000
$ 3.13
April 2019 - December 2019 NYMEX Henry Hub 30,000
$ 3.10

~~Table of Contents~~

~~Index to Financial Statements~~

~~For a portion of the natural gas~~ fixed price swaps listed above, the counterparties had the option to extend the original terms an additional twelve months for the period January 2019 through December 2019. In December 2018, the counterparties chose to exercise all natural gas fixed price swaps, resulting in an additional 100,000 MMBtu per day at a weighted average price of $3.05 per MMBtu, which is included in the natural gas fixed price swaps listed above.

In addition, we have entered into natural gas basis swap positions, which settle on the pricing index to basis differential of Transco Zone 4 to the NYMEX Henry Hub natural gas price. As of December 31, 2018, we had the following natural gas basis swap positions for Transco Zone 4.

Location Daily Volume (MMBtu/day) Hedged Differential
2019 Transco Zone 4 60,000
$ (0.05 )
2020 Transco Zone 4 60,000
$ (0.05 )

In February 2019, we entered into a natural gas basis swap position for 2020, which settles on the pricing index to basis differential of Inside FERC to the NYMEX Henry Hub natural gas price, for approximately 10,000 MMBtu of natural gas per day at a differential of $0.54 per MMBtu. Our fixed price swap contracts are tied to the commodity prices on NYMEX Henry Hub for natural gas and Mont Belvieu for propane, pentane and ethane. We will receive the fixed priced amountas stated in the contract and the floating-price, resulting in a net amount due to or from the counterparty.

We review our derivative positions continuously and if future market conditions change and prices are at levels we believe could jeopardize the effectiveness of a position, we will mitigate this risk by either negotiating a cash settlement with our counterparty, restructuring the position or entering into a new trade that effectively reverses the current position. The factors we consider in closing or restructuring a position before the settlement date are identical to those we review when deciding to enter into the original derivative position. Gains or losses related to closed positions will be recognized in the month specified in the original contract.

We have determined the fair value of our derivative instruments utilizing established index prices, volatility curves and discount factors. These estimates are compared to counterparty valuations for reasonableness. Derivative transactions are also subject to the risk that counterparties will be unable to meet their obligations. This non-performance risk is considered in the valuation of our derivative instruments, but to date has not had a material impact on the values of our derivatives. Future risk related to counterparties not being able to meet their obligations has been partially mitigated under our commodity hedging arrangements that require counterparties to post collateral if their obligations to us are in excess of defined thresholds. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. See Note 13 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of the fair value measurements associated with our derivatives.

As of December 31, 2020, our natural gas derivative instruments consistent of the following types of instruments:

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Index to Financial Statement s

•Swaps: We receive a fixed price and pay a floating market price to ~~its~~the counterparty for the hedged commodity. In exchange for higher fixed prices on certain of our swap trades, we may sell call options.

•Basis Swaps: These instruments are arrangements that guarantee a fixed price differential to NYMEX from a specified delivery point. We receive the fixed price differential and pay the floating market price differential to the counterparty for the hedged commodity.

•Options: We sell, and occasionally buy, call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, we pay the counterparty the ~~current~~excess on sold call options, and we receive the excess on bought call options. If the market price ~~as listed on NYMEX Henry Hub~~settles below the fixed price of the call option, no payment is due from either party.

•Costless Collars: Each two-way price collar has a set floor and ceiling price for ~~natural gas or Mont Belvieu for propane, pentane~~the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ~~ethane.~~ceiling prices in the various collars, the Company will cash-settle the difference with the counterparty.

~~Under our 2019 contracts, we have hedged approximately~~ ~~94% to 97%~~ ~~of our expected 2019 production.~~ Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or ~~oil~~commodities prices increase. At December 31, ~~2018,~~2020, we had a net liability derivative position of ~~$13.0~~$20.8 million as compared to a net asset derivative position of ~~$52.0~~$73.3 million as of December 31, ~~2017, related to our fixed price swaps.~~2019. Utilizing actual derivative contractual volumes, a 10% increase in underlying commodity prices would have reduced the fair value of these instruments by approximately ~~$155.1~~$69.0 million,, while a 10% decrease in underlying commodity prices would have increased the fair value of these instruments by approximately ~~$154.6~~$66.0 million. However, any realized derivative gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instrument.

Interest Rate Risk. Our ~~revolving credit facility is~~Pre-Petition Revolving Credit Facility and DIP Credit Facility are structured under floating rate terms, as advances under ~~this facility~~these facilities may be in the form of either base rate loans or eurodollar loans. As such, our interest expense is sensitive to fluctuations in the prime rates in the ~~U.S.~~United States or, if the eurodollar rates are elected, the eurodollar rates. At December 31, ~~2018,~~2020, we had ~~$45.0~~$292.9 million in borrowings outstanding under our revolving credit facility which bore interest at the weighted average rate of ~~4.23%~~3.15%. At December 31, 2020, we had $157.5 million in borrowings under our DIP credit facility which bore interest at the weighted average rate of 5.50%.A 1% increase in the average interest rate would have increased interest expense by approximately ~~$0.8~~$2.1 million based on outstanding borrowings under our revolving credit facility ~~throughout the year ended~~and DIP credit facility at December 31, ~~2018.~~2020. As of December 31, ~~2018,~~2020, we did not have any interest rate swaps to hedge our interest risks.



~~ITEM 8.~~	~~FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA~~

~~The information required by this item appears beginning on page F-1 following the signature pages of this Report.~~



~~ITEM 9.~~	~~CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE~~

~~None.~~



~~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

Table of Contents

Index to Financial ~~Statements~~Statement

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:~~ITEM 8.			~~David M. Wood~~	~~Name:~~	~~Keri Crowell~~
~~Title:~~	~~Chief Executive Officer and President~~	~~Title:~~	~~Chief Financial Officer~~FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS


			Page

Report of Independent Registered Public Accounting Firm			59

Consolidated Balance Sheets, December 31, 2020 and December 31, 2019			61

Consolidated Statements of Operations, Years Ended December 31, 2020, 2019, and 2018			62

Consolidated Statements of Comprehensive (Loss) Income, Years Ended December 31, 2020, 2019, and 2018			63

Consolidated Statements of Stockholders' (Deficit) Equity, Years Ended December 31, 2020, 2019, and 2018			64

Consolidated Statements of Cash Flows, Year Ended December 31, 2020, 2019, and 2018			65

Notes to Consolidated Financial Statements			66

Table of Contents

Index to Financial ~~Statements~~Statement

Report of Independent Registered Public Accounting Firm

~~Board~~Report 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~~Independent Registered 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.Firm

~~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~~

~~Table of Contents~~

~~Index to Financial Statements~~



~~ITEM 9B.~~	~~OTHER INFORMATION~~

~~None.~~

~~PART III~~



~~ITEM 10.~~	~~DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE~~

For information concerning Item 10-Directors, Executive Officers and Corporate Governance, see our definitive proxy statement, which will be filed with the Securities and Exchange Commission within 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).



~~ITEM 11.~~	~~EXECUTIVE COMPENSATION~~

For information concerning Item 11-Executive Compensation, see our definitive proxy statement, which will be filed with the Securities and Exchange Commission within 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).



~~ITEM 12.~~	~~SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS~~

For information concerning Item 12-Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters, see our definitive proxy statement, which will be filed with the Securities and Exchange Commission within 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).



~~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).



~~ITEM 14.~~	~~PRINCIPAL ACCOUNTING FEES AND SERVICES~~

For information concerning Item 14-Principal Accounting Fees and Services, 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).

~~Table of Contents~~

~~Index to Financial Statements~~

~~PART IV~~



~~ITEM 15.~~	~~EXHIBITS AND FINANCIAL STATEMENT SCHEDULES~~

~~The following documents are filed as part of this report or incorporated by reference herein:~~


~~(1)~~	~~Financial Statements~~

~~Reference is made to the Index to Financial Statements appearing on Page F-1.~~


~~(2)~~	~~Financial Statement Schedules~~

~~All financial statement schedules have been omitted because they are not applicable or the required disclosure is presented in the financial statements or notes thereto.~~


~~(3)~~	~~Exhibits~~



~~Exhibit~~ ~~Number~~		~~Description~~

~~2.1##~~		Purchase and Sale Agreement, dated as of December 13, 2016, by and among Gulfport Energy Corporation, SCOOP Acquisition Company, LLC and Vitruvian II Woodford, LLC (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 15, 2016).

~~3.1~~		~~Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, 2006).~~

~~3.2~~		Certificate of Amendment No. 1 to Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.2 to Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 6, 2009).

~~3.3~~		Certificate of Amendment No. 2 to Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on July 23, 2013).

~~3.4~~		~~Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on July 12, 2006).~~

~~3.5~~		~~First Amendment to the Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on July 23, 2013).~~

~~3.6~~		~~Second Amendment to the Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on May 2, 2014).~~

~~4.1~~		Form of Common Stock certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 2 to the Registration Statement on Form SB-2, File No. 333-115396, filed by the Company with the SEC on July 22, 2004).

~~4.2~~		Indenture, dated as of April 21, 2015, among the Company, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as trustee (including the form of the Company’s 6.625% Senior Notes due 2023) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 21, 2015).

~~4.3~~		Indenture, dated as of October 14, 2016, among Gulfport Energy Corporation, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as trustee (including the form of Gulfport Energy Corporation’s 6.000% Senior Notes due 2024) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 19, 2016).

~~4.4~~		Indenture, dated as of December 21, 2016, among Gulfport Energy Corporation, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as trustee (including the form of Gulfport Energy Corporation’s 6.375% Senior Notes due 2025) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 21, 2016).

~~4.5~~		Indenture, dated as of October 11, 2017, among Gulfport Energy Corporation, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as trustee (including the form of Gulfport Energy Corporation’s 6.375% Senior Notes due 2026) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 11, 2017).

~~4.6~~		Registration Rights Agreement, dated as of February 17, 2017, by and between Gulfport Energy Corporation and Vitruvian II Woodford, LLC (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K, File No. 000-19514, filed by the Company with the SEC on February 24, 2017).

~~Table of Contents~~

~~Index to Financial Statements~~



~~4.7~~		Voting Rights Waiver Agreement, dated June 10, 2015, by and among Gulfport Energy Corporation, Putnam Investment Management, LLC, The Putnam Advisory Company, LLC and Putnam Fiduciary Trust Company (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on June 12, 2015)

~~10.1+~~		~~2013 Restated Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to the Form S-4, File No. 333-189992, filed by the Company with the SEC on July 17, 2013).~~

~~10.2+~~		~~2014 Executive Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 7, 2014).~~

~~10.3+~~		~~Form of Stock Option Agreement (incorporated by reference to Exhibit 10.2 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, 2006).~~

~~10.4+~~		~~Form of Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.3 to the Form 10-K, File No. 000-19514, filed by the Company with the SEC on February 28, 2014).~~

~~10.5+~~		Separation and Release Agreement, dated as of January 31, 2014, by and between the Company and James D. Palm (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on February 4, 2014).

~~10.6+~~		Separation and Release Agreement, effective October 29, 2018, by and between Gulfport Energy Corporation and Michael G. Moore (incorporated by reference to Exhibit 10.3 to the Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 1, 2018).

~~10.7~~		Amended and Restated Credit Agreement, dated as of December 27, 2013, by and among the Company, as borrower, The Bank of Nova Scotia, as administrative agent, sole lead arranger and sole bookrunner, Amegy Bank National Association, as syndication agent, KeyBank National Association, as documentation agent, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on January 3, 2014).

~~10.8~~		First Amendment to Amended and Restated Credit Agreement, dated as of April 23, 2014, among Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent, sole lead arranger and sole bookrunner, Amegy Bank National Association, as syndication agent, KeyBank National Association, as documentation agent, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 28, 2014).

~~10.9~~		Second Amendment to Amended and Restated Credit Agreement, dated as of November 26, 2014, among Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 3, 2014).

~~10.10~~		Third Amendment to Amended and Restated Credit Agreement, dated as of April 10, 2015, among the Company, as borrower, The Bank of Nova Scotia, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 15, 2015).

~~10.11~~		Fourth Amendment to Amended and Restated Credit Agreement, dated as of May 29, 2015, among the Company, as borrower, the Bank of Nova Scotia, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.2 to the Form 10-Q, File No. 000-19514, filed by the Company with the SEC on August 7, 2015).

~~10.12~~		Fifth Amendment to Amended and Restated Credit Agreement, dated as of September 18, 2015, among the Company, as borrower, The Bank of Nova Scotia, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on September 24, 2015).

~~10.13~~		Sixth Amendment, dated February 19, 2016, to Amended and Restated Credit Agreement, dated as of September 18, 2015, among the Company, as borrower, The Bank of Nova Scotia, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.2 to the Form 10-Q, File No. 000-19514, filed by the Company with the SEC on May 5, 2016).

~~10.14~~		Seventh Amendment to Amended and Restated Credit Agreement, dated as of December 13, 2016, among Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 15, 2016).

~~Table of Contents~~

~~Index to Financial Statements~~



~~10.15~~		Eighth Amendment to Amended and Restated Credit Agreement, entered into as of March 29, 2017, among Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent and L/C issuer, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 4, 2017).

~~10.16~~		Ninth Amendment to Amended and Restated Credit Agreement, entered into as of May 4, 2017, among Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent and L/C issuer, the existing lenders named therein and JPMorgan Chase Bank, N.A., Commonwealth Bank of Australia, ABN, AMRO Capital USA LLC, Fifth Third Bank and Canadian Imperial Bank of Commerce, New York branch, as new lenders (incorporated by reference to Exhibit 10.2 to the Form 10-Q, File No. 000-19514, filed by the Company with the SEC on May 9, 2017).

~~10.17~~		Tenth Amendment to Amended and Restated Credit Agreement, dated as of October 4, 2017, among Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 5, 2017).

~~10.18~~		Eleventh Amendment to Amended and Restated Credit Agreement, dated as of November 21, 2017, among Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on November 28, 2017).

~~10.19~~		Twelfth Amendment to Amended and Restated Credit Agreement, dated as of May 21, 2018, among Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on May 25, 2018).

~~10.20~~		Thirteenth Amendment to the Amended and Restated Credit Agreement, dated as of November 28, 2018, between Gulfport Energy Corporation, as Borrower, The Bank of Nova Scotia, as Administrative Agent and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 4, 2018).

~~10.21#~~		Sand Supply Agreement, effective as of October 1, 2014, by and between Muskie Proppant LLC and Gulfport Energy Corporation (incorporated by reference to Exhibit 10.1 to the Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 7, 2014).

~~10.22#~~		Amendment to Sand Supply Agreement, dated as of November 3, 2015, by and between Muskie Proppant LLC and Gulfport Energy Corporation (incorporated by reference to Exhibit 10.2 to the Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 5, 2015).

~~10.23~~		Second Amendment to Sand Supply Agreement, dated as of August 6, 2018, between Gulfport Energy Corporation and Muskie Proppant LLC (incorporated by reference to Exhibit 10.2 to the Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 1, 2018).

~~10.24#~~		Amended and Restated Master Services Agreement, effective as of October 1, 2014, by and between Gulfport Energy Corporation and Stingray Pressure Pumping LLC (incorporated by reference to Exhibit 10.2 to the Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 7, 2014).

~~10.25#~~		Amendment to Amended and Restated Master Services Agreement, dated as of February 18, 2016 to be effective as of January 1, 2016, by and between Gulfport Energy Corporation and Stingray Pressure Pumping LLC.

~~10.26#~~		Amendment No. 2, dated as of July 10, 2018, between Stingray Pressure Pumping, LLC and Gulfport Energy Corporation to that certain Amended & Restated Master Services Agreement for Pressure Pumping Services, effective as of October 1, 2014, as amended effective January 1, 2016 (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q, File No. 000-19514, filed by the Company with the SEC on August 2, 2018).

~~10.27+~~		~~Form of Indemnification Agreement (incorporated by reference to Exhibit 10.1 to the Registration Statement on Form S-4, File No. 333-199905, filed by the Company with the SEC on November 6, 2014).~~

~~10.28+~~		Separation and Release Agreement by and between Gulfport Energy Corporation and Ross Kirtley entered into November 2, 2016 (incorporated by reference to Exhibit 10.1 to the Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 3, 2016).

~~10.29+~~		Employment Agreement, entered into as of April 28, 2017, effective as of January 1, 2017, by and between Gulfport Energy Corporation and Keri Crowell (incorporated by reference to Exhibit 10.3 to the Form 10-Q, File No. 000-19514, filed by the Company with the SEC on May 9, 2017).

~~Table of Contents~~

~~Index to Financial Statements~~



~~10.30+~~		Employment Agreement, entered into as of April 28, 2017, effective as of January 1, 2017, by and between Gulfport Energy Corporation and Stuart Maier (incorporated by reference to Exhibit 10.4 to the Form 10-Q, File No. 000-19514, filed by the Company with the SEC on May 9, 2017).

~~10.31+~~		Employment Agreement, entered into as of April 28, 2017, effective as of January 1, 2017, by and between Gulfport Energy Corporation and Steve Baldwin (incorporated by reference to Exhibit 10.5 to the Form 10-Q, File No. 000-19514, filed by the Company with the SEC on May 9, 2017).

14		~~Code of Ethics (incorporated by reference to Exhibit 14 of Form 8-K, File No. 000-19514, filed by the Company with the SEC on February 14, 2006).~~

21*		~~Subsidiaries of the Registrant.~~

23.1*		~~Consent of Grant Thornton LLP.~~

23.2*		~~Consent of Netherland, Sewell & Associates, Inc.~~

31.1*		~~Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.~~

31.2*		~~Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.~~

32.1**		Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.

32.2**		Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.

99.1*		~~Report of Netherland, Sewell & Associates, Inc~~.

101.INS*		~~XBRL Instance Document.~~

101.SCH*		~~XBRL Taxonomy Extension Schema Document.~~

101.CAL*		~~XBRL Taxonomy Extension Calculation Linkbase Document.~~

101.DEF*		~~XBRL Taxonomy Extension Definition Linkbase Document.~~

101.LAB*		~~XBRL Taxonomy Extension Labels Linkbase Document.~~

101.PRE*		~~XBRL Taxonomy Extension Presentation Linkbase Document.~~



*	~~Filed herewith.~~



**	~~Furnished herewith, not filed.~~



+	~~Management contract, compensatory plan or arrangement.~~



#	~~Confidential treatment with respect to certain portions of this agreement was granted by the SEC which portions have been omitted and filed separately with the SEC.~~

##	The schedules (or similar attachments) referenced in this agreement have been omitted in accordance with Item 601(b)(2) of Regulation S-K. A copy of any omitted schedule (or similar attachment) will be furnished supplementally to the Securities and Exchange Commission.

~~Table of Contents~~

~~Index to Financial Statements~~



~~ITEM 16.~~	~~FORM 10-K SUMMARY~~

~~None.~~

~~SIGNATURES~~

~~In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.~~

~~Date: February 28, 2019~~



~~GULFPORT ENERGY CORPORATION~~

~~By:~~		~~/s/ KERI CROWELL~~
		~~Keri Crowell~~ ~~Chief Financial Officer~~

~~In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.~~

~~Table of Contents~~

~~Index to Financial Statements~~



~~Date:~~	~~February 28, 2019~~	~~By:~~	~~/s/ DAVID M. WOOD~~
			~~David M. Wood~~ ~~Chief Executive Officer and President, Director~~ ~~(Principal Executive Officer)~~

~~Date:~~	~~February 28, 2019~~	~~By:~~	~~/s/ DAVID L. HOUSTON~~
			~~David L. Houston~~ ~~Chairman of the Board and Director~~

~~Date:~~	~~February 28, 2019~~	~~By:~~	~~/s/ KERI CROWELL~~
			~~Keri Crowell~~ ~~Chief Financial Officer~~ ~~(Principal Accounting and Financial Officer)~~

~~Date:~~	~~February 28, 2019~~	~~By:~~	~~/s/ DEBORAH G. ADAMS~~
			~~Deborah G. Adams~~ ~~Director~~

~~Date:~~	~~February 28, 2019~~	~~By:~~	~~/s/ CRAIG GROESCHEL~~
			~~Craig Groeschel~~ ~~Director~~

~~Date:~~	~~February 28, 2019~~	~~By:~~	~~/s/ C. DOUG JOHNSON~~
			~~C. Doug Johnson~~ ~~Director~~

~~Date:~~	~~February 28, 2019~~	~~By:~~	~~/s/ BEN T. MORRIS~~
			~~Ben T. Morris~~ ~~Director~~

~~Date:~~	~~February 28, 2019~~	~~By:~~	~~/s/ SCOTT E. STRELLER~~
			~~Scott E. Streller~~ ~~Director~~

~~Date:~~	~~February 28, 2019~~	~~By:~~	~~/s/ PAUL WESTERMAN~~
			~~Paul Westerman~~ ~~Director~~

~~S-1~~

~~Table of Contents~~

~~Index to Financial Statements~~



~~ITEM 8.~~	~~FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA~~

~~INDEX TO FINANCIAL STATEMENTS~~



	~~Page~~

~~Report of Independent Registered Public Accounting Firm~~	~~F-2~~

~~Consolidated Balance Sheets, December 31, 2018 and December 31, 2017~~	~~F-3~~

~~Consolidated Statements of Operations, Years Ended December 31, 2018, 2017, and 2016~~	~~F-4~~

~~Consolidated Statements of Comprehensive Income (Loss), Years Ended December 31, 2018, 2017, and 2016~~	~~F-5~~

~~Consolidated Statements of Stockholders' Equity, Years Ended December 31, 2018, 2017, and 2016~~	~~F-6~~

~~Consolidated Statements of Cash Flows, Year Ended December 31, 2018, 2017, and 2016~~	~~F-7~~

~~Notes to Consolidated Financial Statements~~	~~F-9~~

~~F-1~~

~~Table of Contents~~

~~Index to Financial Statements~~

Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholders

Gulfport Energy Corporation

Opinion on the financial statements

We have audited the accompanying consolidated balance sheets of Gulfport Energy Corporation (a Delaware corporation) and subsidiaries (Debtor-in-Possession) (the “Company”) as of December 31, ~~2018~~2020 and ~~2017, and~~2019, the related consolidated statements of operations, comprehensive income (loss), stockholders’ (deficit) equity, and cash flows for each of the three years in the period ended December 31, ~~2018,~~2020, and the related notes (collectively referred to as the ~~"financial statements"~~“financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, ~~2018~~2020 and ~~2017,~~2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, ~~2018,~~2020, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, ~~2018,~~2020, based on criteria established in the 2013 Internal ~~Control-Integrated~~Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated ~~February 28, 2019~~March 5, 2021 expressed an unqualified opinion.

Going Concern

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the financial statements, the Company filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code during the year ended December 31, 2020, which constituted an event of default that accelerated the Company's obligations under the Company's pre-petition revolving credit facility and the indentures governing the Company's senior notes, resulting in the principal and interest due thereunder becoming immediately due and payable. These conditions, along with other matters as set forth in Note 1, raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 1. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Basis for ~~Opinion~~opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. 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 audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence ~~supporting~~regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical audit matters

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Depletion expense and impairment of oil and gas properties impacted by the Company’s estimation of proved reserves

As described further in Note 1 to the financial statements, the Company uses the full cost method of accounting for oil and gas operations. This accounting method requires management to make estimates of proved reserves and related future net cash flows to compute and record depletion, depreciation and amortization, as well as to assess potential impairment of oil and gas properties (the full cost ceiling test). To estimate the volume of proved oil and gas reserve quantities, management makes significant estimates and assumptions including forecasting the production decline rate of producing properties and forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped properties. In addition, the estimation of proved reserves is also impacted by management’s judgments and estimates regarding the financial

Table of Contents

Index to Financial Statement s

performance of wells associated with those proved reserves to determine if wells are expected to be economical under the appropriate pricing assumptions that are required in the estimation of depletion, depreciation and amortization expense and potential ceiling test impairment assessments. We identified the estimation of proved reserves as it relates to the recognition of depletion, depreciation and amortization expense and the assessment of potential impairment as a critical audit matter.

The principal consideration for our determination that the estimation of proved reserves is a critical audit matter is that relatively minor changes in certain inputs and assumptions that are necessary to estimate the volume and future cash flows of the Company’s proved reserves could have a significant impact on the measurement of depletion, depreciation and amortization expense and/or impairment expense. In turn, auditing those inputs and assumptions required subjective and complex auditor judgment.

Our audit procedures related to the estimation of proved reserves included the following, among others:

•We tested the design and operating effectiveness of internal controls relating to management’s estimation of proved reserves for the purpose of estimating depletion, depreciation and amortization expense and assessing the Company’s oil and gas properties for potential ceiling test impairment;

•We evaluated the independence, objectivity, and professional qualifications of the Company’s reserves specialist, made inquiries of those reservoir engineers regarding the process followed and judgements made to estimate the Company’s proved reserve volumes and read the report prepared by the Company’s reserve specialist;

•We evaluated sensitive inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions that are derived from the Company’s accounting records, such as historical pricing differentials, operating costs, estimated capital costs, and ownership interest. We tested management’s process for determining the assumptions, including examining the underlying support, on a sample basis where applicable. Specifically, our audit procedures involved testing management’s assumptions as follows:

◦Compared the estimated pricing differentials used in the reserve report to realized prices related to revenue transactions recorded in the current year and examined contractual support for pricing differentials, where applicable;

◦Tested the model used to estimate the operating costs at year end and compared to historical operating costs;

◦Tested the model used to determine the future capital expenditures and compared estimated future capital expenditures used in the reserve report to amounts expended for recently drilled and completed wells, where applicable;

◦Tested the working and net revenue interests used in the reserve report by inspecting land and division order records;

◦Evaluated the Company’s evidence supporting the proved undeveloped properties reflected in the reserve report by examining historical conversion rates and support for the Company’s ability to fund and intent to develop the proved undeveloped properties; and

◦Applied analytical procedures to the reserve report by comparing to historical actual results and to the prior year’s reserve report.

/s/ GRANT THORNTON LLP

We have served as the Company's auditor since 2005.

Oklahoma City, Oklahoma

~~February 28, 2019~~March 5, 2021

~~F-2~~

Table of Contents

Index to Financial ~~Statements~~Statement

GULFPORT ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

December 31, 2018 December 31, 2017
(In thousands, except share data)
Assets
Current assets:
Cash and cash equivalents $ 52,297
$ 99,557
Accounts receivable—oil and natural gas sales 210,200
146,773
Accounts receivable—joint interest and other 22,497
35,440
Prepaid expenses and other current assets 10,607
4,912
Short-term derivative instruments 21,352
78,847
Total current assets 316,953
365,529
Property and equipment:
Oil and natural gas properties, full-cost accounting, $2,873,037 and $2,912,974 excluded from amortization in 2018 and 2017, respectively 10,026,836
9,169,156
Other property and equipment 92,667
86,754
Accumulated depletion, depreciation, amortization and impairment (4,640,098 ) (4,153,733 )
Property and equipment, net 5,479,405
5,102,177
Other assets:
Equity investments 236,121
302,112
Long-term derivative instruments —
8,685
Deferred tax asset —
1,208
Inventories 4,754
8,227
Other assets 13,803
19,814
Total other assets 254,678
340,046
Total assets $ 6,051,036
$ 5,807,752
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable and accrued liabilities $ 518,380
$ 553,609
Asset retirement obligation—current —
120
Short-term derivative instruments 20,401
32,534
Current maturities of long-term debt 651
622
Total current liabilities 539,432
586,885
Long-term derivative instruments 13,992
2,989
Asset retirement obligation—long-term 79,952
74,980
Deferred tax liability 3,127
—
Other non-current liabilities —
2,963
Long-term debt, net of current maturities 2,086,765
2,038,321
Total liabilities 2,723,268
2,706,138
Commitments and contingencies (Notes 16 and 17)

Preferred stock, $.01 par value; 5,000,000 authorized, 30,000 authorized as redeemable 12% cumulative preferred stock, Series A; 0 issued and outstanding —
—
Stockholders’ equity:
Common stock, $.01 par value; 200,000,000 authorized, 162,986,045 issued and outstanding in 2018 and 183,105,910 in 2017 1,630
1,831
Paid-in capital 4,227,532
4,416,250
Accumulated other comprehensive loss (56,026 ) (40,539 )
Accumulated deficit (845,368 ) (1,275,928 )
Total stockholders’ equity 3,327,768
3,101,614
Total liabilities and stockholders’ equity $ 6,051,036
$ 5,807,752
(DEBTOR-IN-POSSESSION)


	December 31, 2020		December 31, 2019
	(In thousands, except share data)
Assets
Current assets:
Cash and cash equivalents	$	89,861	$	6,060

Accounts receivable—oil and natural gas sales	119,879		121,210
Accounts receivable—joint interest and other	12,200		47,975

Prepaid expenses and other current assets	160,664		4,431

Short-term derivative instruments	27,146		126,201
Total current assets	409,750		305,877
Property and equipment:
Oil and natural gas properties, full-cost accounting, $1,457,043 and $1,686,666 excluded from amortization in 2020 and 2019, respectively	10,816,909		10,595,735
Other property and equipment	88,538		96,719
Accumulated depletion, depreciation, amortization and impairment	(8,819,178)		(7,228,660)
Property and equipment, net	2,086,269		3,463,794
Other assets:
Equity investments	24,816		32,044
Long-term derivative instruments	322		563
Deferred tax asset	0		7,563

Operating lease assets	342		14,168
Operating lease assets - related parties	0		43,270
Other assets	18,372		15,540
Total other assets	43,852		113,148
Total assets	$	2,539,871	$	3,882,819
Liabilities and stockholders’ (deficit) equity
Current liabilities:
Accounts payable and accrued liabilities	$	244,903	$	415,218

Short-term derivative instruments	11,641		303

Current portion of operating lease liabilities	0		13,826
Current portion of operating lease liabilities - related parties	0		21,220
Current maturities of long-term debt	253,743		631
Total current liabilities	510,287		451,198
Non-current liabilities:
Long-term derivative instruments	36,604		53,135
Asset retirement obligation—long-term	0		60,355
Uncertain tax position liability	0		3,127
Non-current operating lease liabilities	0		342
Non-current operating lease liabilities - related parties	0		22,050

Long-term debt, net of current maturities	0		1,978,020
Total non-current liabilities	36,604		2,117,029
Liabilities subject to compromise	2,293,480		0
Total liabilities	2,840,371		2,568,227
Commitments and contingencies (Notes 17 and 18)	0		0
Preferred stock, $0.01 par value; 5,000,000 authorized (30,000 authorized as redeemable 12% cumulative preferred stock, Series A), and NaN issued and outstanding	0		0
Stockholders’ (deficit) equity:
Common stock - $0.01 par value, 200,000,000 shares authorized, 160,762,186 issued and outstanding in 2020 and 159,710,955 in 2019	1,607		1,597
Paid-in capital	4,213,752		4,207,554
Accumulated other comprehensive loss	(43,000)		(46,833)
Accumulated deficit	(4,472,859)		(2,847,726)
Total stockholders’ (deficit) equity	(300,500)		1,314,592
Total liabilities and stockholders’ (deficit) equity	$	2,539,871	$	3,882,819

See accompanying notes to consolidated financial statements.

~~F-3~~

Table of Contents

Index to Financial ~~Statements~~Statement

GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(DEBTOR-IN-POSSESSION)


											For the Year Ended December 31,
	For the Year Ended December 31,										2020		2019		2018
	2018			2017			2016				(In thousands, except share data)
	(In thousands, except share data)
Revenues:
REVENUES:										REVENUES:
Natural gas sales	$	1,121,815		$	845,999		$	420,128		Natural gas sales	$	671,535	$	1,135,381	$	1,318,472
Oil and condensate sales	177,793			124,568			81,173			Oil and condensate sales	62,902		117,937		177,793
Natural gas liquid sales	178,915			136,057			59,115			Natural gas liquid sales	66,814		101,448		178,915
Net (loss) gain on natural gas, oil, and NGL derivatives	(123,479		)	213,679			(174,506		)
	1,355,044			1,320,303			385,910
Costs and expenses:
Net gain (loss) on natural gas, oil, and NGL derivatives										Net gain (loss) on natural gas, oil, and NGL derivatives	65,291		208,360		(123,479)
Total Revenues										Total Revenues	866,542		1,563,126		1,551,701
OPERATING EXPENSES:										OPERATING EXPENSES:
Lease operating expenses	91,640			80,246			68,877			Lease operating expenses	54,235		73,496		79,716
Production taxes	33,480			21,126			13,276
Taxes other than income										Taxes other than income	28,509		40,510		48,298
Midstream gathering and processing expenses	290,188			248,995			165,972			Midstream gathering and processing expenses	456,318		508,843		486,845
Depreciation, depletion and amortization	486,664			364,629			245,974			Depreciation, depletion and amortization	239,744		550,108		486,664
Impairment of oil and natural gas properties	—			—			715,495			Impairment of oil and natural gas properties	1,357,099		2,039,770		0
General and administrative expenses	56,633			52,938			43,409			General and administrative expenses	59,329		45,542		47,100
Restructuring and liability management expenses										Restructuring and liability management expenses	30,847		4,611		0
Accretion expense	4,119			1,611			1,057			Accretion expense	3,066		3,939		4,119
Acquisition expense	—			2,392			—
	962,724			771,937			1,254,060
INCOME (LOSS) FROM OPERATIONS	392,320			548,366			(868,150		)
OTHER (INCOME) EXPENSE:

Total Operating Expenses										Total Operating Expenses	2,229,147		3,266,819		1,152,742
(LOSS) INCOME FROM OPERATIONS										(LOSS) INCOME FROM OPERATIONS	(1,362,605)		(1,703,693)		398,959
OTHER EXPENSE (INCOME):										OTHER EXPENSE (INCOME):
Interest expense	135,273			108,198			63,530			Interest expense	120,079		141,786		141,912
Interest income	(314		)	(1,009		)	(1,230		)	Interest income	(414)		(801)		(314)
Litigation settlement	1,075			—			—
Insurance proceeds	(231		)	—			(5,718		)
Loss on debt extinguishment	—			—			23,776

Gain on debt extinguishment										Gain on debt extinguishment	(49,579)		(48,630)		0

Gain on sale of equity method investments	(124,768		)	(12,523		)	(3,391		)	Gain on sale of equity method investments	0		0		(124,768)
(Income) loss from equity method investments, net	(49,904		)	17,780			37,376
Other expense (income), net	698			(1,041		)	129
	(38,171		)	111,405			114,472
INCOME (LOSS) BEFORE INCOME TAXES	430,491			436,961			(982,622		)
INCOME TAX (BENEFIT) EXPENSE	(69		)	1,809			(2,913		)
NET INCOME (LOSS)	$	430,560		$	435,152		$	(979,709	)
NET INCOME (LOSS) PER COMMON SHARE:
Loss (income) from equity method investments, net										Loss (income) from equity method investments, net	11,055		210,148		(49,904)
Reorganization items, net										Reorganization items, net	152,359		0		0
Other expense, net										Other expense, net	21,738		3,725		1,542
Total Other Expense (Income)										Total Other Expense (Income)	255,238		306,228		(31,532)
(LOSS) INCOME BEFORE INCOME TAXES										(LOSS) INCOME BEFORE INCOME TAXES	(1,617,843)		(2,009,921)		430,491
INCOME TAX EXPENSE (BENEFIT)										INCOME TAX EXPENSE (BENEFIT)	7,290		(7,563)		(69)
NET (LOSS) INCOME										NET (LOSS) INCOME	$	(1,625,133)	$	(2,002,358)	$	430,560
NET (LOSS) INCOME PER COMMON SHARE:										NET (LOSS) INCOME PER COMMON SHARE:
Basic	$	2.46		$	2.42		$	(7.97	)	Basic	$	(10.14)	$	(12.49)	$	2.46
Diluted	$	2.45		$	2.41		$	(7.97	)	Diluted	$	(10.14)	$	(12.49)	$	2.45
Weighted average common shares outstanding—Basic	174,675,840			179,834,146			122,952,866			Weighted average common shares outstanding—Basic	160,231,335		160,341,125		174,675,840
Weighted average common shares outstanding—Diluted	175,398,706			180,253,024			122,952,866			Weighted average common shares outstanding—Diluted	160,231,335		160,341,125		175,398,706

See accompanying notes to consolidated financial statements.

~~F-4~~

Table of Contents

Index to Financial ~~Statements~~Statement

GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME ~~(LOSS)~~

(DEBTOR-IN-POSSESSION)


	For the Year Ended December 31,
	2020		2019		2018
	(In thousands)
Net (loss) income	$	(1,625,133)	$	(2,002,358)	$	430,560
Foreign currency translation adjustment (1)	3,833		9,193		(15,487)


Other comprehensive income (loss)	3,833		9,193		(15,487)
Comprehensive (loss) income	$	(1,621,300)	$	(1,993,165)	$	415,073

For the Year Ended December 31,
2018 2017 2016
(In thousands)
Net income (loss) $ 430,560
$ 435,152
$ (979,709 )
Foreign currency translation adjustment (1) (15,487 ) 12,519
2,119
Other comprehensive (loss) income (15,487 ) 12,519
2,119
Comprehensive income (loss) $ 415,073
$ 447,671
$ (977,590 )
_____________________

(1) ~~Net of $1.3 million in taxes for the year ended December 31, 2016. No~~NaN taxes were recorded for the years ended December 31, ~~2018~~2020, 2019 and ~~December 31, 2017.~~2018.

See accompanying notes to consolidated financial statements.

~~F-5~~63

Table of Contents

Index to Financial ~~Statements~~Statement s

GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ (DEFICIT) EQUITY

(DEBTOR-IN-POSSESSION)


																														Paid-in Capital				Accumulated Other Comprehensive Loss		Accumulated Deficit		Total Stockholders’ (Deficit) Equity
						Paid-in Capital				Accumulated Other Comprehensive Loss				Accumulated Deficit				Total Stockholders’ Equity					Common Stock
	Common Stock												Shares								Amount
	Shares		Amount										(In thousands, except share data)
	(In thousands, except share data)
Balance at January 1, 2016	108,322,250		$	1,082					$		2,824,303						$				(55,177	)		$	(731,371	)	$	2,038,837
Net Loss	—		—						—				—							(979,709		)		(979,709		)
Other Comprehensive Income	—		—			—					2,119					—				2,119
Stock-based Compensation	—		—			12,251				—				—				12,251
Issuance of Common Stock in public offerings, net of related expenses	50,255,000		503			1,109,891				—				—				1,110,394
Issuance of Restricted Stock	252,566		3			(3		)		—				—				—
Balance at December 31, 2016	158,829,816		1,588			3,946,442				(53,058		)		(1,711,080		)		2,183,892
Net Income	—		—			—				—				435,152				435,152
Other Comprehensive Income	—		—			—				12,519				—				12,519
Stock-based Compensation	—		—			10,615				—				—				10,615
Issuance of Common Stock for the Vitruvian Acquisition, net of related expenses	23,852,117		239			459,197				—				—				459,436
Issuance of Restricted Stock	423,977		4			(4		)										—
Balance at December 31, 2017	183,105,910		1,831			4,416,250				(40,539		)		(1,275,928		)		3,101,614
Balance at January 1, 2018																					Balance at January 1, 2018		183,105,910					$	1,831			$	4,416,250			$	(40,539)	$	(1,275,928)	$	3,101,614
Net Income	—		—			—				—				430,560				430,560			Net Income		—					—			—				—		430,560		430,560
Other Comprehensive Loss	—		—			—				(15,487		)		—				(15,487		)	Other Comprehensive Loss		—					—		—				(15,487)		—		(15,487)
Stock-based Compensation	—		—			11,332				—				—				11,332			Stock-based Compensation		—					—		11,332				—		—		11,332
Shares Repurchased	(20,746,536	)	(207		)	(200,044		)		—				—				(200,251		)	Shares Repurchased		(20,746,536)					(207)		(200,044)				—		—		(200,251)
Issuance of Restricted Stock	626,671		6			(6		)		—				—				—			Issuance of Restricted Stock		626,671					6		(6)				—		—		0
Balance at December 31, 2018	162,986,045		$	1,630		$	4,227,532			$	(56,026	)		$	(845,368	)		$	3,327,768		Balance at December 31, 2018		162,986,045					$	1,630	$	4,227,532			$	(56,026)	$	(845,368)	$	3,327,768
Net Loss																					Net Loss		—					—		—				—		(2,002,358)		(2,002,358)
Other Comprehensive Income																					Other Comprehensive Income		—					—		—				9,193		—		9,193
Stock-based Compensation																					Stock-based Compensation		—					—		10,677				—		—		10,677

Shares Repurchased																					Shares Repurchased		(3,951,198)					(40)		(30,648)				—		—		(30,688)
Issuance of Restricted Stock																					Issuance of Restricted Stock		676,108					7		(7)				—		—		0
Balance at December 31, 2019																					Balance at December 31, 2019		159,710,955					$	1,597	$	4,207,554			$	(46,833)	$	(2,847,726)	$	1,314,592
Net Loss																					Net Loss		—					—		—				—		(1,625,133)		(1,625,133)
Other Comprehensive Income																					Other Comprehensive Income		—					—		—				3,833		—		3,833
Stock-based Compensation																					Stock-based Compensation		—					—		6,444				—		—		6,444

Shares Repurchased																					Shares Repurchased		(243,054)					(3)		(233)				—		—		(236)
Issuance of Restricted Stock																					Issuance of Restricted Stock		1,294,285					13		(13)				—		—		0
Balance at December 31, 2020																					Balance at December 31, 2020		160,762,186					$	1,607	$	4,213,752			$	(43,000)	$	(4,472,859)	$	(300,500)

See accompanying notes to consolidated financial statements.

~~F-6~~

Table of Contents

Index to Financial ~~Statements~~Statement

~~GULFPORT ENERGY CORPORATION~~

~~CONSOLIDATED STATEMENTS OF CASH FLOWS~~

Year Ended December 31,
2018 2017 2016
(In thousands)
Cash flows from operating activities:
Net income (loss) $ 430,560
$ 435,152
$ (979,709 )
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Accretion expense 4,119
1,611
1,057
Depletion, depreciation and amortization 486,664
364,629
245,974
Impairment of oil and gas properties —
—
715,495
Stock-based compensation expense 6,799
6,369
7,351
(Income) loss from equity investments (49,625 ) 18,513
37,788
Gain on debt extinguishment —
—
(1,108 )
Change in fair value of derivative instruments 65,051
(188,802 ) 323,303
Deferred income tax expense 1,208
1,690
18,188
Amortization of loan costs 6,121
5,011
3,660
Amortization of note discount and premium —
—
(1,716 )
Gain on sale of equity method investments (124,768 ) (12,523 ) (3,391 )
Distributions from equity method investments 3,206
—
—
Changes in operating assets and liabilities:
Increase in accounts receivable—oil and natural gas sales (63,427 ) (35,879 ) (76,269 )
Decrease (increase) in accounts receivable—joint interest and other 12,943
(9,573 ) 11,380
Decrease in accounts receivable—related parties —
16
—
Increase in prepaid expenses and other current assets (5,695 ) (1,777 ) (3,734 )
Decrease (increase) in other assets 4,066
(7,866 ) —
(Decrease) increase in accounts payable, accrued liabilities and other (24,015 ) 106,375
43,763
Settlement of asset retirement obligation (719 ) (3,057 ) (4,189 )
Net cash provided by operating activities 752,488
679,889
337,843
Cash flows from investing activities:
Deductions to cash held in escrow —
8
8
Additions to other property and equipment (7,870 ) (19,372 ) (33,152 )
Acquisitions of oil and natural gas properties —
(1,348,657 ) —
Additions to oil and natural gas properties (865,300 ) (1,064,678 ) (724,925 )
Proceeds from sale of oil and gas properties 5,114
4,866
45,812
Proceeds from sale of other property and equipment 351
1,569
—
Proceeds from sale of equity method investments 226,487
—
—
Contributions to equity method investments (2,319 ) (55,280 ) (26,472 )
Distributions from equity method investments 446
7,376
18,147
Net cash used in investing activities (643,091 ) (2,474,168 ) (720,582 )
Cash flows from financing activities:
Principal payments on borrowings (220,575 ) (365,276 ) (87,685 )
Borrowings on line of credit 265,000
365,000
86,000
Proceeds from bond issuance —
450,000
1,250,000
Repayment of bonds —
—
(624,561 )
Borrowings on term loan —
2,951
21,049
Debt issuance costs and loan commitment fees (831 ) (14,350 ) (24,718 )
Payments on repurchase of stock (200,251 ) —
—
Proceeds from issuance of common stock, net of offering costs and exercise of stock options —
(5,364 ) 1,110,555
Net cash (used in) provided by financing activities (156,657 ) 432,961
1,730,640
Net (decrease) increase in cash, cash equivalents and restricted cash (47,260 ) (1,361,318 ) 1,347,901
Cash, cash equivalents and restricted cash at beginning of period 99,557
1,460,875
112,974
Cash, cash equivalents and restricted cash at end of period $ 52,297
$ 99,557
$ 1,460,875

~~(Continued on next page)~~

~~F-7~~

~~Table of Contents~~

~~Index to Financial Statements~~

GULFPORT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS ~~(continued)~~

(DEBTOR-IN-POSSESSION)

Supplemental disclosure of cash flow information:
Interest payments $ 126,342
$ 101,958
$ 68,966
Income tax receipts $ —
$ (1,105 ) $ (19,770 )
Supplemental disclosure of non-cash transactions:
Capitalized stock-based compensation $ 4,533
$ 4,246
$ 4,900
Asset retirement obligation capitalized $ 1,452
$ 42,270
$ 10,971
Interest capitalized $ 4,470
$ 9,470
$ 9,148
Foreign currency translation (loss) gain on equity method investments $ (15,487 ) $ 12,519
$ 3,468


	Year Ended December 31,
	2020		2019		2018
	(In thousands)
Cash flows from operating activities:
Net (loss) income	$	(1,625,133)	$	(2,002,358)	$	430,560
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depletion, depreciation and amortization	239,744		550,108		486,664
Impairment of oil and natural gas properties	1,357,099		2,039,770		0
Loss (income) from equity investments, net	11,055		210,289		(49,625)
Gain on debt extinguishment	(49,579)		(48,630)		0


Net loss (gain) on derivative instruments	(65,291)		(208,360)		123,479
Net cash receipts on settled derivative instruments	159,394		123,130		(58,428)
Non-cash reorganization items, net	21,956		0		0
Deferred income tax expense (benefit)	7,290		(7,563)		1,208

Gain on sale of equity method investments and other assets	0		(220)		(124,768)
Distributions from equity method investments	0		2,457		3,206
Other, net	31,984		15,178		17,039
Changes in operating assets and liabilities, net	6,785		50,192		(43,064)
Net cash provided by operating activities	95,304		723,993		786,271
Cash flows from investing activities:


Additions to oil and natural gas properties	(367,287)		(720,057)		(899,083)
Proceeds from sale of oil and gas properties	50,971		48,527		5,114

Proceeds from sale of equity method investments	0		0		226,487
Other, net	1,729		(3,241)		(9,392)

Net cash used in investing activities	(314,587)		(674,771)		(676,874)
Cash flows from financing activities:
Principal payments on pre-petition revolving credit facility	(383,290)		(877,000)		(220,000)
Borrowings on pre-petition revolving credit facility	713,701		952,000		265,000

Principal payments on DIP credit facility	(90,000)		0		0
Borrowings on DIP credit facility	90,000		0		0
Repurchase of senior notes	(22,827)		(138,786)		0

DIP credit facility financing fees	(2,988)		0		0
Payments on repurchase of stock under approved stock repurchase programs	0		(30,000)		(200,251)
Other, net	(1,512)		(1,673)		(1,406)

Net cash provided (used in) by financing activities	303,084		(95,459)		(156,657)
Net increase (decrease) in cash, cash equivalents and restricted cash	83,801		(46,237)		(47,260)
Cash, cash equivalents and restricted cash at beginning of period	6,060		52,297		99,557
Cash, cash equivalents and restricted cash at end of period	$	89,861	$	6,060	$	52,297

See accompanying notes to consolidated financial statements.

~~F-8~~

Table of Contents

Index to Financial ~~Statements~~Statement

GULFPORT ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

~~DECEMBER 31, 2018, 2017 AND 2016~~(DEBTOR-IN-POSSESSION)

1.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES


1.	~~SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES~~

Business

Gulfport Energy Corporation, ~~(“Gulfport” or the “Company”)~~a Delaware corporation formed in 1997, is an independent ~~oil and gas~~natural gas-weighted exploration ~~development~~ and production company ~~with its~~focused on the production of natural gas, crude oil and NGL in the United States. The Company's principal properties are located ~~in the Utica Shale primarily~~ in Eastern Ohio targeting the Utica formation and in central Oklahoma targeting the SCOOP Woodford and SCOOP Springer ~~plays in Oklahoma. The Company also holds an acreage position along~~formations.

Voluntary Reorganization Under Chapter 11 of the ~~Louisiana Gulf Coast in~~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 West Cote Blanche Bay and Hackberry fields and has an interest in producing properties in Northwestern Colorado in the Niobrara Formation and in Western North Dakota in the Bakken Formation, and has investments in companies operatingUnited States Code in the United States ~~Canada~~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). The debtors continue to operate their businesses as "debtors-in-possession" under the jurisdiction of the Bankruptcy Court, in accordance with the applicable provisions of the Bankruptcy Code and ~~Thailand.~~

~~Cash and Cash Equivalents~~the orders of the Bankruptcy Court.

The commencement of a voluntary proceeding in bankruptcy constituted an event of default that accelerated the Company's obligations under the Company's Pre-Petition Revolving Credit Facility and the indentures governing the Company's senior notes, resulting in the principal and interest due thereunder becoming immediately due and payable. Subject to certain specific exceptions under the Bankruptcy Code, the filing of the Chapter 11 Cases automatically stayed all judicial or administrative actions against the Company ~~considers~~and efforts by creditors to collect on or otherwise exercise rights or remedies with respect to pre-petition claims. Absent an order from the Bankruptcy Court, substantially all ~~highly liquid investments~~of the Debtors’ pre-petition liabilities are subject to settlement under the Bankruptcy Code.

The Company has applied FASB ASC Topic 852 - Reorganizations ("ASC 852") in preparing the consolidated financial statements, which specifies the accounting and financial reporting requirements for entities reorganizing through Chapter 11 bankruptcy proceedings. These requirements include distinguishing transactions associated with the reorganization separate from activities related to the ongoing operations of the business. Accordingly, pre-petition liabilities that may be impacted by the Chapter 11 proceedings have been classified as liabilities subject to compromise on the consolidated balance sheet as of December 31, 2020. Additionally, certain expenses, realized gains and losses and provisions for losses that are realized or incurred during the Chapter 11 Cases, including adjustments to the carrying value of certain indebtedness are recorded as reorganization items, net in the consolidated statements of operations for the year ended December 31, 2020. Refer to Note 2 for more information on the events of the bankruptcy proceedings as well as the accounting and reporting impacts of the reorganization.

Ability to Continue as a Going Concern

The accompanying consolidated financial statements are prepared in accordance with generally accepted accounting principles applicable to a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business.

As discussed above, the filing of the Chapter 11 Cases constituted an ~~original maturity~~event of ~~three months~~default under the Company’s Pre-Petition Revolving Credit Facility and the indentures governing the Company's senior notes (the "Default"), resulting in the principal and interest due thereunder becoming immediately due and payable. The Company does not have sufficient cash on hand or ~~less~~available liquidity to repay these amounts due. These conditions and events raise substantial doubt about the Company’s ability to continue as a going concern.

As part of the Chapter 11 Cases, the Company submitted the Plan to the Bankruptcy Court. The Company’s operations and its ability to develop and execute its business plan are subject to a high degree of risk and uncertainty associated with the Chapter 11 Cases. The outcome of the Chapter 11 Cases is subject to a high degree of uncertainty and is dependent upon factors that are outside of the Company’s control, including actions of the Bankruptcy Court and the Company’s creditors.

Table of Contents

Index to Financial Statement s

There can be no assurance that the Company will confirm and consummate the plan of reorganization as contemplated by the RSA with certain holders of the Company’s senior notes or complete another plan of reorganization with respect to the Chapter 11 Cases. As a result, the Company has concluded that management’s plans do not alleviate substantial doubt about the Company’s ability to continue as a going concern.

While operating as a debtor-in-possession, the Company may settle liabilities, subject to the approval of the Bankruptcy Court or as otherwise permitted in the ordinary course of business, for amounts other than those reflected in the accompanying consolidated financial statements. Further, the Plan or other bankruptcy proceedings could materially change the amounts and classifications of assets and liabilities reported in the consolidated financial statements, including liabilities subject to compromise which will be resolved in connection with the Chapter 11 Cases. The accompanying consolidated financial statements do not include any adjustments related to the recoverability and classification of assets or the amounts and classification of liabilities or any other adjustments that might be necessary should the Company be unable to continue as a going concern or as a consequence of the Chapter 11 Cases.

Risks and Uncertainties

In March 2020, the World Health Organization classified the outbreak of COVID-19 as a pandemic and recommended containment and mitigation measures worldwide. The measures have led to worldwide shutdowns and halting of commercial and interpersonal activity, as governments around the world have imposed regulations in efforts to control the spread of COVID-19 such as shelter-in-place orders, quarantines, executive orders and similar restrictions.

Gulfport remains focused on protecting the health and well-being of its employees and the communities in which it operates while assuring the continuity of its business operations. The Company implemented preventative measures and developed corporate and field response plans to minimize unnecessary risk of exposure and prevent infection. Additionally, the Company has a crisis management team for health, safety and environmental matters and personnel issues, and has established a COVID-19 Response Team to address various impacts of the situation, as they have been developing. Gulfport has modified certain business practices (including remote working for its corporate employees and restricted employee business travel) to conform to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention, the World Health Organization and other governmental and regulatory authorities. In May 2020, the Company began its phased transition back to the office for its corporate employees. As part of this transition, the Company put into place preventative measures to focus on social distancing and minimizing unnecessary risk of exposure. As of the date of this filing, Gulfport has transitioned the vast majority of its employees back to the corporate office; however, the Company continues to provide a balanced work schedule that allows for a significant portion of the work week to be ~~cash equivalents~~performed remotely. The Company will continue to monitor trends and governmental guidelines and may adjust its return to office plans accordingly to ensure the health and safety of its employees. As a result of its business continuity measures, the Company has not experienced significant disruptions in executing its business operations in 2020.

On March 27, 2020, the U.S. government enacted the Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”). The CARES Act did not have a material impact on the Company’s consolidated financial statements. Gulfport is closely monitoring the impact of COVID-19 on all aspects of its business and the current commodity price environment and is unable to predict the impact it will have on its future financial position or operating results.

Decreased demand for ~~purposes~~oil and natural gas as a result of the ~~statement~~COVID-19 pandemic has put further downward pressure on commodity pricing. In the current depressed commodity price environment and period of ~~cash flows.~~economic uncertainty, the Company has taken the following operational and financial measures in 2020 to improve its balance sheet and preserve liquidity:

•Reduced 2020 capital spending by more than 50% as compared to 2019

•Focused on operational efficiencies to reduce operating costs; including significant improvements in development and completion costs per lateral foot

•Repurchased $73.3 million of unsecured notes at a discount

•Evaluated economics across our portfolio and shut-in certain non-economical production in the second quarter of 2020

•Reduced recurring corporate general and administrative costs significantly through pay reductions, furloughs and reductions in force.

Table of Contents

Index to Financial Statement s

Although management’s actions listed above have helped to improve the Company's liquidity and leverage profile, continued macro headwinds including the depressed state of energy capital markets and the extraordinarily low commodity price environments resulted in the Company filing for protection under Bankruptcy Rules as noted above.

Principles of Consolidation

The consolidated financial statements include the Company and its wholly-owned subsidiaries, Grizzly Holdings Inc., Jaguar Resources LLC, Gator Marine, Inc., Gator Marine Ivanhoe, Inc., Westhawk Minerals LLC, Puma Resources, Inc., Gulfport Appalachia LLC, Gulfport Midstream Holdings, LLC, ~~and~~ Gulfport MidCon, LLC and Mule Sky LLC. All intercompany balances and transactions are eliminated in consolidation.

Cash and Cash Equivalents

The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents for purposes of the consolidated financial statements.

Accounts Receivable

The Company sells oil and natural gas to various purchasers and participates in drilling, completion and operation of oil and natural gas wells with joint interest owners on properties the Company operates. The related receivables are classified as accounts receivable—oil and natural gas sales and accounts receivable—joint interest and other, respectively. Credit is extended based on evaluation of a customer’s payment history and, generally, collateral is not required. Accounts receivable are due within 30 days and are stated at amounts due from customers, net of an allowance for doubtful accounts when the Company believes collection is doubtful. Accounts outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the customer’s current ability to pay its obligation to the Company, amounts which may be obtained by an offset against production proceeds due the customer and the condition of the general economy and the industry as a whole. ~~The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. No~~NaN material allowance was deemed necessary at December 31, ~~2018~~2020 and December 31, ~~2017.~~2019.

Oil and Gas Properties

The Company uses the full cost method of accounting for oil and gas operations. Accordingly, all costs, including nonproductive costs and certain general and administrative costs directly associated with acquisition, exploration and development of oil and gas properties, are capitalized. Additionally, interest is capitalized on the cost of unproved oil and natural gas properties that are excluded from amortization for which exploration and development activities are in process or expected within the next 12 months.

Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the 12-month unweighted average of the first-day-of-the-month price, ~~for 2018, 2017 and 2016,~~ adjusted for any contract provisions or financial derivatives, if any, that hedge the Company’s oil and natural gas revenue (only to the extent that the derivative instruments are treated as cash flow hedges for accounting purposes), and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of unproved properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or noncash writedown is required. Ceiling test impairment can result in a significant loss for a particular period; however, future depletion expense

~~F-9~~

~~Table of Contents~~

~~Index to Financial Statements~~

would be reduced. A decline in oil and gas prices may result in an impairment of oil and gas properties. ~~The~~As a result of the decline in commodity prices throughout 2020, the Company ~~did not recognize a~~recognized ceiling test ~~impairment~~impairments of $1.4 billion for the year ended December 31, ~~2018.~~2020.

Such capitalized costs, including the estimated future development costs and site remediation costs of proved undeveloped properties, are depleted by an equivalent units-of-production method, converting barrels to gas at the ratio of one barrel of oil to ~~six~~6 Mcf of gas. No gain or loss is recognized upon the disposal of oil and gas properties, unless such dispositions significantly alter the relationship between capitalized costs and ~~proven~~proved oil and gas reserves. Oil and gas properties not subject to amortization consist of the cost of unproved leaseholds and totaled approximately ~~$2.9~~$1.5 billion and $1.7 billion at ~~both~~ December 31, ~~2018~~2020 and December 31, ~~2017.~~2019, respectively. These costs are reviewed quarterly by management for impairment. If impairment

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has occurred, the portion of cost in excess of the current value is transferred to the cost of oil and gas properties subject to amortization. Factors considered by management in its impairment assessment include drilling results by Gulfport and other operators, the terms of oil and gas leases not held by production, and available funds for exploration and development.

The Company accounts for its abandonment and restoration liabilities by recording a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability is recorded in the period in which the obligation meets the definition of a liability, which is generally when the asset is placed into service. When the liability is initially recorded, the Company increases the carrying amount of oil and natural gas properties by an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is included in capitalized costs and depreciated consistent with depletion of reserves. Upon settlement of the liability or the sale of the well, the liability is reversed. These liability amounts may change because of changes in asset lives, estimated costs of abandonment or legal or statutory remediation requirements.

Other Property and Equipment

Depreciation of other property and equipment is provided on a straight-line basis over the estimated useful lives of the related assets, which range from 3 to 30 years.

Foreign Currency

The U.S. dollar is the functional currency for Gulfport’s consolidated operations. However, the Company has an equity investment in a Canadian entity whose functional currency is the Canadian dollar. The assets and liabilities of the Canadian investment are translated into U.S. dollars based on the current exchange rate in effect at the balance sheet dates. Canadian income and expenses are translated at average rates for the periods presented and equity contributions are translated at the current exchange rate in effect at the date of the contribution. In addition, the Company has an equity investment in a U.S. company that has a subsidiary that is a Canadian entity whose functional currency is the Canadian dollar. Translation adjustments have no effect on net income and are included in accumulated other comprehensive income in stockholders’ (deficit) equity. The following table presents the balances of the Company’s cumulative translation adjustments included in accumulated other comprehensive loss, exclusive of taxes.

(In thousands)
December 31, 2015 $ (55,175 )
December 31, 2016 $ (51,709 )
December 31, 2017 $ (39,190 )
December 31, 2018 $ (54,677 )


			(In thousands)
December 31, 2017			(39,190)
December 31, 2018			(54,677)
December 31, 2019			(45,484)
December 31, 2020			(41,651)

Net (Loss) Income per Common Share

Basic net (loss) income per common share is computed by dividing income attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net (loss) income per common share reflects the potential dilution that could occur if options or other contracts to issue common stock were exercised or converted into common stock. Potential common shares are not included if their effect would be anti-dilutive. Calculations of basic and diluted net (loss) income per common share are illustrated in Note ~~12.~~12.

Income Taxes

~~F-10~~

~~Table of Contents~~

~~Index to Financial Statements~~

Gulfport uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income during the period the rate change is enacted. Deferred tax assets are recognized as income in the year in which realization becomes determinable. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized.

The Company is subject to U.S. federal income tax as well as income tax of multiple jurisdictions. The Company’s ~~2004~~2003 – ~~2017~~2019 U.S. federal and ~~1998~~2009 - ~~2017~~2019 state income tax returns remain open to examination by tax authorities, due to net operating

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Index to Financial Statement s

losses. As of December 31, ~~2018,~~2020, the Company has no0 unrecognized tax benefits that would have a material impact on the effective rate. The Company recognizes interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively.

On December 22, 2018, the Company finalized the provisional accounting for the Tax Cuts and Jobs Act ("Tax Act"), which was enacted in 2017. Further information on the tax impacts of the Tax Act is included in Note 11 of the Company's consolidated financial statements.

Revenue Recognition

The Company’s revenues are primarily derived from the sale of natural gas, oil and condensate and ~~NGLs.~~NGL. Sales of natural gas, oil and condensate and ~~NGLs~~NGL are recognized in the period that the performance obligations are satisfied. The Company generally considers the delivery of each unit (MMBtu or Bbl) to be separately identifiable and represents a distinct performance obligation that is satisfied at a point-in-time once control of the product has been transferred to the customer. The Company considers a variety of facts and circumstances in assessing the point of control transfer, including but not limited to (i) whether the purchaser can direct the use of the product, (ii) the transfer of significant risks, (iii) the Company’s right to payment and (iv) transfer of legal title.

Gathering, processing and compression fees attributable to gas processing, as well as any transportation fees, including firm transportation fees, incurred to deliver the product to the purchaser, are presented as midstream, gathering and processing expense in the accompanying consolidated statements of operations.

Revenue is measured based on consideration specified in the contract with the customer, and excludes any amounts collected on behalf of third parties. These contracts typically include variable consideration that is based on pricing tied to market indices and volumes delivered in the current month. As such, this market pricing may be constrained (i.e., not estimable) at the inception of the contract but will be recognized based on the applicable market pricing, which will be known upon transfer of the goods to the customer. The payment date is usually within 30 days of the end of the calendar month in which the commodity is delivered.

The recognition of gains or losses on derivative instruments is outside the scope of ~~Accounting Standards Codification ("ASC")~~ASC 606, Revenue from Contracts with Customers ~~("ASC 606")~~ and is not considered revenue from contracts with customers subject to ASC 606. The Company may use financial or physical contracts accounted for as derivatives as economic hedges to manage price risk associated with normal sales, or in limited cases may use them for contracts the Company intends to physically settle but do not meet all of the criteria to be treated as normal sales.

The Company has elected to exclude from the measurement of the transaction price all taxes assessed by governmental authorities that are both imposed on and concurrent with a specific revenue-producing transaction and collected by the Company from a customer, such as sales tax, use tax, value-added tax and similar taxes.

See Note 109 for additional discussion of revenue from contracts with customers.

Investments—Equity Method

Investments in entities in which the Company owns an equity interest greater than 20% and less than 50% and/or investments in which it has significant influence are accounted for under the equity method. Under the equity method, the Company’s share of investees’ earnings or loss is recognized in the ~~statement~~consolidated statements of operations.

The Company reviews its investments annually to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, the Company recognizes an impairment provision. The Company ~~recognized an~~did 0t record any impairment ~~charge~~charges related to its investments in Mammoth and Grizzly for the year ended December 31, 2020. During the year ended December 31, 2019, the Company recorded impairments of ~~$23.1~~$160.8 million related to its investment in ~~Grizzly Oil Sands ULC~~Mammoth Energy and $32.4 million related to its investment in Grizzly. There were 0 impairment charges recorded for the year ended December 31, ~~2016. There were no impairment charges recorded~~2018. See Note 5 for ~~the years ended December 31, 2017~~further discussion of Mammoth Energy and ~~December 31, 2018.~~Grizzly impairments.

~~F-11~~

~~Table of Contents~~

~~Index to Financial Statements~~

Accounting for Stock-based Compensation

Share-based payments to employees, including grants of restricted stock, are recognized as equity or liabilities at the fair value on the date of grant and to be expensed over the applicable vesting period. The vesting periods for restricted shares range between one to ~~four~~three years with annual vesting installments. The Company does not recognize expense based on an estimate of forfeitures, but rather recognizes the impact of forfeitures only as they occur. The Company will continue to account for its share-based payments consistent with prior periods until the Bankruptcy Court takes specific actions to modify or cancel existing awards.

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Derivative Instruments

The Company utilizes commodity derivatives to manage the price risk associated with forecasted sale of its natural gas, crude oil and ~~natural gas liquid~~NGL production. All derivative instruments are recognized as assets or liabilities in the consolidated balance ~~sheet,~~sheets, measured at fair value. The Company does not apply hedge accounting to derivative instruments. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements and revenues and expenses during the reporting period. Actual results could differ materially from those estimates. Significant estimates with regard to these financial statements include the estimate of proved oil and gas reserve quantities and the related present value of estimated future net cash flows there from, the amount and timing of asset retirement obligations, the realization of deferred tax assets, the fair value determination of acquired assets and liabilities and the realization of future net operating loss carryforwards available as reductions of income tax expense. The estimate of the Company’s oil and gas reserves is used to compute depletion, depreciation, amortization and impairment of oil and gas properties.

~~Reclassification~~Supplemental cash flow and non-cash information

~~Certain reclassifications~~


	Year Ended December 31,
	2020		2019		2018
Supplemental disclosure of cash flow information:	(In thousands)
Cash paid for reorganization items, net	$	24,553	$	0	$	0
Interest payments	$	84,823	$	142,664	$	132,995
Income tax receipts	$	0	$	(1,794)	$	0
Supplemental disclosure of non-cash transactions:
Capitalized stock-based compensation	$	2,860	$	5,766	$	4,533
Asset retirement obligation capitalized	$	2,358	$	6,883	$	1,452
Asset retirement obligation removed due to divestiture	$	(2,213)	$	(30,146)	$	0
Interest capitalized	$	907	$	3,372	$	4,470
Pre-petition revolver principal transfer to DIP credit facility	$	157,500	$	0	$	0
Fair value of contingent consideration asset on date of divestiture	$	23,090	$	(1,137)	$	0
Foreign currency translation gain (loss) on equity method investments	$	3,833	$	9,193	$	(15,487)

Reclassifications

In the fourth quarter of 2020, the Company updated the presentation of certain costs on its consolidated statements of operations to better align its cost reporting with industry peers. In particular, the Company created a new expense line item titled “Taxes other than income” in its consolidated statement of operations. This new line item includes production taxes, property taxes and certain other non-income tax related costs incurred. Prior period amounts have been ~~made~~reclassified to ~~prior period financial statements and related disclosures~~align to ~~conform to current period presentation. These~~this new approach. The reclassifications have no impact on ~~previous~~previously reported total assets, ~~total~~ liabilities, net (loss) income ~~(loss)~~ or total operating cash flows.

~~Recent Accounting Pronouncements~~Impact on Previously Reported Results

~~In May 2014,~~During the ~~Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2014-09,~~ ~~Revenue from Contracts with Customers~~, which supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance with Topic 606. Subsequent to ASU 2014-09, the FASB issued several related ASU's to clarify the applicationthird quarter of the revenue recognition standard. The core principle of the new standard is for the recognition of revenue to depict the transfer of goods or services to customers in amounts that reflect the payment to which the company expects to be entitled in exchange for those goods or services. The Company adopted ASC 606 as of January 1, 2018 using the modified retrospective transition method applied to contracts that were not completed as of that date. Results for reporting periods beginning after January 1, 2018 are presented under the new revenue standard. Under the modified retrospective method,2020, the Company ~~recognizes~~identified that certain transportation activities during the cumulative effect of initially applying the new revenue standard as an adjustment to the opening balance of retained earnings; however, no adjustment was required as a result of adopting the new revenue standard. The comparative information has not been restatedyears ended December 31, 2019 and continues to be reported under the historic accounting standards in effect for those periods. The impact of the adoption of the new revenue standard is not expected to be material to the Company’s net income on an ongoing basis. See Note 10 for further discussion of the revenue standard.

~~In February 2016, the FASB issued ASU No. 2016-02,~~ ~~Leases (Topic 842). The standard supersedes the previous lease guidance by requiring lessees to recognize a right-to-use asset~~2018 were misclassified between "natural gas sales" and ~~lease liability on the balance sheet for all leases with lease terms of greater than one year while maintaining substantially similar classifications for financing~~"midstream gathering and ~~operating leases. The guidance is effective for periods after December 15, 2018, and the Company will adopt beginning January 1, 2019 using the transition method permitted by ASU No. 2018-11,~~ ~~Leases (Topic 842): Targeted Improvements~~, issued in August 2018, which permits an entity to recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption with no adjustment made to the comparative periods presented in the consolidated financial statements. The Company

~~F-12~~

~~Table of Contents~~

~~Index to Financial Statements~~

will also utilize the practical expedient provided by ASU 2018-11 to not separate non-lease components from the associated lease component and, instead, to account for those components as a single component if the non-lease components would be accounted for under ASC 606 and other conditions are met.

~~The Company has identified its portfolio of leased assets under the new standard and has evaluated the impact of this guidance~~processing expenses" on its consolidated ~~financial~~ statements and related disclosures. Offsetting right-of-use assets and corresponding lease liabilities recognized by the Company on the adoption date totaled approximately $110 million, representing minimum payment obligations associated with identified leases with contractual durations longer than one year. Adoption of the new standard will not result in a material impact to the consolidated statement of operations. The Company ~~has implemented processes and controls needed to comply~~assessed the materiality of this presentation on prior periods’ consolidated financial statements in accordance with the ~~requirements~~SEC Staff Accounting Bulletin No. 99, “Materiality”, codified in Accounting Standards Codification Topic 250, “Accounting Changes and Error Corrections". Based on this assessment, the Company concluded that the correction is not material to any previously issued financial statements. The correction had no impact on its consolidated balance sheets, consolidated statements of comprehensive income, consolidated statements of stockholders' equity or consolidated statements of cash flows. Additionally, the error had no impact on net loss or net loss per share. The Company will conform presentation of previously reported consolidated statements of operations in future filings.

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Index to Financial Statement s

The following tables present the effect of the ~~new standard, which includes~~correction on all affected line items of our previously issued consolidated financial statements of operations for the ~~implementation of a lease accounting software solution to support lease portfolio management~~years ended December 31, 2019 and ~~accounting and disclosures.~~2018.

~~Additionally, in~~


	Year Ended December 31, 2019
	As Reported		Adjustments		As Revised
	(In thousands)
Natural gas sales	$	918,263	$	217,118	$	1,135,381
Total Revenues	$	1,346,008	$	217,118	$	1,563,126
Midstream gathering and processing expenses	$	291,725	$	217,118	$	508,843
Total Operating Expenses	$	3,049,701	$	217,118	$	3,266,819

	Year Ended December 31, 2018
	As Reported		Adjustments		As Revised
	(In thousands)
Natural gas sales	$	1,121,815	$	196,657	$	1,318,472
Total Revenues	$	1,355,044	$	196,657	$	1,551,701
Midstream gathering and processing expenses	$	290,188	$	196,657	$	486,845
Total Operating Expenses	$	956,085	$	196,657	$	1,152,742

Recent Adopted Accounting Pronouncements

On January ~~2018,~~1, 2020, the ~~FASB issued ASU No. 2018-01,~~ ~~Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842~~. The amendments in this update provide an optional expedient to not evaluate existing or expired land easements that were not previously accounted for under current leases guidance in Topic 840. An entity that elects this practical expedient should evaluate new or modified land easements beginning at the date of adoption. The Company ~~does not currently account for any land easements under Topic 840 and plans to utilize this practical expedient in conjunction with the adoption of ASU 2016-02.~~

~~In June 2016, the FASB issued~~adopted ASU No. 2016-13, Financial Instruments-Credit Losses: Measurement of Credit Losses on Financial Instruments~~. This ASU amends guidance on reporting~~, which replaces the incurred loss impairment methodology with a methodology that reflects expected credit losses ~~for assets held at amortized cost basis~~ and ~~available for sale debt securities. For assets held at amortized cost basis, this ASU eliminates the probable initial recognition threshold in current GAAP~~requires consideration of a broader range of reasonable and ~~instead, requires an entity~~supportable information to ~~reflect its current estimate~~inform credit loss estimates. The measurement of ~~all~~ expected credit ~~losses. The amendments~~losses is based on relevant information about past events, including historical experience, current conditions and reasonable and supportable forecasts that affect ~~loans, debt securities, trade receivables, net investments in leases, off balance sheet credit exposure, reinsurance receivables and any other financial assets not excluded from~~ the ~~scope that have~~collectability of the ~~contractual right to receive cash. The guidance is effective for periods after December 15, 2019, with early adoption permitted.~~reported amount. The Company ~~is currently evaluating~~adopted the new standard using the prospective transition method, and it did not have a material impact ~~this standard will have~~ on ~~its~~the Company's consolidated financial statements and related ~~disclosures~~disclosures.

2.CHAPTER 11 PROCEEDINGS

Restructuring Support Agreement

On November 13, 2020, the Debtors commenced the Chapter 11 Cases as described in Note 1 above. To ensure ordinary course operations, the Debtors have obtained approval from the Bankruptcy Court for certain "first day" motions, including motions to obtain customary relief intended to continue ordinary course operations after the Petition Date. In addition, the Debtors have received authority to use cash collateral of the lenders under the DIP Credit Facility.

On November 13, 2020, the Debtors entered into a restructuring support agreement with (i) over 95% of the lenders (the “Consenting RBL Lenders”) party to the Pre-Petition Revolving Credit Facility, dated as of December 27, 2013, by and among the Company, as borrower, each of the lenders party thereto, the Bank of Nova Scotia, as administrative agent and issuing bank, the joint lead arrangers and joint bookrunners, the co-syndication agents, and the co-documentation agents and (ii) certain holders (the “Consenting Noteholders,” and, together with the Consenting RBL Lenders, the “Consenting Stakeholders”) holding over two-thirds of the Company’s (a) 6.625% senior notes due 2023, issued under that certain Indenture, dated as of April 21, 2015, (b) 6.000% senior notes due 2024, issued under that certain Indenture, dated as of October 14, 2016, (c) 6.375% senior notes due 2025, issued under that certain Indenture, dated as of December 21, 2016, and (d) 6.375% senior notes due 2026, issued under that certain Indenture, dated as of October 11, 2017 (collectively, the “Unsecured Notes”), each by and among the Company, the subsidiary guarantors party thereto, and UMB Bank, N.A. as successor trustee.

The RSA outlines the key elements and actions the Company plans to take as part of Chapter 11 process, including equitizing a significant portion of its prepetition indebtedness and rejecting or renegotiating certain contracts which will result in a materially improved balance sheet and cost structure. The RSA contains certain covenants on the part of each of Gulfport and the Consenting Stakeholders, including commitments by the Consenting Stakeholders to vote in favor of the Plan and commitments of Gulfport and the Consenting Stakeholders to negotiate in good faith to finalize the documents and agreements

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Index to Financial Statement s

governing the Restructuring. The RSA also places certain conditions on the obligations of the parties and provides that the RSA may be terminated upon the occurrence of certain events, including, without limitation, the failure to achieve certain milestones and certain breaches by the parties under the RSA. One such condition is the requirement to obtain sufficient savings on certain midstream obligations (as set forth in the RSA) through rejection of such contracts and/or renegotiation of their terms.

Although Gulfport intends to pursue the Restructuring in accordance with the terms set forth in the RSA, there can be no assurance that Gulfport will be successful in completing a restructuring or any other similar transaction on the terms set forth in the RSA, on different terms, or at all.

Plan of Reorganization

The Restructuring contemplated under the RSA will be pursued by Gulfport pursuant to a prearranged joint plan of reorganization (the “Plan”). Capitalized terms used under this heading titled “Joint Prearranged Chapter 11 Plan of Reorganization” but not otherwise defined herein shall have the meaning given to such terms in the Plan. The Plan can be found as an exhibit to this Form 10-K.

Below is a summary of the treatment that the stakeholders of the Company would receive under the Plan:

•each Holder of an Allowed Other Secured Claim shall receive, at the option of the applicable Debtor and with the consent of the Required Consenting Stakeholders (such consent not to be unreasonably withheld): (a) payment in full in Cash of its Allowed Other Secured Claim; (b) the collateral securing its Allowed Other Secured Claim; (c) Reinstatement of its Allowed Other Secured Claim; or (d) such other treatment rendering its Allowed Other Secured Claim unimpaired in accordance with section 1124 of the Bankruptcy Code;

•each Holder of an Allowed Other Priority Claim shall receive treatment in a manner consistent with section 1129(a)(9) of the Bankruptcy Code;

•each Holder of an Allowed RBL Claim shall receive, at the option of each such Holder, either (a) its Pro Rata share of the Exit RBL/Term Loan A Facility, if such Holder elects to participate in the Exit RBL/Term Loan A Facility or (b) its Pro Rata share of the Exit Term Loan B Facility, if such Holder does not ~~anticipate~~elect to participate in the Exit RBL/Term Loan A Facility (including by not making any election with respect to the Exit Facility on the ballot);

•each Holder of an Allowed General Unsecured Claim against Gulfport Parent shall receive in full and final satisfaction of such Claim, its Pro Rata share of the Gulfport Parent Equity Pool; provided, however, that once the Holders of Notes Claims receive distributions of 94% of the New Common Stock (prior to and not including any dilution by the Management Incentive Plan or any conversion of New Preferred Stock into New Common Stock) in the aggregate on account of their Notes Claims against all Debtors, the Holders of Notes Claims shall waive any excess recovery on account of their Pro Rata share of the Gulfport Parent Equity Pool until Holders of Allowed General Unsecured Claims against Gulfport Parent have received New Common Stock with a value sufficient to satisfy their Allowed General Unsecured Claims against Gulfport Parent in full (based on Plan Value);

•each Holder of an Allowed General Unsecured Claim against Gulfport Subsidiaries shall receive in full and final satisfaction of such Claim, its Pro Rata share of: (a) the Gulfport Subsidiaries Equity Pool; (b) the Rights Offering Subscription Rights; and (c) the New Unsecured Notes;

•each Holder of an Allowed Notes Claim against Gulfport Parent shall receive, in full and final satisfaction of such Claim, its Pro Rata share of the Gulfport Parent Equity Pool; provided, however, that once the Holders of Notes Claims receive distributions of 94% of the New Common Stock (prior to and not including any dilution by the Management Incentive Plan or any conversion of New Preferred Stock into New Common Stock) in the aggregate on account of their Notes Claims against all Debtors, the Holders of Notes Claims shall waive any excess recovery on account of their Pro Rata share of the Gulfport Parent Equity Pool until Holders of Allowed General Unsecured Claims against Gulfport Parent have received New Common Stock with a value sufficient to satisfy their Allowed General Unsecured Claims against Gulfport Parent in full (based on Plan Value); provided further, however, distributions to any Holder of a Notes Claim against Gulfport Parent shall be subject to the rights and terms of the Notes Indentures and the rights of the Notes Trustee to assert the Notes Trustee Charging Lien;

•each Holder of an Allowed Notes Claim against Gulfport Subsidiaries shall receive, in full and final satisfaction of such Claim, its Pro Rata share of the: (i) Gulfport Subsidiaries Equity Pool, (ii) Rights Offering Subscription Rights, and (iii) New Unsecured Notes; provided, however, distributions to any Holder of a Notes Claim against Gulfport

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Index to Financial Statement s

Subsidiaries shall be subject to the rights and terms of the Notes Indentures and the rights of the Notes Trustee to assert the Notes Trustee Charging Lien;

•each Intercompany Claim shall be cancelled in exchange for the distributions contemplated by the Plan to Holders of Claims against and Interests in the respective Debtor entities and shall be considered settled pursuant to Bankruptcy Rule 9019;

•each Holder of an Intercompany Interest shall receive no recovery or distribution and shall be Reinstated solely to the extent necessary to maintain the Debtors’ prepetition corporate structure for the ultimate benefit of the Holders of New Common Stock and New Preferred Stock; and

•all Existing Interests (i.e. equity) in Gulfport Parent and all Allowed Section 510(b) Claims, if any, shall be cancelled, released, extinguished, and of no further force or effect.

DIP Credit Facility

Pursuant to the RSA, the Consenting RBL Lenders have agreed to provide the Company with a senior secured superpriority debtor-in-possession revolving credit facility in an aggregate principal amount of $262.5 million consisting of (a) $105 million of new money and (b) $157.5 million to roll up a portion of the existing outstanding obligations under the Pre-Petition Revolving Credit Facility. The proceeds of the DIP Credit Facility may be used for, among other things, post-petition working capital, permitted capital investments, general corporate purposes, letters of credit, administrative costs, premiums, expenses and fees for the transactions contemplated by the Chapter 11 Cases and payment of court approved adequate protection obligations. In the current period, the Company incurred $3.0 million of fees related to the arrangement and funding of the DIP Credit Facility. The DIP Credit Facility was approved by the Bankruptcy Court on a final basis on December 18, 2020. See Note 6 for additional information.

Executory Contracts

Subject to certain exceptions, under the Bankruptcy Code, the Company may assume, assign, or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and certain other conditions. Generally, the rejection of an executory contract or unexpired lease is treated as a pre-petition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Company from performing its future obligations under such executory contract or unexpired lease but entitles the contract counterparty or lessor to a pre-petition general unsecured claim for damages caused by such deemed breach. Counterparties to rejected contracts or leases may assert unsecured claims in the Bankruptcy Court against the Company's estate for such damages. Generally, the assumption of an executory contract or unexpired lease requires the Company to cure existing monetary defaults under such executory contract or unexpired lease and provide adequate assurance of future performance. Accordingly, any description of an executory contract or unexpired lease with the Company, including where applicable a quantification of the Company's obligations under any such executory contract or unexpired lease of the Company, is qualified by any overriding rejection rights it has under the Bankruptcy Code.

Potential Claims

The Company has filed with the Bankruptcy Court schedules and statements setting forth, among other things, the assets and liabilities of the Company and each of its subsidiaries, subject to the assumptions filed in connection therewith. These schedules and statements may be subject to further amendment or modification after filing. Certain holders of pre-petition claims that are not governmental units were required to file proofs of claim by the deadline for general claims, which was set by the Bankruptcy Court as January 26, 2021. Governmental units are required to file proof of claims by May 12, 2021, the deadline that was set by the Bankruptcy Court.

As of February 25, 2021, the Debtors have ~~a material effect.~~received approximately 2,200 proofs of claim for an aggregate amount of approximately $12.5 billion. The Company will continue to evaluate these claims throughout the Chapter 11 process and recognize or adjust amounts in future financial statements as necessary using the best information available at such time. Differences between amounts scheduled by the Company and claims by creditors will ultimately be reconciled and resolved in connection with the claims resolution process. In light of the expected number of creditors, the claims resolution process may take considerable time to complete and likely will continue after the Company emerges from bankruptcy.

~~In August 2016, the FASB issued ASU No. 2016-15,~~

Financial Statement ~~of Cash Flows:~~ Classification of ~~Certain Cash Receipts and Cash Payments.~~ ~~This ASU clarifies how certain cash receipts and cash payments should~~Liabilities Subject to Compromise

The accompanying audited consolidated balance sheet as of December 31, 2020, includes amounts classified as liabilities subject to compromise, which represent liabilities the Company anticipates will be ~~classified and presented~~allowed as claims in the ~~statement~~Chapter 11 Cases.

Table of ~~cash flows.~~Contents

Index to Financial Statement s

These amounts represent the Company's current estimate of known or potential obligations to be resolved in connection with the Chapter 11 Cases, and may differ from actual future settlement amounts paid. Differences between liabilities estimated and claims filed, or to be filed, will be investigated and resolved in connection with the claims resolution process. The Company ~~adopted~~will continue to evaluate these liabilities throughout the Chapter 11 process and adjust amounts as necessary. Such adjustments may be material.

Liabilities subject to compromise includes amounts related to the rejection of various executory contracts. Additional amounts may be included in liabilities subject to compromise in future periods if additional executory contracts and/or unexpired leases are rejected. The nature of many of the potential claims arising under the Company's executory contracts and unexpired leases has not been determined at this ~~standard~~time, and therefore, such claims are not reasonably estimable at this time and may be material. Damages related to rejected contracts are accounted for after they have been approved for rejection by the Bankruptcy Court.

The following table summarizes the components of liabilities subject to compromise included on the Company's audited consolidated balance sheet as of December 31, 2020:


	December 31, 2020
	(in thousands)
Debt subject to compromise	$	2,005,219
Accounts payable and accrued liabilities	164,939
Asset retirement obligations	63,566
Accrued interest on debt subject to compromise	55,634
Other liabilities	4,122
Liabilities subject to compromise	$	2,293,480

Interest Expense

The Company has discontinued recording interest on debt instruments classified as liabilities subject to compromise as of the Petition Date. The contractual interest expense on liabilities subject to compromise not accrued in the ~~first quarter~~consolidated statements of ~~2018~~operations was approximately $15.3 million from the Petition Date through December 31, 2020.

Reorganization Items, Net

The Company has incurred and will continue to incur significant expenses, gains and losses associated with the reorganization, primarily the write-off of unamortized debt issuance costs, debt and equity financing fees, adjustments to allowed claims and legal and professional fees incurred subsequent to the Chapter 11 filings for the restructuring process. The amount of these items, which are being incurred in reorganization items, net within the Company's accompanying audited consolidated statements of operations, are expected to significantly affect the Company's statements of operations. The Company has ~~made an accounting policy election~~incurred adjustments for allowable claims related to ~~classify distributions received from equity method investees using~~its legal proceedings and executory contracts approved for rejections by the ~~nature of~~Bankruptcy Court, with additional adjustments possible in future periods.

The following table summarizes the ~~distribution approach, which classifies distributions received from investees as either cash inflows from operating activities or cash inflows from investing activities~~components in reorganization items, net included in the ~~statement~~Company's audited consolidated statements of ~~cash flows based on the nature of the activities of the investee that generated the distribution. The impact of adopting this ASU was not material to prior periods presented.~~

~~In November 2016, the FASB issued ASU No. 2016-18,~~ ~~Statement of Cash Flows (Topic 230): Restricted Cash~~. This ASU requires that amounts generally described as restricted cash and restricted cash equivalents be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period amounts shown on the statement of cash flows and to provide a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. The Company adopted this standard in the first quarter of 2018 using the retrospective transition method. The adoption of this standard had no impact on the statement of cash flowsoperations for the year ended December 31, ~~2018. As~~2020:


	Year Ended December 31, 2020
	(in thousands)
Adjustment to allowed claims	$	104,943
Legal and professional fees	24,905
Write off of unamortized issuance costs on debt subject to compromise	21,956
DIP credit facility financing fees	2,988
Gain on settlement of pre-petition accounts payable	(2,433)
Reorganization items, net	$	152,359

Table of Contents

Index to Financial Statement s

3.DIVESTITURES

Sale of Water Infrastructure Assets

On January 2, 2020, the Company closed on the sale of its SCOOP water infrastructure assets to a ~~result~~third-party water service provider. The Company received $50.0 million in cash proceeds upon closing and has an opportunity to earn potential additional incentive payments over the next 15 years, subject to the Company's ability to meet certain thresholds which will be driven by, among other things, the Company's future development program and water production levels. The agreement contained no minimum volume commitments. The fair value of the adoption, $185.0 million in restricted cash was removed from net cash used in investing resulting in an increase to the ending cash balance for the year ended December 31, 2016. The adoption also resulted in an addition of $185.0 million in restricted cash to the net cash used in investing activities for the year ended December 31, 2017. This addition and the resulting decrease to ending cash was offset by the increase to beginning cash balance of $185.0 million due to the changes at December 31, 2016. Therefore, there was no net impact on the statement of cash flowscontingent consideration as of ~~December 31, 2017.~~

~~In January 2017,~~ the ~~FASB issued ASU No. 2017-01,~~ ~~Clarifying the Definition of a Business~~. Under the current business combination guidance, there are three elements of a business: inputs, processes and outputs. The revised guidance adds an initial screen test to determine if substantially allclosing date was $23.1 million. See Note 15 for additional discussion of the fair value of the ~~gross~~contingent consideration.

The divested assets acquired is concentrated in a single asset or group of similar assets. If that screen is met, the set of assets is not a business. The new framework also specifies the minimum required inputs and processes necessary to be a business. The Company adopted this standardwere included in the ~~first quarter of 2018 with no significant effect on its financial statements or related disclosures.~~

~~F-13~~

~~Table of Contents~~

~~Index to Financial Statements~~

~~In February 2018, the FASB issued ASU No. 2018-02,~~ ~~Income statement - Reporting Comprehensive Income (Topic 220) - Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income~~, which allows a reclassification from accumulated other comprehensive income to retained earnings for standard tax effects resulting from the Tax Cuts and Jobs Act of 2017. The amendment will be effective for reporting periods beginning after December 15, 2018, and early adoption is permitted. The Company assessed the impactamortization base of the ~~ASU on its~~full cost pool and 0 gain or loss was recognized in the accompanying consolidated ~~financial~~ statements ~~and related disclosures, and determined there was no material impact.~~

~~In August 2018, the FASB issued ASU No. 2018-13,~~ ~~Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement~~, which removes, modifies, and adds certain disclosure requirements on fair value measurements. The amendment will be effective for reporting periods beginning after December 15, 2019, and early adoption is permitted. The Company is currently assessing the impactof operations as a result of the ~~ASU on its consolidated financial statements and related disclosures.~~sale.

Sale of Non-operated Utica Interests

In ~~August 2018, the FASB issued ASU No. 2018-15,~~ ~~Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract~~, which aligns the accounting for costs associated with implementing a cloud computing arrangement in a hosting arrangement that is a service contract with the accounting for implementation costs incurred to develop or obtain internal-use software. The amendment will be effective for reporting periods beginning after December ~~15,~~ 2019, ~~and early adoption is permitted. The Company is currently assessing the impact of the ASU on its consolidated financial statements and related disclosures.~~

~~In August 2018, the Securities and Exchange Commission ("SEC") issued Final Rule Release No. 33-10532,~~ ~~Disclosure Update and Simplification~~, which amends certain disclosure requirements that were redundant, duplicative, overlapping or superseded. Under these amendments, the annual disclosure requirements on the analysis of stockholders' equity is extended to interim financial statements. The Company will present an analysis of changes in stockholders' equity for the current and comparative year-to-date interim periods. The final rule is effective November 5, 2018, and the Company ~~will begin presenting this analysis beginning with the quarter ended March 31, 2019.~~

~~In November 2018, the FASB also issued ASU No. 2018-18,~~ ~~Collaborative Arrangements (Topic 808): Clarifying the Interaction Between Topic 808 and Topic 606~~, which provides guidance on how to assess whether certain transactions between participants in a collaborative arrangement should be accounted for within the ASU No. 2014-09 revenue recognition standard discussed above. The amendment will be effective for reporting periods beginning after December 15, 2019, and early adoption is permitted. The Company is currently assessing the impact of the ASU on its consolidated financial statements and related disclosures.


2.	~~ACQUISITIONS~~

~~In December 2016, the Company, through its wholly-owned subsidiary Gulfport MidCon LLC (“Gulfport MidCon”) (formerly known as SCOOP Acquisition Company, LLC),~~ entered into an agreement to ~~acquire~~divest certain ~~assets of Vitruvian II Woodford, LLC (“Vitruvian”), an unrelated third-party seller (the “Vitruvian Acquisition”). The assets included~~non-operated interests in the ~~Vitruvian Acquisition include 46,400~~Utica for approximately $29.0 million in cash subject to customary closing terms and adjustments. This sale closed on December 30, 2019.

Sale of Bakken Overriding Royalty Interests

During 2019, the Company announced the sale of certain overriding royalty interests associated with assets the Company held in the Bakken. The sale closed on December 11, 2019 and, net ~~surface acres~~of purchase price adjustments, the Company received approximately $7.0 million of total proceeds.

Sale of Southern Louisiana Assets

In December 2018, the Company entered into an agreement to sell its non-core assets located in ~~Grady, Stephens~~the West Cote Blanche Bay and ~~Garvin Counties, Oklahoma. On February 17, 2017, the Company completed the Vitruvian Acquisition~~Hackberry fields of southern Louisiana to an undisclosed third party for a ~~total initial~~ purchase price of approximately ~~$1.85 billion, consisting~~$19.7 million. The sale closed on July 3, 2019, subject to customary post-closing terms and conditions, with an effective date of ~~$1.35 billion~~August 15, 2018. The Company received approximately $9.2 million 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). The cash portion of the purchase price was funded with the net proceeds from the December 2016 common stock and senior note offerings and cash on hand. Acquisition costs of $2.4 million were incurred during the year ended December 31, 2017 ~~related to the Vitruvian Acquisition.~~ ~~No acquisition costs were incurred during the year ended December 31, 2018~~.

~~Purchase Price~~

~~The Vitruvian Acquisition qualified as a business combination for accounting purposes and, as such,~~retained contingent overriding royalty interests. In addition, the Company ~~estimated~~could also receive contingent payments based on commodity prices exceeding specified thresholds over the ~~fair value of~~two years following the ~~acquired properties as of the February 17, 2017 acquisition~~closing date. ~~The fair value of the assets acquired and liabilities assumed was estimated using assumptions that represent Level 3 inputs.~~ See Note 1413 for ~~additional~~further discussion of the ~~measurement inputs.~~

~~The Company estimated that the~~contingent consideration ~~paid in the Vitruvian Acquisition for these properties approximated the fair value that would be paid by a typical market participant. As a result,~~ no ~~goodwill or bargain purchase gain~~arrangement, which was ~~recognized in conjunction with the purchase.~~

~~F-14~~

~~Table of Contents~~

~~Index to Financial Statements~~

~~The following table summarizes the consideration paid by the Company in the Vitruvian Acquisition to acquire the properties and the fair value amount of the assets acquired as of February 17, 2017.~~

(In thousands)
Consideration:
     Cash, net of purchase price adjustments $ 1,354,093
     Fair value of Gulfport’s common stock issued 464,639
Total Consideration $ 1,818,732

Estimated Fair value of identifiable assets acquired and liabilities assumed:
     Oil and natural gas properties
       Proved properties $ 362,264
       Unproved properties 1,462,957
     Asset retirement obligations (6,489 )
Total fair value of net identifiable assets acquired $ 1,818,732

The equity consideration included in the initial purchase price was based on an equity offering price of $20.96 on December 15, 2016. The decrease in the price of Gulfport’s common stock from $20.96 on December 15, 2016 to $19.48 on February 17, 2017 resulted in a decrease to the fair value of the total consideration paid as compared to the initial purchase price of approximately $35.3 million, which resulted in a closing date fair value lower than the initial purchase price.

~~Post-Acquisition Operating Results~~

For the period from the acquisition date of February 17, 2017 to December 31, 2017, the assets acquired in the Vitruvian Acquisition have contributed the following amounts of revenue to the Company’s consolidated statements of operations. The amount of net income contributed by the assets acquired is not presented below as it is impracticable to calculate due to the Company integrating the acquired assets into its overall operations using the full cost method of accounting.

Period from
February 17, 2017
to
December 31, 2017
(In thousands)
Revenue $ 213,368

~~Pro Forma Information (Unaudited)~~

The following unaudited pro forma combined financial information presents the Company’s results as though the Vitruvian Acquisition had been completed at January 1, 2016. The pro forma combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the Vitruvian Acquisition taken place on January 1, 2016; furthermore, the financial information is not intendeddetermined to be ~~a projection of future results.~~an embedded derivative. The buyer assumed all plugging and abandonment liabilities associated with these assets which totaled approximately $30.0 million at the divestiture date.

December 31,
2017 2016
(In thousands, except share data)
Pro forma revenue $ 1,356,202
$ 523,097
Pro forma net income (loss) $ 448,398
$ (1,190,481 )
Pro forma earnings (loss) per share (basic) $ 2.49
$ (8.11 )
Pro forma earnings (loss) per share (diluted) $ 2.49
$ (8.11 )
4.PROPERTY AND EQUIPMENT

~~F-15~~

~~Table of Contents~~

~~Index to Financial Statements~~


3.	~~PROPERTY AND EQUIPMENT~~

The major categories of property and equipment and related accumulated depletion, depreciation, amortization and impairment as of December 31, ~~2018~~2020 and ~~2017~~2019 are as follows:


	December 31,
	2020		2019
	(In thousands)
Oil and natural gas properties	$	10,816,909	$	10,595,735
Other depreciable property and equipment	85,530		91,198
Land	3,008		5,521
Total property and equipment	10,905,447		10,692,454
Accumulated depletion, depreciation, amortization and impairment	(8,819,178)		(7,228,660)
Property and equipment, net	$	2,086,269	$	3,463,794

Under the full cost method of accounting, capitalized costs of oil and natural gas properties are subject to a quarterly full cost ceiling test, which is discussed in Note 1. During the years ended December 31, 2020 and 2019, the Company incurred $1.4 billion and $2.0 billion of impairments, respectively, as a result of its oil and natural gas properties exceeding its calculated

Table of Contents

Index to Financial Statement s

December 31,
2018 2017
(In thousands)
Oil and natural gas properties $ 10,026,836
$ 9,169,156
Office furniture and fixtures 42,581
37,369
Buildings 44,565
44,565
Land 5,521
4,820
Total property and equipment 10,119,503
9,255,910
Accumulated depletion, depreciation, amortization and impairment (4,640,098 ) (4,153,733 )
Property and equipment, net $ 5,479,405
$ 5,102,177

Noceiling. The lower ceiling values resulted primarily from significant decreases in the 12-month average trailing prices for natural gas, oil and NGL, which significantly reduced proved reserves values and proved reserves. NaN impairment of oil and natural gas properties was required under the ceiling test for the years ended December 31, 2018 and 2017. At December 31, 2016, the net book value of the Company's oil and natural gas properties was above the calculated ceiling as a result of the reduced commodity prices during the year ended December 31, 2016. As a result, the Company recorded an impairment of its oil and natural gas properties under the full cost method of accounting in the amount of $715.5 million for the year ended December 31, 2016.2018.

Included in oil and natural gas properties at December 31, 2018 and 2017 is the cumulative capitalization of $203.3 million and $165.6 million, respectively, in general and administrative costs incurred and capitalized to the full cost pool. General and administrative costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All general and administrative costs not directly associated with exploration and development activities were charged to expense as they were incurred. Capitalized general and administrative costs were approximately ~~$37.7~~$25.0 million, ~~$35.7~~$30.1 million and ~~$29.3~~$37.7 million for the years ended December 31, ~~2018, 2017~~2020, 2019 and ~~2016,~~2018, respectively. The average depletion rate per Mcfe, which is a function of capitalized costs, future development costs and the related underlying reserves in the periods presented, was ~~$0.96, $0.90~~$0.61, $1.08 and ~~$0.92~~$0.96 per Mcfe for the years ended December 31, ~~2018, 2017~~2020, 2019 and ~~2016,~~2018, respectively.

The following is a summary of Gulfport’s oil and natural gas properties not subject to amortization as of December 31, ~~2018:~~

2020:


	Costs Incurred in													Costs Incurred in
	2018		2017		2016			Prior to 2016			Total			2020		2019		2018		Prior to 2018		Total
	(In thousands)													(In thousands)
Acquisition costs	$	128,415	$	1,469,820	$	122,399		$	1,128,975		$	2,849,609	Acquisition costs	$	18,485	$	8,067	$	98,876	$	1,330,895	$	1,456,323
Exploration costs	9,027		—		—			—			9,027		Exploration costs	0		0		0		0		0
Development costs	548		869		4,536			5,789			11,742		Development costs	0		0		0		0		0
Capitalized interest	2,120		2,915		(657		)	(1,719		)	2,659		Capitalized interest	0		121		172		427		720
Total oil and natural gas properties not subject to amortization	$	140,110	$	1,473,604	$	126,278		$	1,133,045		$	2,873,037	Total oil and natural gas properties not subject to amortization	$	18,485	$	8,188	$	99,048	$	1,331,322	$	1,457,043

~~F-16~~

~~Table of Contents~~

~~Index to Financial Statements~~

The following table summarizes the Company’s non-producing properties excluded from amortization by area as of December 31, ~~2018:~~

2020:

December 31, 2018
(In thousands)
Utica $ 1,483,194
MidContinent 1,388,706
Niobrara 451
Southern Louisiana 586
Bakken 100
$ 2,873,037


	December 31, 2020
	(In thousands)
Utica	$	793,441
SCOOP	662,614
Other	988
	$	1,457,043

As of December 31, ~~2017,~~2019, approximately ~~$2.9~~$1.7 billion of non-producing ~~leasehold~~property costs ~~was not~~were subject to amortization.

The Company evaluates the costs excluded from its amortization calculation at least annually. Subject to industry conditions and the level of the Company’s activities, the inclusion of most of the above referenced costs into the Company’s amortization calculation typically occurs within three to five years. However, the majority of the Company's non-producing leases in the Utica ~~Shale~~ have ~~five year~~five-year extension terms which could extend this time frame beyond five years.

Table of Contents

Index to Financial Statement s

A reconciliation of the Company's asset retirement obligation for the years ended December 31, ~~2018~~2020 and ~~2017~~2019 is as follows:


	December 31,
	2020		2019
	(In thousands)
Asset retirement obligation, beginning of period	$	60,355	$	79,952
Liabilities incurred	2,358		5,935
Liabilities settled	0		(273)
Liabilities removed due to divestitures	(2,213)		(30,146)
Accretion expense	3,066		3,939
Revisions in estimated cash flows	0		948
Total asset retirement obligation as of end of period	63,566		60,355
Less: amounts reclassified to liabilities subject to compromise	(63,566)		0
Total asset retirement obligation reflected as non-current liabilities	$	0	$	60,355

5.EQUITY INVESTMENTS

December 31,
2018 2017
(In thousands)
Asset retirement obligation, beginning of period $ 75,100
$ 34,276
Liabilities incurred 1,827
16,300
Liabilities settled (719 ) (3,057 )
Accretion expense 4,119
1,611
Revisions in estimated cash flows (375 ) 25,970
Asset retirement obligation as of end of period 79,952
75,100
Less current portion —
120
Asset retirement obligation, long-term $ 79,952
$ 74,980

~~F-17~~

~~Table of Contents~~

~~Index to Financial Statements~~


4.	~~EQUITY INVESTMENTS~~

Investments accounted for by the equity method consist of the following as of December 31, 2020 and 2019:


			Carrying Value				Loss (income) from equity method investments
	Approximate Ownership %		December 31,				For the Year Ended December 31,
			2020		2019		2020		2019		2018
			(In thousands)
Investment in Grizzly Oil Sands ULC	24.5	%	$	24,816	$	21,000	$	377	$	32,710	$	510
Investment in Mammoth Energy Services, Inc.	21.5	%	0		11,005		10,646		179,524		(49,969)
Investment in Tatex Thailand II, LLC	23.5	%	0		0		0		(2,086)		(241)
Other equity investments(1)	0	%	0		39		32		0		(204)


			$	24,816	$	32,044	$	11,055	$	210,148	$	(49,904)

_____________________

(1) Consists of sold/dissolved investments, including Windsor Midstream, LLC, which was dissolved as of December 31, 2020. Additionally, this includes the Company's investment in Strike Force that was sold in 2018, ~~and 2017:~~

Carrying Value (Income) loss from equity method investments
Approximate Ownership % December 31, For the Year Ended December 31,
2018 2017 2018 2017 2016
(In thousands)
Investment in Tatex Thailand II, LLC 23.5 % $ —
$ —
$ (241 ) $ (549 ) $ (412 )
Investment in Tatex Thailand III, LLC — % —
—
—
(183 ) —
Investment in Grizzly Oil Sands ULC 24.9999 % 44,259
57,641
510
2,189
25,150
Investment in Timber Wolf Terminals LLC⁽³⁾
— % —
983
536
8
8
Investment in Windsor Midstream LLC 22.5 % 39
30
(9 ) 25,233
(13,618 )
Investment in Stingray Cementing LLC⁽¹⁾
— % —
—
—
205
263
Investment in Blackhawk Midstream LLC⁽⁴⁾
— % —
—
(38 ) —
—
Investment in Stingray Energy Services LLC⁽¹⁾
— % —
—
—
282
1,044
Investment in Sturgeon Acquisitions LLC⁽¹⁾
— % —
—

(71 ) 993
Investment in Mammoth Energy Services, Inc.⁽¹⁾
21.9 % 191,823
165,715
(49,969 ) (11,288 ) 24,037
Investment in Strike Force Midstream LLC⁽²⁾
— % —
77,743
(693 ) 1,954
(89 )
$ 236,121
$ 302,112
$ (49,904 ) $ 17,780
$ 37,376




~~(1)~~	On June 5, 2017, Mammoth Energy Services, Inc. ("Mammoth Energy") acquired Stingray Cementing LLC, Stingray Energy Services LLC and Sturgeon Acquisitions LLC. See below under Mammoth Energy Partners LP/Mammoth Energy Services, Inc. for information regarding these transactions.
~~(2)~~	~~On May 1, 2018, the Company sold its 25% interest in Strike Force Midstream to EQT Midstream Partners, LP. See below under under~~ ~~Strike Force Midstream LLC~~ ~~for information regarding this transaction.~~
~~(3)~~	~~On June 5, 2018, the Company received its final distribution from Timber Wolf Terminals LLC ("Timber Wolf"). See below under~~ ~~Timber Wolf Terminals LLC~~ ~~for information regarding this distribution.~~
~~(4)~~	~~On December 31, 2018, the Company received its final distribution from Blackhawk Midstream LLC ("Blackhawk"). See below under~~ ~~Blackhawk Midstream LLC~~ ~~for information regarding this distribution.~~

from which the Company recognized a gain of $96.4 million net of transaction fees, which is included in gain on sale of equity method investments in the accompanying consolidated statement of operations for the year ended December 31, 2018.

The tables below summarize financial information for the Company's equity investments, as of December 31, ~~2018~~2020 and ~~2017.~~2019.

Summarized balance sheet information:


	December 31,					December 31,
	2018		2017			2020		2019
	(In thousands)					(In thousands)
Current assets	$	471,733	$	415,032	Current assets	$	483,303	$	421,326
Noncurrent assets	$	1,302,488	$	1,542,090	Noncurrent assets	$	1,092,495	$	1,260,075
Current liabilities	$	239,975	$	261,086	Current liabilities	$	132,978	$	132,569
Noncurrent liabilities	$	94,575	$	148,839	Noncurrent liabilities	$	148,240	$	163,241

~~F-18~~

Table of Contents

Index to Financial ~~Statements~~Statement s

Summarized results of operations:


	December 31,									December 31,
	2018		2017			2016				2020		2019		2018
	(In thousands)									(In thousands)
Gross revenue	$	1,729,778	$	755,374		$	287,733		Gross revenue	$	313,076	$	625,012	$	1,729,778
Net income (loss)	$	253,451	$	(37,102	)	$	(65,070	)
Net (loss) income									Net (loss) income	$	(106,072)	$	(76,523)	$	253,451

~~Tatex Thailand II, LLC~~

The Company has an indirect ownership interest in Tatex Thailand II, LLC (“Tatex”). Tatex holds an 8.5% interest in APICO, LLC (“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. The Company received $0.2 million and $0.5 million in distributions from Tatex during the years ended December 31, 2018 and 2017, respectively.

~~Tatex Thailand III, LLC~~

The Company had an ownership interest in Tatex Thailand III, LLC ("Tatex III"). Tatex III previously owned a concession covering approximately 245,000 acres in Southeast Asia. As of December 31, 2014, the Company reviewed its investment in Tatex III and, together with Tatex III, made the decision to allow the concession to expire in January 2015. As such, the Company fully impaired the asset as of December 31, 2014. In December 2017, Tatex III was dissolved and the Company received a final distribution of $0.2 million.

Grizzly Oil Sands ULC

The Company, through its wholly owned subsidiary Grizzly Holdings, ~~Inc. ("Grizzly Holdings"),~~ owns ana 24.5% interest in Grizzly, ~~Oil Sands ULC ("Grizzly"),~~ a Canadian unlimited liability company. The remaining interest in Grizzly is owned by Grizzly Oil Sands Inc. ~~("Oil Sands").~~ As of December 31, ~~2018,~~2020, Grizzly had approximately 830,000 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 I steam-assisted gravity drainage ("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 start up plans for the facility.

The Company reviewed its investment in Grizzly ~~as of~~at December 31, ~~2016~~2020 and December 31, 2019 for impairment ~~due to~~based on certain qualitative ~~factors~~ and ~~as such, engaged an independent third party to assist management~~quantitative factors. This resulted in ~~determining fair value calculations of its investment. As a result of the calculated fair values~~recording 0 impairment losses and ~~other qualitative factors, the Company concluded that an other than temporary impairment was required, resulting in an aggregate impairment loss of $23.1~~$32.4 million for the ~~year~~years ended December 31, ~~2016,~~2020 and 2019, respectively, which is included in ~~(income)~~ loss from equity method investments, net in the accompanying consolidated statements of operations. ~~As of and during the periods ended~~The Company reviewed its investment in Grizzly for impairment at December 31, 2018 and ~~2017, commodity prices had increased as compared to 2016.~~ determined 0 impairment was required.

The Company ~~engaged an independent third party~~did 0t pay any cash calls during 2020 as a result of its election to ~~perform a sensitivity analysis based on updated pricing as of December 31, 2018, and concluded that there were no impairment indicators that required~~cease funding further ~~evaluation for impairment. If commodity prices decline~~capital calls in ~~the future however, further impairment of the investment in Grizzly may be necessary. Gulfport~~2019. The Company paid ~~$2.3~~$0.4 million in cash calls during ~~each of~~ the ~~years~~year ended December 31, ~~2018 and December 31, 2017.~~2019 prior to this election. Grizzly’s functional currency is the Canadian dollar. The Company's investment in Grizzly was increased by a $4.2 million foreign currency translation gain, increased by a $9.0 million foreign currency translation gain and decreased by a $15.2 million foreign currency translation loss for the ~~year ended December 31, 2018, and increased by a $12.3 million and $4.2 million foreign currency translation gain for the~~ years ended December 31, ~~2017~~2020, 2019 and ~~2016,~~2018, respectively.

~~Effective October 5, 2012,~~ The Company had $40.6 million and $44.8 million in accumulated other comprehensive loss in its accompanying consolidated balance sheets related to Grizzly ~~entered into a $125.0 million revolving credit facility, of which Grizzly paid the outstanding balance in full in July 2016. Gulfport paid its share of this amount on June 30, 2016.~~

~~Timber Wolf Terminals LLC~~

During 2012, the Company invested in Timber Wolf Terminals LLC (“Timber Wolf”). Timber Wolf was formed to operate a crude/condensate terminal and a sand transloading facility in Ohio. During the years endedat December 31, ~~2018~~2020 and ~~2017, the~~

~~F-19~~

~~Table of Contents~~

~~Index to Financial Statements~~

~~Company paid no cash calls to Timber Wolf. During the year ended~~ December 31, ~~2018, Timber Wolf was dissolved and the Company received a final distribution of $0.4 million.~~

~~Windsor Midstream LLC~~

At December 31, 2018, the Company held a 22.5% interest in Windsor Midstream LLC (“Midstream”), an entity controlled and managed by an unrelated third party. The Company received no distributions from Midstream during the year ended December 31, 2018 and $0.5 million in distributions during the same period in 2017.

~~Stingray Cementing LLC~~

~~During 2012, the Company invested in Stingray Cementing LLC ("Stingray Cementing"). Stingray Cementing provides well cementing services. The (income) loss from equity method investments presented~~2019, respectively, that will be included in the ~~table above reflects any intercompany profit eliminations. On June 5, 2017, the Company contributed all~~calculations of ~~its membership interests in Stingray Cementing~~future charge related to ~~Mammoth Energy. See below under~~ ~~Mammoth Energy Partners LP/Mammoth Energy Services, Inc.~~ ~~for information regarding this transaction.~~a sale or abandonment.

~~Blackhawk Midstream LLC~~

During 2012, the Company invested in Blackhawk Midstream LLC ("Blackhawk"). Blackhawk coordinated gathering, compression, processing and marketing activities for the Company in connection with the development of its Utica Shale acreage. During the year ended December 31, 2018, Blackhawk was dissolved and the Company received a final distribution of $0.04 million.

~~Stingray Energy Services LLC~~

During 2013, the Company invested in Stingray Energy Services LLC ("Stingray Energy"). 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. The (income) loss from equity method investments presented in the table above reflects any intercompany profit eliminations. On June 5, 2017, the Company contributed all of its membership interests in Stingray Energy to Mammoth Energy. See below under ~~Mammoth Energy Partners LP/Mammoth Energy Services, Inc.~~ ~~for information regarding this transaction.~~

~~Sturgeon Acquisitions LLC~~

During 2014, the Company invested in Sturgeon Acquisitions LLC ("Sturgeon") and received an ownership interest of 25% in Sturgeon. Sturgeon owns and operates sand mines that produce hydraulic fracturing grade sand. On June 5, 2017, the Company contributed all of its membership interests in Sturgeon to Mammoth Energy. See below under ~~Mammoth Energy Partners LP/Mammoth Energy Services, Inc.~~ ~~for information regarding this transaction.~~

~~Mammoth Energy Partners LP/~~Mammoth Energy Services, Inc.

In the fourth quarter of 2014, the Company contributed its investments in four entities to Mammoth Energy Partners LP ("Mammoth") for a 30.5% interest in Mammoth. Mammoth originally intended to pursue its initial public offering in 2014 or 2015; however, due to low commodity prices, the offering was postponed. In October 2016, Mammoth converted from a limited partnership into a limited liability company named Mammoth Energy Partners LLC ("Mammoth LLC") and the Company and the other members of Mammoth LLC contributed their interests in Mammoth LLC to Mammoth Energy. The Company received 9,150,000 shares of Mammoth Energy common stock in return for its contribution. Following the contribution, Mammoth Energy completed its initial public offering (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 the Company for which it received net proceeds of $1.1 million. Immediately following the IPO, the Company owned an approximate 24.2% interest in Mammoth Energy. To reflect the dilution of the Company's shares of Mammoth Energy stock after the IPO, the Company recognized a gain of $3.4 million, which is included in gain on sale of equity method investments in the accompanying consolidated statements of operations.

On June 5, 2017, the Company contributed all of its membership interests in Sturgeon (which owns Taylor Frac, LLC, Taylor Real Estate Investments, LLC and South River Road, LLC), Stingray Energy and Stingray Cementing to Mammoth Energy in exchange for approximately 2.0 million shares of Mammoth Energy common stock (the "June 2017 Transactions").

~~F-20~~

~~Table of Contents~~

~~Index to Financial Statements~~

Following the June 2017 transactions, the Company held approximately 25.1% of Mammoth Energy’s outstanding common stock. The Company accounted for the transactions as a sale of financial assets. The Company valued the shares of Mammoth Energy common stock it received in the June 2017 Transactions at $18.50 per share, which was the closing price of Mammoth Energy common stock on June 5, 2017. During the second quarter of 2017, the Company recognized a gain of $12.5 million from the June 2017 Transactions, which is included in gain on sale of equity method investments in the accompanying consolidated statements of operations.

On June 29, 2018, the Company sold 1,235,600 shares of its Mammoth Energy common stock in an underwritten public offering for net proceeds of approximately $47.0 million. In connection with the Company's public offering of a portion of its shares of Mammoth Energy common stock, the Company granted the underwriters an option to purchase additional shares of its Mammoth Energy common stock. On July 26, 2018, the underwriters exercised this option, in part, and on July 30, 2018, the Company sold an additional 118,974 shares for net proceeds of ~~approximately~~approximately $4.5 million. Following the sales of these shares, the Company owned 9,829,548 shares, or ~~21.9%~~21.5% at December 31, 2018, of Mammoth Energy's outstanding common stock. As a result of the sales, the Company recorded a gain of $28.3 million, which is included in gain on sale of equity method investments in the accompanying consolidated statements of operations. The approximate fair value of the Company's investment in Mammoth Energy's common stock at December 31, ~~2018~~2019 was ~~$176.7~~$21.6 million based on the quoted market price of Mammoth Energy's common stock.

At December 31, 2020, the Company owned 9,829,548 shares, or 21.5%, of the outstanding common stock of Mammoth Energy. As a result of the net loss Mammoth sustained in the first quarter of 2020, we recorded a loss of $10.6 million for the year ended December 31, 2020 which reduced the Company's investment balance in Mammoth to 0. This is included in loss (income) from equity method investments, net in the accompanying consolidated statements of operations. The Company's investment in Mammoth Energy was increased by a $0.2 million foreign currency gain and decreased by a $0.4 million foreign currency loss ~~and increased by a $0.2 million foreign currency gain~~ resulting from Mammoth Energy's foreign subsidiary for the years ended December 31, ~~2018~~2019 and ~~2017,~~2018, respectively. During the year ended December 31, ~~2018,~~2019, Gulfport received distributions of $2.5 million from Mammoth Energy as a result of dividends in ~~August 2018~~February 2019 and ~~November 2018.~~May 2019. The approximate fair value of the Company's investment in Mammoth Energy's common stock at December 31, 2020 was $43.7 million based on the quoted market price of Mammoth Energy's common stock. The loss (income) ~~loss~~ from equity method investments presented in the table above reflects any intercompany profit eliminations.

~~Strike Force Midstream~~

Table of Contents

Index to Financial Statement s

Tatex Thailand II, LLC

~~In February 2016, the~~The Company ~~through its wholly-owned subsidiary Gulfport Midstream Holdings, LLC ("Midstream Holdings"), entered into~~has an agreement with Rice Midstream Holdings LLC ("Rice"), a subsidiary of Rice Energy Inc., to develop natural gas gathering assets in eastern Belmont County and Monroe County, Ohio through an entity called Strike Force Midstream LLC ("Strike Force"). In 2017, Rice was acquired by EQT Corporation ("EQT"). Prior to the sale of the Company'sindirect ownership interest in ~~Strike Force (discussed below), the Company owned a 25% interest in Strike Force,~~Tatex Thailand II, LLC ("Tatex") and EQT acted as operator and owned the remaining 75% interest in Strike Force. Strike Force's gathering assets provide gathering services for wells operated by Gulfport and other operators and connectivity of existing dry gas gathering systems. Prior to the sale of its interest in Strike Force, the Company elected to report its proportionate share of Strike Force's earnings on a one-quarter lag as permitted under ASC 323. The (income) lossreceived 0 distributions from ~~equity method investments presented in the table above reflects any intercompany profit eliminations.~~

~~During~~Tatex during the year ended December 31, ~~2018, Gulfport~~2020. The Company received $2.1 million in distributions ~~of $0.8 million~~ from ~~Strike Force. For~~Tatex during the year ended December 31, ~~2017, Gulfport paid $53.0 million in cash calls to Strike Force and received distributions of $6.9 million from Strike Force.~~

~~On May 1, 2018, the Company sold its 25%~~2019. Tatex previously held an 8.5% interest in ~~Strike Force to EQT Midstream Partners, LP for proceeds of $175.0 million~~an entity holding a reserve base in ~~cash. As a result of~~Southeast Asia, including the ~~sale, the Company recognized a gain of $96.4 million net of transaction fees, which is included in gain on sale of equity method investments in the accompanying consolidated statement of operations.~~


5.	~~VARIABLE INTEREST ENTITIES~~

As of December 31, 2018, the Company held a variable interest in Midstream, a variable interest entity ("VIE"), but was not the primary beneficiary. This entity has governing provisions that are the functional equivalent of a limited partnership and is considered a VIE because the limited partners or non-managing members lack substantive kick-out or participating rights which causes the equity owners, as a group, to lack a controlling financial interest. The Company is a limited partner or non-managing member in this VIE and is not the primary beneficiary because it does not have a controlling financial interest. The general partner or managing member has power to direct the activities that most significantly impact the VIE's economic performance. The Company held a variable interest in Timber WolfPhu Horm Field, before ~~the entity was dissolved. The Company was a limited partner or non-managing member in Timber Wolf and was not the primary beneficiary because it did not have a controlling financial interest.~~ The Company also held a variable interest in Strike Force prior to the sale of that interest due to the fact that it does not have sufficient equity capital at risk. The Company was not the primary beneficiary of this entity. Prior to Mammoth Energy's IPO, Mammoth LLC was considered a VIE. As a result of the Company’s contribution ofselling its interest in ~~Mammoth LLC to Mammoth~~June 2019.

~~F-21~~6.LONG-TERM DEBT

~~Table of Contents~~

~~Index to Financial Statements~~

Energy in exchange for Mammoth Energy common stock and the completion of Mammoth Energy’s IPO, the Company determined that it no longer held an interest in a VIE. Prior to the contribution of Stingray Energy, Stingray Cementing and Sturgeon to Mammoth Energy, these entities were considered VIEs. As a result of the Company’s contribution of its membership interests in Stingray Energy, Stingray Cementing and Sturgeon to Mammoth Energy in exchange for Mammoth Energy common stock, the Company determined that it no longer held an interest in a VIE.

The Company accounts for its investment in VIEs following the equity method of accounting. The carrying amounts of the Company’s equity investments are classified as other non-current assets on the accompanying consolidated balance sheets. The Company’s maximum exposure to loss as a result of its involvement with VIEs is based on the Company’s capital contributions and the economic performance of the VIEs, and is equal to the carrying value of the Company’s investments which is the maximum loss the Company could be required to record in the consolidated statements of operations. See Note 4 for further discussion of these entities, including the carrying amounts of each investment.


6.	~~LONG-TERM DEBT~~

Long-term debt consisted of the following items as of December 31:


	2020		2019
	(In thousands)
DIP credit facility	$	157,500	$	0
Pre-petition revolving credit facility	292,910		120,000


6.625% senior unsecured notes due 2023	324,583		329,467
6.000% senior unsecured notes due 2024	579,568		603,428
6.375% senior unsecured notes due 2025	507,870		529,525
6.375% senior unsecured notes due 2026	374,617		397,529

Building loan	21,914		22,453
Net unamortized debt issuance costs	0		(23,751)
Total Debt, net	2,258,962		1,978,651
Less: current maturities of long term debt	(253,743)		(631)
Less: amounts reclassified to liabilities subject to compromise	(2,005,219)		0
Total Debt reflected as long term	$	0	$	1,978,020

2018 2017
(In thousands)
Revolving credit agreement (1) $ 45,000
$ —
6.625% senior unsecured notes due 2023 (2) 350,000
350,000
6.000% senior unsecured notes due 2024 (3) 650,000
650,000
6.375% senior unsecured notes due 2025 (4) 600,000
600,000
6.375% senior unsecured notes due 2026 (5) 450,000
450,000
Net unamortized debt issuance costs (6) (30,733 ) (34,781 )
Construction loan (7) 23,149
23,724
Less: current maturities of long term debt (651 ) (622 )
Debt reflected as long term $ 2,086,765
$ 2,038,321
Chapter 11 Proceedings

~~Maturities~~Filing of ~~long-term~~the Chapter 11 Cases constituted an event of default with respect to certain of our secured and unsecured debt ~~(excluding unamortized~~obligations. As a result of the Chapter 11 Cases, the principal and interest due under these debt ~~issuance costs)~~instruments became immediately due and payable. However, Section 362 of the Bankruptcy Code stays the creditors from taking any action as a result of the default.

The principal amounts from the Senior Notes, Building Loan and Pre-Petition Revolving Credit Facility, other than letters of credit drawn on the Pre-Petition Revolving Credit Facility after the Petition Date, have been classified as liabilities subject to compromise on the accompanying audited consolidated balance sheet as of December 31, ~~2018~~2020. Additionally, non-cash adjustments were made to write off all of the related unamortized debt issuance costs of $22.0 million, which are included in reorganization items, net in the accompanying audited consolidated statements of operations for the year ended December 31, 2020, as ~~follows:~~discussed in Note 2.

Debtor-in-Possession Credit Agreement

Pursuant to the RSA, the Consenting RBL Lenders have agreed to provide the Company with a senior secured superpriority debtor-in-possession revolving credit facility in an aggregate principal amount of $262.5 million consisting of (a) $105 million of new money and (b) $157.5 million to roll up a portion of the existing outstanding obligations under the Pre-Petition Revolving Credit Facility. The terms and conditions of the DIP Credit Facility are set forth in that certain form of credit agreement governing the DIP Credit Facility. The proceeds of the DIP Credit Facility may be used for, among other things, post-petition working capital, permitted capital investments, general corporate purposes, letters of credit, administrative costs, premiums, expenses and fees for the transactions contemplated by the Chapter 11 Cases and payment of court approved adequate protection obligations. In the current period, the Company incurred $3.0 million of fees related to the arrangement and funding of the DIP Credit Facility. The DIP Credit Facility was approved by the Bankruptcy Court on a final basis on December 18, 2020.

Borrowings under the DIP Credit Facility will mature, and the lending commitments thereunder will terminate, upon the earliest to occur of: (a) August 30, 2021; (b) three (3) business days after the Petition Date, if the Interim Order and Hedging

Table of Contents

Index to Financial Statement s

(In thousands)
2019 $ 651
2020 629
2021 45,661
2022 692
2023 350,724
Thereafter 1,719,792
Total $ 2,118,149
Order have not been entered prior to the expiration of such period; (c) thirty five (35) days (or a later date consented to by the Administrative Agent and the Majority Lenders in their sole discretion) after the entry of the Interim Order, if the Bankruptcy Court has not entered the Final Order on or prior to such date; (d) the effective date of an Approved Plan of Reorganization, (e) the consummation of a sale of all or substantially all of the equity and/or assets of the Debtors and budgeted and necessary expenses of the estates; (f) the date of the payment in full, in cash, of all Obligations (and the termination of all Commitments in accordance with the terms hereof); and (g) the date of termination of all Commitments and/or the acceleration of all of the Obligations under the Agreement and the other Loan Documents following the occurrence and during the continuance of an Event of Default.

~~(1)~~ Borrowings under the DIP Credit Facility bear interest at a eurodollar rate or base rate, at our election, plus an applicable margin of 4.50% per annum for eurodollar loans and 3.50% per annum for base rate loans. At December 31, 2020, amounts borrowed under the DIP credit facility bore interest at a weighted average rate of 5.50%. In addition to paying interest on outstanding principal and letters of credit posted under the DIP Credit Facility, we are required to pay a commitment fee of 0.50% per annum to the lenders of the DIP Credit Facility in respect of the unutilized DIP commitments thereunder and a letter of credit fee equal to 0.20% per annum.

The DIP Credit Facility includes negative covenants that, subject to significant exceptions, limit the Company's ability and the ability of its restricted subsidiaries to, among other things, (i) create liens on assets, property revenues, (ii) make investments, (iii) incur additional indebtedness, (iv) engage in mergers, consolidations, liquidations and dissolutions, (v) sell assets, (vi) pay dividends and distributions or repurchase capital stock, (vii) cease for any reason to be the operator of its properties, (viii) enter into letters of credit without prior written consent, (ix) enter into certain commodity hedging contracts except commodity hedging contracts with terms approved by the Bankruptcy Court in the hedging order or certain interest rate contracts, (x) change lines of business, (xi) engage in certain transactions with affiliates and (xii) incur more than a certain amount in capital expenditures in any calendar month. The DIP Credit Facility includes certain customary representations and warranties, affirmative covenants and events of default, including but not limited to defaults on account of nonpayment, breaches of representations and warranties and covenants, certain bankruptcy-related events, certain events under ERISA, material judgments and a change in control. If an event of default occurs, the lenders under the DIP Credit Facility will be entitled to take various actions, including the acceleration of all amounts due under the DIP Credit Facility and all actions permitted to be taken under the loan documents or application of law. In addition, the DIP Credit Facility is subject to various other financial performance covenants, including compliance with certain financial metrics and adherence to a budget approved by the Company's DIP Credit Facility lenders.

Pre-Petition Revolving Credit Facility

The Company has entered into a senior secured revolving credit facility agreement, as amended, with ~~the~~The Bank of Nova Scotia, as the lead arranger and administrative agent and certain lenders from time to time party thereto. ~~The credit agreement provides for a maximum facility amount~~On May 1, 2020, the Company entered into the fifteenth amendment to the Amended and Restated Credit Agreement. As part of ~~$1.5~~the amendment, the Company's borrowing base and elected commitment were reduced from $1.2 billion and ~~matures on December 31, 2021. On March 29, 2017,~~$1.0 billion, respectively, to $700.0 million. Additionally, the ~~Company further amended its revolving credit facility~~amendment added a requirement to ~~among other things, amend the definition~~maintain a ratio of ~~the term~~Net Secured Debt to EBITDAX to permit pro forma treatment of acquisitions that involve the payment of consideration by Gulfport and its subsidiaries in excess of $50.0 million and of dispositions of property or series of related dispositions of properties that yields gross proceeds to Gulfport or any of its subsidiaries in excess of $50.0 million. On May 4, 2017,(as defined under the revolving credit ~~facility was further amended~~agreement) not exceeding 2.00 to ~~increase~~1.00, deferred the requirement to maintain a ratio of Net Funded Debt to EBITDAX of 4.00 to 1.00 until September 30, 2021, and added a limitation on the repurchase of unsecured notes, among other amendments.

On July 27, 2020, the Company entered into the sixteenth amendment to the Amended and Restated Credit Agreement. Among other changes, the Sixteenth Amendment amends the Credit Agreement to: (i) require that, in the event of any issuances of Senior Notes, including Second Lien Notes, after the effective date, the then effective borrowing base ~~from $700.0 million~~will be reduced by a variable amount prescribed in the Credit Agreement to ~~$1.0 billion, adjust certain~~the extent the proceeds are not used to satisfy previously issued senior notes within 90 days of such issuance; (ii) require that each Loan Notice specify the amount of the ~~Company’s investment baskets~~then effective Borrowing Base and ~~add five additional banks~~Pro Forma Borrowing Base, the Aggregate Elected Commitment Amount, and the current Total Outstandings, both with and without regard to the ~~syndicate. On November 21, 2017,~~requested Borrowing; (iii) permit the ~~Company further amended its revolving credit facility~~Borrower or any Restricted Subsidiary to among other things, (a) decrease the applicable rate for all loans by 0.5% and (b) add a provision that allows Gulfport to elect a commitment amount (the “Elected Commitment Amount”) that is less than the borrowing base. Inenter into obligations in connection with ~~this amendment,~~a Permitted Bond Hedge Transaction or Permitted Warrant Transaction; (iv) permit the

Borrower to make any payments of Senior Notes and Subordinated Obligation prior to their scheduled maturity, in any event not to exceed $750 million or, if lesser, the net cash proceeds of any Senior Notes issued within 90 days before such payment; (v) require that the Senior Notes have a stated maturity date of no earlier than March 13, 2024, as well as not require payment of principal prior to such date, in order for the Borrower to be permitted to secure indebtedness under the Senior Notes; (vi) permit certain additional liens securing obligations in respect of the incurrence or issuance of any Permitted Refinancing Notes (as such term is defined in the Credit Agreement) not to exceed $750 million, subject to the terms of an intercreditor agreement; and (vii) amend and restate the Applicable Rate Grid.

~~F-22~~

Table of Contents

Index to Financial ~~Statements~~Statement s

On October 8, 2020, the Company's borrowing base under its Pre-Petition Revolving Credit Facility was ~~set at $1.2 billion, with an elected commitment of $1.0 billion.~~reduced for the second time in 2020 from $700 million to $580 million, thereby significantly reducing the Company's available liquidity. On ~~May 21, 2018,~~October 15, 2020, the Company ~~further amended~~elected to not pay interest on certain Senior Notes outstanding triggering a default under the credit agreement. There was $292.9 million of outstanding borrowings under the Pre-Petition Revolving Credit Facility as of December 31, 2020 that were not rolled up into the DIP Credit Facility. This amount of indebtedness will remain outstanding throughout the Chapter 11 Cases and will continue to accrue interest at the default interest rate on amounts drawn after the Petition Date. The Company made certain adequate protection payments of $1.3 million on its Pre-Petition Revolving Credit Facility between the Petition Date and December 31, 2020 which reduced the amount of outstanding borrowings under the Pre-Petition Revolving Credit Facility classified as liabilities subject to compromise as of December 31, 2020 in the accompanying consolidated balance sheets.

Additionally, as of December 31, 2020, we had an aggregate of $147.5 million of letters of credit outstanding under our Pre-Petition Revolving Credit Facility. This facility is secured by substantially all of our assets. All of our wholly-owned subsidiaries, excluding Grizzly Holdings and Mule Sky, guarantee our obligations under our revolving credit ~~facility to, among other things, (a) decrease~~facility.

During the ~~applicable rate for all loans~~fourth quarter of 2020, $171.8 million was drawn on letters of credit secured by ~~0.25%, (b) permit Gulfport and each~~the Company's Pre-Petition Revolving Credit Facility by its firm transportation providers. Of these drawn letters of ~~its subsidiaries to use~~credit, $96.2 million were drawn after the ~~proceeds from dispositions~~Petition Date. As these were post-petition activities, the post-petition letters of ~~certain investments to acquire~~credit drawn are included in current portion of long-term debt, in the ~~common stock or other equity interests~~accompanying consolidated balance sheets. The pre-petition amounts are included in borrowings outstanding as of ~~Gulfport,~~December 31, 2020 which are included in liabilities subject to ~~certain limitations and (c) increase~~compromise in the ~~borrowing base to $1.4 billion, with an elected commitment of $1.0 billion. On November 28, 2018,~~accompanying consolidated balance sheets. At December 31, 2020 the Company ~~further amended its revolving~~included $111.8 million in prepaid and other current assets in the accompanying consolidated balance sheets as an offset for the drawn letters of credit. A portion of the drawn letters of credit ~~facility~~were netted against pre-petition accounts payable to ~~amount other things, (a) permit Gulfport~~the Company's firm transportation providers and ~~each~~another portion was charged to reorganization items, net in the accompanying consolidated statements of its subsidiaries to directly or indirectly purchase, redeem or otherwise acquire equity interests of Gulfport, subject to certain limitations and (b) reaffirm the borrowing base of $1.4 billion, with an elected commitment of $1.0 billion.operations.

As of December 31, 2018, $45.0 million was outstanding under the revolving credit facility and the total availability for future borrowings under this facility, after giving effect to an aggregate of $316.6 million of letters of credit, was $638.4 million. The Company's wholly-owned subsidiaries have guaranteed the obligations of the Company under the revolving credit facility.

Advances under the revolving credit facility may be in the form of either base rate loans or eurodollar loans. The interest rate for base rate loans is equal to (1) the applicable rate, which ranges from 0.25% to 1.25%, plus (2) the highest of: (a) the federal funds rate plus 0.50%, (b) the rate of interest in effect for such day as publicly announced from time to time by agent as its “prime rate,” and (c) the eurodollar rate for an interest period of one month plus 1.00%. The interest rate for eurodollar loans is equal to (1) the applicable rate, which ranges from 1.25% to 2.25%, plus (2) the London interbank offered rate that appears on pages LIBOR01 or LIBOR02 of the Reuters screen that displays such rate for deposits in U.S. dollars, or, if such rate is not available, the rate as administered by ICE Benchmark Administration (or any other person that takes over administration of such rate) per annum equal to the offered rate on such other page or service that displays on average London interbank offered rate as determined by ICE Benchmark Administration (or any other person that takes over administration of such rate) for deposits in U.S. dollars, or, if such rate is not available, the average quotations for three major New York money center banks of whom the agent shall inquire as the “London Interbank Offered Rate” for deposits in U.S. dollars. At December 31, 2018,2020, amounts borrowed under the ~~credit facility~~Pre-Petition Revolving Credit Facility bore interest at athe weighted average rate of ~~4.23%~~3.15%.

~~The revolving credit facility contains customary negative covenants including, but not limited to, restrictions on the Company’s and its subsidiaries’ ability to:~~Senior Unsecured Notes

•~~incur indebtedness;~~

•~~grant liens;~~

•~~pay dividends and make other restricted payments;~~

•~~make investments;~~

•~~make fundamental changes;~~

•~~enter into swap contracts;~~

•~~dispose of assets;~~

•~~change the nature of their business; and~~

•~~enter into transactions with affiliates.~~

The negative covenants are subject to certain exceptions as specified in the revolving credit facility. The revolving credit facility also contains certain affirmative covenants, including, but not limited to the following financial covenants:

(i) the ratio of net funded debt to EBITDAX (net income, excluding (i) any non-cash revenue or expense associated with swap contracts resulting from ASC 815 and (ii) any cash or non-cash revenue or expense attributable to minority investments plus without duplication and, in the case of expenses, to the extent deducted from revenues in determining net income, the sum of (a) the aggregate amount of consolidated interest expense for such period, (b) the aggregate amount of income, franchise, capital or similar tax expense (other than ad valorem taxes) for such period, (c) all amounts attributable to depletion, depreciation, amortization and asset or goodwill impairment or writedown for such period, (d) all other non-cash charges, (e) explorationLoan issuance costs ~~deducted in determining net income under successful efforts accounting, (f) actual cash distributions received~~

~~F-23~~

~~Table of Contents~~

~~Index to Financial Statements~~

from minority investments, (g) to the extent actually reimbursed by insurance, expenses with respect to liability on casualty events or business interruption, and (h) all reasonable transaction expenses related to dispositions and acquisitions of assets, investments and debt and equity offerings (provided that expenses related to any unsuccessful disposition will be limited to $3.0 million in the aggregate) for a twelve-month period may not be greater than 4.00 to 1.00; and

~~(ii) the ratio of EBITDAX to interest expense for a twelve-month period may not be less than 3.00 to 1.00.~~

~~The Company was in compliance with all covenants at December 31, 2018.~~

(2) On April 21, 2015, the Company issued $350.0 million in aggregate principal amount of 6.625% Senior Notes due 2023 (the "2023 Notes") to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act (the "2023 Notes Offering"). The Company received net proceeds of approximately $343.6 million after initial purchaser discounts and commissions and estimated offering expenses.

The 2023 Notes were issued under an indenture, dated as of April 21, 2015, among the Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee. In October 2015, the 2023 Notes were exchanged for a new issue of substantially identical debt securities registered under the Securities Act. Pursuant to the indenture relating to the 2023 Notes, interest on the 2023 Notes accrues at a rate of 6.625% per annum on the outstanding principal amount thereof, payable semi-annually on May 1 and November 1 of each year. The 2023 Notes are not guaranteed by Grizzly Holdings, Inc. and will not be guaranteed by any of the Company's future unrestricted subsidiaries.

In connection with the 2023 Notes Offering, the Company and its subsidiary guarantors entered into a registration rights agreement, dated as of April 21, 2015, pursuant to which the Company agreed to file a registration statement with respect to an offer to exchange the 2023 Notes for a new issue of substantially identical debt securities registered under the Securities Act. The exchange offer for the 2023 Notes was completed on October 13, 2015.

(3) On October 14, 2016, the Company issued $650.0 million in aggregate principal amount of 6.000% Senior Notes due 2024 (the "2024 Notes"). The 2024 Notes were issued under an indenture, dated as of October 14, 2016, among the Company, the subsidiary guarantors party thereto and the senior note indenture trustee (the "2024 Indenture"), to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act (the “2024 Notes Offering”). Under the 2024 Indenture, interest on the 2024 Notes accrues at a rate of 6.000% per annum on the outstanding principal amount thereof from October 14, 2016, payable semi-annually on April 15 and October 15 of each year, commencing on April 15, 2017. The 2024 Notes will mature on October 15, 2024. The Company received approximately $638.9 million in net proceeds from the offering of the 2024 Notes, which was used, together with cash on hand, to purchase the outstanding 2020 Notes in a concurrent cash tender offer, to pay fees and expenses thereof, and to redeem any of the 2020 Notes that remained outstanding after the completion of the tender offer.

(4) On December 21, 2016, the Company issued $600.0 million in aggregate principal amount of 6.375% Senior Notes due 2025 (the “2025 Notes”). The 2025 Notes were issued under an indenture, dated as of December 21, 2016, among the Company, the subsidiary guarantors party thereto and the senior note indenture trustee (the "2025 Indenture"), to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. Under the 2025 Indenture, interest on the 2025 Notes accrues at a rate of 6.375% per annum on the outstanding principal amount thereof from December 21, 2016, payable semi-annually on May 15 and November 15 of each year, commencing on May 15, 2017. The 2025 Notes will mature on May 15, 2025. The Company received approximately $584.7 million in net proceeds from the offering of the 2025 Notes, which was used, together with the net proceeds from the Company's December 2016 common stock offering and cash on hand, to fund the cash portion of the purchase price for the Vitruvian Acquisition. See Note 2 for additional discussion of the Vitruvian Acquisition.

In connection with each of the 2024 and 2025 Notes Offering, the Company and its subsidiary guarantors entered into a registration rights agreement pursuant to which the Company agreed to file a registration statement with respect to offers to exchange the 2024 Notes and 2025 Notes for a new issue of substantially identical debt securities registered under the Securities Act. The exchange offers for the 2024 Notes and 2025 Notes were completed on September 12, 2017.

(5) On October 11, 2017, the Company issued $450.0 million in aggregate principal amount of its 6.375% Senior Notes due 2026 (the “2026 Notes”) to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. Interest on the 2026 Notes accrues at a rate of 6.375% per annum on the outstanding principal amount thereof from October 11, 2017, payable semi-annually on January 15 and July 15 of each year, commencing on January 15, 2018. The 2026 Notes will mature on January 15, 2026. The Company received

~~F-24~~

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~~Index to Financial Statements~~

approximately $444.1 million in net proceeds from the offering of the 2026 Notes, a portion of which was used to repay all of the Company's outstanding borrowings under its secured revolving credit facility on October 11, 2017 and the balance was used to fund the remaining outspend related to the ~~Company's 2017 capital development plans.~~

~~In connection with the 2026~~Senior Notes offering, the Company and its subsidiary guarantors entered into a registration rights agreement pursuant to which the Company agreed to file a registration statement with respect to an offer to exchange the 2026 Notes for a new issue of substantially identical debt securities registered under the Securities Act. On January 18, 2018, the Company filed a registration statement on Form S-4 with respect to an offer to exchange the 2026 Notes for substantially identical debt securities registered under the Securities Act, which registration statement was declared effective by the SEC on February 12, 2018. The exchange offer relating to the 2026 Notes closed on March 22, 2018.

~~(6) Loan issuance cost related to the 2023 Notes, the 2024 Notes, the 2025 Notes and the 2026 Notes (collectively the "Notes")~~ have been presented as a reduction to the ~~Notes.~~principal amount of the Senior Notes at December 31, 2019. At December 31, ~~2018, total~~2020, there were no remaining unamortized ~~debt~~loan issuance costs ~~were $4.4~~related to the Senior Notes. The Company expensed approximately $22.0 million ~~for~~in unamortized loan issuance costs related to the ~~2023~~Senior Notes ~~$8.7 million for~~to reorganization items, net as a result of the ~~2024 Notes, $12.5 million for~~Chapter 11 filing and the ~~2025 Notes and $5.0 million for the 2026 Notes.~~ application of ASC 852.

Building Loan

In ~~addition, loan commitment fee costs for the construction loan agreement described immediately below were $0.1 million at December 31, 2018.~~

~~(7) On~~ June 4, 2015, the Company entered into a ~~construction~~ loan ~~agreement (the "Construction Loan") with InterBank~~ for the construction of ~~a new~~its corporate headquarters in Oklahoma City, which was substantially completed in December 2016. The Construction Loan allows for maximum principal borrowings of $24.5 million and required the Company to fund 30% of the cost of the construction before any funds could be drawn, which occurred in January 2016. Interest accrues daily on the outstanding principal balance at a fixed rate of 4.50% per ~~annum and was payable~~annum. The building loan matures on ~~the last day of the month through May 31, 2017. Starting June 30, 2017, the Company began making monthly payments of principal and interest, with the final payment due~~ June 4, 2025. AtAs of December 31, ~~2018,~~2020, the total borrowings under the ~~Construction~~building loan were approximately ~~$23.1 million.~~$21.9 million, which has been classified as liabilities subject to compromise in the accompanying consolidated balance sheets as of December 31, 2020.

Debt Repurchases

In July of 2019, the Company's Board of Directors authorized $100 million of cash to be used to repurchase its Senior Notes in the open market at discounted values to par. In December 2019, the Company's Board of Directors increased the authorized size of its senior note repurchase program to $200 million in total. During the year ended December 31, 2020, the Company used borrowings under its revolving credit facility to repurchase in the open market approximately $73.3 million aggregate principal amount of its outstanding Notes for $22.8 million in cash and recognized a $49.6 million gain on debt extinguishment, which included retirement of unamortized issuance costs and fees associated with the repurchased debt. This gain is included in gain on debt extinguishment in the accompanying consolidated statements of operations.

Interest Expense

The following schedule shows the components of interest expense for the year ended December 31:

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	2018			2017			2016				2020		2019		2018
	(In thousands)										(In thousands)
Cash paid for interest	$	126,342		$	101,958		$	68,966		Cash paid for interest	$	84,823	$	142,664	$	132,995
Change in accrued interest	7,280			10,699			1,768			Change in accrued interest	30,600		(3,834)		7,266
Capitalized interest	(4,470		)	(9,470		)	(9,148		)	Capitalized interest	(907)		(3,372)		(4,470)
Amortization of loan costs	6,121			5,011			3,660			Amortization of loan costs	5,563		6,328		6,121
Amortization of note discount and premium	—			—			(1,716		)

Total interest expense	$	135,273		$	108,198		$	63,530		Total interest expense	$	120,079	$	141,786	$	141,912

The Company capitalized approximately ~~$4.5~~$0.9 million and ~~$9.5~~$3.4 million in interest expense to undeveloped oil and natural gas properties during the years ended December 31, ~~2018~~2020 and ~~2017,~~2019, respectively.


7.	~~COMMON STOCK OPTIONS, RESTRICTED STOCK AND CHANGES IN CAPITALIZATION~~

~~Options~~Fair Value of Debt

~~In January 2005,~~At December 31, 2020, the ~~Company adopted~~carrying value of the ~~2005 Stock Incentive Plan (“2005 Plan”), which is administered~~outstanding debt represented by the ~~Compensation Committee (the "Committee"). Under~~Notes was approximately $1.8 billion. Based on the ~~terms~~quoted market prices (Level 1), the fair value of the ~~2005 Plan, the Committee may determine when options shall~~Notes was determined to be granted, to which eligible participants options shall be granted, the number of shares covered by such options, the purchase price or exercise price of such options, the vesting periods of such options and the exercisable period of such options. Eligible participants are defined as employees, consultants, and directors of the Company.

On April 20, 2006, the Company amended and restated the 2005 Plan to (i) include (a) incentive stock options, (b) nonstatutory stock options, (c) restricted awards (restricted stock and restricted stock units), (d) performance awards and (e) stock appreciation rights and (ii) increase the maximum aggregate amount of common stock that may be issued under the 2005 Plan from 1,904,606 shares to 3,000,000 shares, including the 627,337 shares underlying options granted to employees

~~F-25~~

~~Table of Contents~~

~~Index to Financial Statements~~

~~under the Plan prior to adoption of the 2005 Plan. As of~~approximately $1.2 billion at December 31, 2018, the Company had granted 997,269 options for the purchase of shares of the Company’s common stock and 1,143,217 shares of restricted stock under the 2005 Plan. No additional securities will be issued under the Plan.2020.

On April 19, 2013, the Company amended and restated the 2005 Plan with the 2013 Restated Stock Incentive Plan ("2013 Plan"). The 2013 Plan increased the numbers of shares that may be awarded from 3,000,000 to 7,500,000 shares, including the 627,337 shares underlying options granted to employees under the 2005 Plan. The shares of stock issued once the options are exercised will be from authorized but unissued common stock. As of December 31, 2018, the Company had granted 3,518,964 shares of restricted stock under the 2013 Plan.

~~Issuance of Common Stock~~

On March 15, 2016, the Company issued 16,905,000 shares of its common stock in an underwritten public offering (which included 2,205,000 shares sold pursuant to an option to purchase additional shares of the Company's common stock granted by the Company to, and exercised in full by, the underwriters). The net proceeds from this equity offering were approximately $411.7 million, after underwriting discounts and commissions and offering expenses. The Company used the net proceeds from this offering primarily to fund a portion of its 2017 capital development plan and for general corporate purposes.7.CHANGES IN CAPITALIZATION

On December 21, 2016, the Company issued an aggregate 33,350,000 shares of its common stock in an underwritten public offering (which included 4,350,000 shares subject to an option to purchase additional shares exercised by the underwriters). The net proceeds from this equity offering were approximately $698.8 million, after deducting underwriting discounts and commissions and estimated offering expenses. The Company used the net proceeds from this offering, together with the net proceeds from the offering of the 2025 Notes and cash on hand, to fund the cash portion of the purchase price for the Vitruvian Acquisition (see Note 2).

On February 17, 2017, the Company completed the Vitruvian Acquisition for a total initial 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 are subject to the indemnity escrow). See Note 2 for additional discussion of the Vitruvian Acquisition.

Stock Repurchases

In January 2018, the board of directors of the Company approved a stock repurchase program to acquire up to $100 million of the Company's outstanding stock during 2018. In May 2018, the Company's board of directors authorized the expansion of its stock repurchase program, authorizing the Company to acquire up to an additional $100 million of its outstanding common stock during 2018 for a total of up to $200 million. ~~The repurchase program does not require the Company to acquire any specific number of shares.~~ This repurchase program was authorized to extend through December 31, 2018 and ~~was fully executed. For the year ended December 31, 2018,~~ the Company repurchased 20.7 million shares of common stock in 2018 for $200.0 million in aggregate consideration.

In January 2019, the board of directors of the Company approved a new stock repurchase program to acquire a portion of the Company's outstanding common stock within a 24-month period. During 2019, the Company repurchased 3.8 million shares for a cost of approximately ~~$200.0~~$30 million under this ~~repurchase~~board approved program. ~~Additionally, for~~The program was suspended in the ~~year~~fourth quarter of 2019, and 0 further repurchases were made under this program.

For the years ended December 31, ~~2018,~~2020 and 2019, the Company repurchased approximately ~~29,000~~0.2 million and 0.1 million shares for ~~a cost of~~ approximately ~~$0.3~~$0.2 million and $0.7 million, respectively, to satisfy tax withholding requirements incurred upon the vesting of restricted stock. All repurchased shares have been ~~canceled.~~canceled and returned to the status of authorized but unissued shares.


8.	~~STOCK-BASED COMPENSATION~~

8.STOCK-BASED COMPENSATION

The Company adopted the 2005 Plan in January 2005. The 2005 Plan was amended and restated in April 2013 with the 2013 Plan. During 2019, the Company further amended and restated the 2013 Plan with the 2019 Plan. The 2019 Plan provides for grants of options, stock appreciation rights, restricted awards (restricted stock and restricted stock units) and performance awards to employees, consultants and directors of the Company that, in aggregate, do not exceed 12,500,000 shares. The 2019 Plan is administered by the Compensation Committee of the Company's board of directors (the "Committee"). Among other responsibilities, the Committee selects individuals to receive awards and establishes the terms of awards. As of December 31, 2020, the Company has awarded an aggregate of 7,630,554 restricted stock units and 840,595 performance vesting restricted stock units under the 2019 Plan.

During the years ended December 31, ~~2018, 2017~~2020, 2019 and ~~2016~~2018 the Company’s stock-based compensation cost was ~~$11.3~~$16.3 million, ~~$10.6~~$10.7 million and ~~$12.3~~$11.3 million, respectively, of which the Company capitalized ~~$4.5~~$2.9 million, ~~$4.2~~$5.8 million and ~~$4.9~~$4.5 million, respectively, relating to its exploration and development efforts. Stock compensation costs, net of the amounts capitalized, are included in general and administrative expenses in the accompanying consolidated statements of operations.

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The following table summarizes restricted stock unit and performance vesting restricted stock unit activity for the twelve months ended December 31, ~~2018, 2017~~2020, 2019 and ~~2016:~~2018:


	Number of Unvested Restricted Stock Units	Weighted Average Grant Date Fair Value		Number of Unvested Performance Vesting Restricted Stock Units	Weighted Average Grant Date Fair Value
Unvested shares as of January 1, 2018	976,027	$	18.71	0	$	0
Granted	1,579,911	9.90		0	0
Vested	(626,671)	18.05		0	0
Forfeited	(393,456)	12.23		0	0
Unvested shares as of December 31, 2018	1,535,811	$	11.57	0	$	0
Granted	4,011,073	$	3.74	2,009,144	2.85
Vested	(676,108)	12.89		0	0
Forfeited	(772,458)	6.05		(225,484)	1.98
Unvested shares as of December 31, 2019	4,098,318	$	4.73	1,783,660	$	2.96
Granted	3,069,521	0.85		0	0
Vested	(1,294,285)	5.73		0	0
Forfeited	(4,171,041)	1.68		(943,065)	1.98
Unvested shares as of December 31, 2020	1,702,513	$	4.74	840,595	$	4.07

Restricted Stock Units

~~F-26~~

~~Table~~Restricted stock units awarded under the 2019 Plan generally vest over a period of ~~Contents~~

~~Index to Financial Statements~~

Number of
Unvested
Restricted Shares

Weighted
Average
Grant Date
Fair Value
Unvested shares as of January 1, 2016 484,239
$ 43.51
Granted 451,241
27.78
Vested (252,566 ) 43.94
Forfeited (69,858 ) 33.43
Unvested shares as of December 31, 2016 613,056
$ 32.90
Granted 876,846
$ 15.14
Vested (423,977 ) 29.90
Forfeited (89,898 ) 27.91
Unvested shares as of December 31, 2017 976,027
$ 18.71
Granted 1,579,911
9.90
Vested (626,671 ) 18.05
Forfeited (393,456 ) 12.23
Unvested shares as of December 31, 2018 1,535,811
$ 11.57

one year in the case of directors and three years in the case of employees and vesting is dependent upon the recipient meeting applicable service requirements. Stock-based compensation costs are recorded ratably over the service period. The grant date fair value of restricted stock units represents the closing market price of the Company's common stock on the date of grant. Unrecognized compensation expense as of December 31, ~~2018~~2020 related to outstanding restricted stock ~~options and restricted shares~~units was ~~$13.9~~$5.2 million. The expense is expected to be recognized over a weighted average period of ~~1.60~~1.31 years.

Performance Vesting Restricted Stock Units

During the year ended December 31, 2019, the Company awarded performance vesting restricted stock units to certain of its executive officers under the 2019 Plan. The number of shares of common stock issued pursuant to the award will be based on Relative Total Shareholder Return ("RTSR"). RTSR is an incentive measure whereby participants will earn from 0% to 200% of the target award based on the Company’s RTSR ranking compared to the RTSR of the companies in the Company’s designated peer group at the end of the performance period. Awards will be earned and vested over a performance period measured from January 1, 2019 to December 31, 2021, subject to earlier termination of the performance period in the event of a change in control. The grant date fair value was determined using the Monte Carlo simulation method and is being recorded ratably over the performance period. Expected volatilities utilized in the Monte Carlo model were estimated using a historical period consistent with the remaining performance period of approximately two years. The risk-free interest rates were based on the U.S. Treasury rate for a term commensurate with the expected life of the grant. The Company assumed a range of risk-free interest rates of 1.56% to 2.42% and a range of expected volatilities of 29.1% to 85.1% to estimate the fair value of performance vesting units granted during the year ended December 31, 2020. Unrecognized compensation expense as of December 31, 2020 related to performance vesting restricted stock units was $1.4 million. The expense is expected to be recognized over a weighted average period of 1.27 years.

Cash Incentive Awards

On March 16, 2020, the Board of Directors of the Company approved the Company's 2020 Incentive Plan (the "2020 Incentive Plan"). The 2020 Incentive Plan provided for incentive compensation opportunities ("Incentive Awards") for select employees of the Company that were tied to the achievement of one or more performance goals relating to certain financial and operational metrics over a period of time. During March 2020, the Company awarded Incentive Awards to certain of its executive officers under the 2020 Incentive Plan. The cash amount of each award to be ultimately received was based on the attainment of certain financial, operational and total shareholder return performance targets and was subject to the recipient's

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9.			~~FAIR VALUE OF FINANCIAL INSTRUMENTS~~

continuous employment. The Incentive Awards were considered liability awards as the ultimate amount of the award was based, at least in part, on the price of the Company's shares, and as such, were remeasured to fair value at the end of each reporting period. In August 2020 all previous unpaid amounts related to the Incentive Awards issued under the 2020 Incentive Plan were canceled and replaced with cash retention incentives, as discussed below.

2020 Compensation Adjustments

On August 4, 2020, the Company's Board of Directors authorized a redesign of the incentive compensation program for the Company's workforce, including for its current named executive officers. In connection with a comprehensive review of the Company’s compensation programs and in consultation with its independent compensation consultant and legal advisors, the Board of Directors determined that significant changes were appropriate to retain and motivate the Company’s employees as a result of the ongoing uncertainty and unprecedented disruption in the oil and gas industry.

All unpaid amounts previously awarded pursuant to the 2020 Incentive Plan and all restricted stock units granted in March 2020 to the Company's named executive officers were cancelled and replaced with cash retention incentives. These cash retention incentives are equally weighted between achievement of certain specified performance metrics and a service period. Of the cash retention incentives, 50% may be clawed back on an after-tax basis if an executive officer terminates employment for any reason other than a qualifying termination prior to the earlier of July 31, 2021, a change in control or completion of a restructuring, and the remaining 50% will be subject to repayment on an after-tax basis if established performance metrics are not met over performance periods from August 1, 2020 through July 31, 2021. In total, $13.5 million in cash retention incentives were paid to the Company's executives in August 2020.

The ~~carrying amounts on~~transactions were considered a modification to the previously issued equity- and liability-classified awards, and the previously issued equity-classified awards were reclassified as liability awards. The after-tax value of the cash incentives paid to the Company's executives of $3.6 million as of December 31, 2020 was capitalized to prepaid expenses and other current assets in the accompanying consolidated balance ~~sheet for~~sheets and will be amortized over the remaining service period. The Company immediately expensed the difference between the cash and after-tax value of the prepaid cash ~~equivalents, accounts receivable, accounts payable and accrued liabilities, and current debt are carried at cost,~~incentives of $4.8 million, which ~~approximates market value due to their short-term nature. Long-term debt related~~is not subject to the ~~Construction Loan~~clawback provisions, and recognized an additional $1.5 million in stock compensation expense to adjust for the difference in cash retention amounts paid and expense previously recognized on the modified awards at the modification date.

9.REVENUE FROM CONTRACTS WITH CUSTOMERS

Revenue Recognition

The Company’s revenues are primarily derived from the sale of natural gas, oil and condensate and NGL. Sales of natural gas, oil and condensate and NGL are recognized in the period that the performance obligations are satisfied. The Company generally considers the delivery of each unit (MMBtu or Bbl) to be separately identifiable and represents a distinct performance obligation that is ~~carried~~satisfied at ~~cost, which approximates~~the time control of the product is transferred to the customer. Revenue is measured based on consideration specified in the contract with the customer, and excludes any amounts collected on behalf of third parties. These contracts typically include variable consideration that is based on pricing tied to market ~~value~~indices and volumes delivered in the current month. As such, this market pricing may be constrained (i.e., not estimable) at the inception of the contract but will be recognized based on the ~~borrowing rates currently available~~applicable market pricing, which will be known upon transfer of the goods to the ~~Company with similar terms and maturities.~~

~~At December 31, 2018, the carrying value~~customer. The payment date is usually within 30 days of the outstanding debt represented by the Notes was $2.0 billion including the unamortized debt issuance cost of approximately $4.4 million related to the 2023 Notes, approximately $8.7 million related to the 2024 Notes, approximately $12.5 million related to the 2025 Notes, and approximately $5.0 million related to the 2026 Notes. Based on the quoted market price, the fair valueend of the ~~Notes was determined to be approximately $1.8 billion at December 31, 2018.~~calendar month in which the commodity is delivered.


~~10.~~	~~REVENUE FROM CONTRACTS WITH CUSTOMERS~~

On January 1, 2018, the Company adopted ASC 606 using the modified retrospective transition applied to contracts that were not completed as of that date. The adoption did not result in a material change in the Company’s accounting or have a material effect on the Company’s financial position, including measurement of revenue, the timing of revenue recognition and the recognition of contract assets, liabilities and related costs. For periods through December 31, 2017, the Company accounted for its revenue using ASC 605, ~~Revenue Recognition~~.

Transaction Price Allocated to Remaining Performance Obligations

A significant number of the Company's product sales are short-term in nature generally through evergreen contracts with contract terms of one year or less. These contracts typically automatically renew under the same provisions. For those contracts, the Company has utilized the practical expedient allowed in the new revenue accounting standard that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

For product sales that have a contract term greater than one year, the Company has utilized the practical expedient that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required. Currently, the Company's product sales

~~F-27~~

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~~Index to Financial Statements~~

that have a contractual term greater than one year have no long-term fixed consideration.

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Contract Balances

Receivables from contracts with customers are recorded when the right to consideration becomes unconditional, generally when control of the product has been transferred to the customer. Receivables from contracts with customers were ~~$210.2~~$119.9 million and ~~$146.8~~$121.2 million as of December 31, ~~2018~~2020 and December 31, ~~2017,~~2019, respectively, and are reported in accounts receivable - oil and natural gas sales onin the accompanying consolidated balance ~~sheet.~~sheets. The Company currently has no assets or liabilities related to its revenue contracts, including no upfront or rights to deficiency payments.

~~Contract Modifications~~

For contracts modified prior to the beginning of the earliest reporting period presented under ASC 606, the Company has elected to reflect the aggregate of the effect of all modifications that occurred before the beginning of the earliest period presented under the new standard when identifying the satisfied and unsatisfied performance obligations, determining the transaction price and allocating the transaction price to the satisfied and unsatisfied performance obligations for the modified contracts at transition.

Prior-Period Performance Obligations

The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain ~~gas and NGLs~~ sales may be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. The differences between the estimates and the actual amounts for product sales is recorded in the month that payment is received from the purchaser. ~~The Company has internal controls in place for the estimation process and any identified differences between revenue estimates and actual revenue received historically have not been significant.~~ For the year ended December 31, ~~2018,~~2020, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

10.LEASES

Nature of Leases

The Company has operating leases on certain equipment and field offices with remaining lease durations in excess of one year. The Company recognizes a right-of-use asset and lease liability on the balance sheet for all leases with lease terms of greater than one year. Short-term leases that have an initial term of one year or less are not capitalized.

The Company has entered into contracts for drilling rigs with varying terms with third parties to ensure operational continuity, cost control and rig availability in its operations. The Company has concluded its drilling rig contracts are operating leases as the assets are identifiable and the Company has the right to control the identified assets. The Company's drilling rig commitments are typically structured with an initial term of less than one year to two years, although at December 31, 2020, the Company did not have any active long-term drilling rig contracts in place. These agreements typically include renewal options at the end of the initial term. Due to the nature of the Company's drilling schedules and potential volatility in commodity prices, the Company is unable to determine at contract commencement with reasonable certainty if the renewal options will be exercised; therefore, renewal options are not considered in the lease term for drilling contracts. The operating lease liabilities associated with these rig commitments, when applicable, are based on the minimum contractual obligations, primarily standby rates, and do not include variable amounts based on actual activity in a given period. Pursuant to the full cost method of accounting, these costs are capitalized as part of oil and natural gas properties on the accompanying consolidated balance sheets. A portion of drilling costs are borne by other interest owners in our wells.

Effective October 1, 2014, the Company entered into an Amended and Restated Master Services Agreement for pressure pumping services with Stingray, a subsidiary of Mammoth Energy and a related party. Pursuant to this agreement, as amended effective July 1, 2018, Stingray has agreed to provide hydraulic fracturing, stimulation and related completion and rework services to the Company through 2021 and the Company has agreed to pay Stingray a monthly service fee plus the associated costs of the services provided. As discussed further in Note 18, the Company terminated the Master Services Agreement for pressure pumping with Stingray. As a result, in the first quarter of 2020, Gulfport removed the related right of use assets and lease liabilities associated with the terminated contract.

The Company rents office space for its field locations and certain other equipment from third parties, which expire at various dates through 2024. These agreements are typically structured with non-cancelable terms of one to five years. The Company has determined these agreements represent operating leases with a lease term that equals the primary non-cancelable contract term. The Company has included any renewal options that it has determined are reasonably certain of exercise in the determination of the lease terms.

As of December 31, 2020, all lease liabilities have been classified as liabilities subject to compromise in the accompanying consolidated balance sheet.

Discount Rate

As most of the Company's leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The Company's

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~~11.~~			~~INCOME TAXES~~

incremental borrowing rate reflects the estimated rate of interest that it would pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment.

Future amounts due under operating lease liabilities as of December 31, 2020 were as follows:


	(In thousands)
2021	$	129
2022	115
2023	90
2024	30
Total lease payments	364
Less: Imputed interest	(22)
Less: amounts reclassified to liabilities subject to compromise	(342)
Total lease liabilities	$	0

Lease costs incurred for the years ended December 31, 2020 and 2019 consisted of the following:


	For the Year Ended December 31,
	2020		2019
	(In thousands)
Operating lease cost	$	9,658	$	24,960
Operating lease cost - related party	0		22,440
Variable lease cost	586		2,172
Variable lease cost - related party	0		66,924
Short-term lease cost	9,361		834
Total lease cost(1)	$	19,605	$	117,330

_____________________

(1) The majority of the Company's total lease cost was capitalized to the full cost pool, and the remainder was included in general and administrative expenses in the accompanying consolidated statements of operations.

Supplemental cash flow information for the years ended December 31, 2020 and 2019 related to leases was as follows:



	For the Year Ended December 31,
	2020	2019
Cash paid for amounts included in the measurement of lease liabilities	(In thousands)
Operating cash flows from operating leases	140	182
Investing cash flow from operating leases	10,272	24,263
Investing cash flow from operating leases - related party	6,800	84,750

The weighted-average remaining lease term as of December 31, 2020 was 3.03 years. The weighted-average discount rate used to determine the operating lease liability as of December 31, 2020 was 4.22%.

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11.INCOME TAXES

The income tax provision consists of the following:


	2018			2017			2016				2020		2019		2018
	(In thousands)										(In thousands)
Current:										Current:
State	$	(1,530	)	$	2,167		$	(1,330	)	State	$	0	$	0	$	(1,530)
Federal	253			3,362			(19,771		)	Federal	(273)		(7)		253
Deferred:										Deferred:
State	1,530			(118		)	(386		)	State	7,563		(7,556)		1,530
Federal	(322		)	(3,602		)	18,574			Federal	0		0		(322)
Total income tax (benefit) expense provision	$	(69	)	$	1,809		$	(2,913	)
Total income tax expense (benefit) provision										Total income tax expense (benefit) provision	$	7,290	$	(7,563)	$	(69)

A reconciliation of the statutory federal income tax amount to the recorded expense follows:


	2020		2019		2018
	(In thousands)
(Loss) income before federal income taxes	$	(1,617,843)	$	(2,009,921)	$	430,491
Expected income tax at statutory rate	(339,747)		(422,083)		90,403
State income taxes	(14,696)		(28,316)		(511)
Other differences	10,800		3,372		1,078


Change in valuation allowance due to current year activity	350,933		439,464		(91,039)

Income tax expense (benefit) recorded	$	7,290	$	(7,563)	$	(69)

~~F-28~~

Table of Contents

Index to Financial ~~Statements~~Statement s

2018 2017 2016
(In thousands)
Income (loss) before federal income taxes $ 430,491
$ 436,961
$ (982,622 )
Expected income tax at statutory rate 90,403
152,936
(343,918 )
State income taxes (511 ) 2,299
(5,883 )
Other differences 1,078
5,731
4,293
Intraperiod tax allocation —
—
(1,349 )
Remeasurement due to Tax Cut and Jobs Act —
190,034
—
Change in valuation allowance due to current year activity (91,039 ) (158,704 ) 343,944
Change in valuation allowance due to Tax Cuts and Jobs Act —
(190,487 ) —
Income tax (benefit) expense recorded $ (69 ) $ 1,809
$ (2,913 )

The tax effects of temporary differences and net operating loss carryforwards, which give rise to deferred tax assets and liabilities at December 31, ~~2018, 2017~~2020, 2019 and ~~2016~~2018 are estimated as follows:


	2020		2019		2018
	(In thousands)
Deferred tax assets:
Net operating loss carryforward	$	392,318	$	269,851	$	164,363
Oil and gas property basis difference	463,705		289,850		3,595
Investment in pass through entities	61,078		58,951		8,620
Stock-based compensation expense	1,223		1,440		616
Business energy investment tax credit	370		370		369

Charitable contributions carryover	318		297		269
Change in fair value of derivative instruments	7,656		11,219		2,761
Foreign tax credit carryforwards	523		943		2,009
Accrued liabilities	868		669		834
ARO liability	13,414		12,744		16,923
Non-oil and gas property basis difference	0		0		104
Lease liability	72		12,128		0
Reorganization items	25,714		0		0
State net operating loss carryover	22,191		13,258		11,526
Interest expense carryforward	0		23,818		0
Total deferred tax assets	989,450		695,538		211,989
Valuation allowance for deferred tax assets	(985,528)		(647,575)		(211,987)
Deferred tax assets, net of valuation allowance	3,922		47,963		2
Deferred tax liabilities:
Non-oil and gas property basis difference	575		1,859		0

Change in fair value of derivative instruments	3,272		26,410		2
Right of use asset	72		12,128		0
Other	3		3		0
Total deferred tax liabilities	3,922		40,400		2
Net deferred tax asset	$	0	$	7,563	$	0

2018 2017 2016
(In thousands)
Deferred tax assets:
Net operating loss carryforward $ 164,363
$ 120,626
$ 162,073
Oil and gas property basis difference 3,595
151,260
386,302
Investment in pass through entities 8,620
12,343
27,469
Stock-based compensation expense 616
813
2,084
Business energy investment tax credit 369
369
369
AMT credit —
—
3,842
Charitable contributions carryover 269
255
303
Change in fair value of derivative instruments 2,761
—
48,317
Foreign tax credit carryforwards 2,009
2,074
2,074
Accrued liabilities 834
285
397
ARO liability 16,923
15,897
12,107
Non-oil and gas property basis difference 104
171
—
State net operating loss carryover 11,526
6,954
5,351
Total deferred tax assets 211,989
311,047
650,688
Valuation allowance for deferred tax assets (211,987 ) (298,830 ) (645,841 )
Deferred tax assets, net of valuation allowance 2
12,217
4,847
Deferred tax liabilities:
Non-oil and gas property basis difference —
—
155
Change in fair value of derivative instruments 2
11,009
—
Total deferred tax liabilities 2
11,009
155
Net deferred tax asset $ —
$ 1,208
$ 4,692
The company recognized income tax expense of $7.3 million in 2020 and an income tax benefit of $7.6 million in 2019. The net change is primarily related to the recognition of the valuation allowance against the Oklahoma state tax deferred asset that was not realized as a result of the Oklahoma water asset sale as previously expected.

The Company has an available federal tax net operating loss carryforward estimated at approximately $1.9 billion as of December 31, 2020. These federal net operating loss carryforwards generated in tax years prior to 2018 will begin to expire in 2023. As a result of the Tax Cuts and Jobs Act, the 2018 through 2020 federal NOL carryforwards have no expiration. The Company also has state net operating loss carryovers of $441.0 million that began to expire in 2019 and federal foreign tax credit carryovers of $0.5 million that will expire in 2021.

At each reporting period, the Company weighs all available positive and negative evidence to determine whether its deferred tax assets are more likely than not to be realized. As a result of this analysis at December 31, 2020, the Company determined a valuation allowance was necessary with respect to its net deferred tax assets totaling $985.5 million.

There was an increase of $338.0 million, an increase of $439.5 million and a decrease of $86.8 million to the valuation allowance ~~of $86.8 million~~during 2020, 2019 and ~~$347.0 million during~~ 2018, ~~and 2017, respectively, and an~~respectively. The increase toin the valuation allowance ~~of $342.6 million during 2016.~~in 2020 and 2019 was primarily due to increases in net deferred tax assets from pre-tax losses resulting from impairments in the Company's oil and natural gas properties. The decrease in the valuation allowance in 2018 was primarily due to decreases in net deferred tax assets due to ~~pretax~~pre-tax income. The decrease in the valuation allowance in 2017 was primarily due to decreases in net deferred tax assets due to pretax income and remeasurement of deferred tax assets due to the Tax Cuts and Jobs Act. The increase in the valuation allowance in 2016 was primarily due to increases in deferred tax assets from pre-tax losses resulting from impairments to the full cost pool.,

~~F-29~~

Table of Contents

Index to Financial ~~Statements~~Statement s

~~As December 31, 2018,~~On March 27, 2020, the ~~Company maintains full valuation allowances related~~CARES Act was enacted in response to the ~~total net~~COVID-19 pandemic. The Act includes several significant provisions for corporations including allowing companies to carryback certain NOLs, increasing the amount of NOLs that corporations can use to offset income, and increasing the amount of deductible interest under section 163(j). The Company does not expect to be materially impacted by the CARES Act provision and does not anticipate the CARES Act to have a material effect on its ability to realized deferred tax assets, as they cannot objectively assert that these deferred tax assets are more likely than not to be realized. It is reasonably possible that a portion of this valuation allowance could be reversed within the next year due to increased book profitability levels. Future provisions for income taxes will include no tax benefits with respect to losses incurred and tax expense only to the extent of current taxes payable until the valuation allowances are eliminated.

All available positive and negative evidence is weighed to determine whether a valuation allowance should be recorded. The more significant evidential matter relates to the Company’s recent cumulative losses resulting from impairments to the full cost pool in 2016. Management currently estimates that pretax income in 2019 will result in the Company emerging from a cumulative loss position in the first quarter of 2019, at which point there may no longer be any significant negative evidence regarding the realizability of deferred tax assets and the determination around the need for a valuation allowance will primarily depend on management’s ability to objectively project sufficient future taxable income exclusive of reversing temporary differences to ensure realization of deferred tax assets. ~~As such, it is reasonably possible that a material change in valuation allowance may be recorded during an interim period for the year ending December 31, 2019.~~

The Company has an available federal tax net operating loss carryforward estimated at approximately $782.7 million as of December 31, 2018. This carryforward will begin to expire in the year 2023. Based upon the December 31, 2018 net deferred tax asset position and a recent history of cumulative losses, management believes that there is sufficient negative evidence to place a valuation allowance on the net deferred tax asset that may not be utilized based upon a more likely than not basis. The Company also has state net operating loss carryovers of $205.7 million that began to expire in 2017 and federal foreign tax credit carryovers of $1.8 million which began to expire in 2017. The Company believes that it can utilize an Oklahoma state NOL through carrybacks. Therefore, the Company has recorded a total valuation allowance of $212.0 million related to the remaining net deferred tax asset.

The Company’s ability to utilize NOL carryforwards and other tax attributes to reduce future federal taxable income is subject to potential limitations under ~~Internal Revenue Code~~ Section 382 ~~(“Section 382”)~~ and its related tax regulations. The utilization of these attributes may be limited if certain ownership changes by 5% ~~stockholders~~shareholders (as defined in Treasury regulations pursuant to Section 382) and the effects of stock issuances by the Company during any three-year period result in a cumulative change or more than 50% in the beneficial ownership of ~~Gulfport. The~~the Company. As of December 31, 2020, the Company ~~is currently conducting~~has completed a Section 382 analysis, ~~to determine if an ownership change has occurred. If it is determined~~which reflects that anno ownership change has occurred ~~under these rules, the Company would generally be subject~~ to ~~an annual limitation on~~further limit the use of ~~pre-ownership change~~ NOL carryforwards ~~and certain~~or other ~~losses and/or credits. In addition, certain future transactions regarding the Company's equity, including the cumulative effects of small transactions as well as transactions~~tax attributes. There are conditions that exist that are beyond the Company’s control which could cause an ownership change in the future and ~~therefore~~create a ~~potential~~significant limitation on the ~~annual utilization~~Company's ability to utilize those tax attributes. On April 30, 2020, the board of ~~their deferred~~directors of the Company adopted a tax ~~assets.~~

benefits preservation plan in order to protect against a possible limitation on the Company’s ability to use its tax net operating losses and certain other tax benefits to reduce potential future U.S. federal income tax obligations. The Tax ~~Act was enacted on December 22, 2017. The Tax Act reduces the US federal corporate tax rate~~Benefits Preservation Plan is intended to prevent against such an ownership change by deterring any person or group from 35% to 21% effective January 1, 2018. Deferred tax assets and liabilities are measured using the enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to reverse. As a resultacquiring beneficial ownership of 4.9% or more of the reduction in the statutory rate, the Company has remeasured its deferred tax balances, the effects of which are reflected in the rate reconciliation shown in the table above. The Company has applied the provisions of SEC Staff Accounting Bulletin No. 118 ("SAB 118"). SAB 118 allows for a measurement period in which companies can either use provisional estimates for changes resulting from the Tax Act or apply the tax laws that were in effect immediately prior to the Tax Act being enacted if estimates cannot be determined at the time of the preparation of the financial statements until the actual impacts can be determined. The Company finalized its accounting for the impact of the Tax Act within its December 31, 2018 financial statements. The net impact of the finalization was immaterial.Company’s securities.

The Company's income tax benefit in 2016 was primarily attributable to the Company recording a full cost ceiling impairment of $715.5 million against the oil and gas assets. The Company's income tax expense in 2017 is primarily the result of a change in state income tax positions.

As of December 31, ~~2018,~~2020, the ~~amount of unrecognized tax benefits related to federal and state tax liabilities~~Company has recorded a liability associated with uncertain tax positions ~~was immaterial.~~of $3.8 million, which is included in liabilities subject to compromise in the accompanying consolidated balance sheet as of December 31, 2020.

12. EARNINGS PER SHARE

~~F-30~~

~~Table of Contents~~

~~Index to Financial Statements~~


~~12.~~	~~EARNINGS PER SHARE~~

Reconciliations of the components of basic and diluted net income per common share are presented in the tables below:


	For the Year Ended December 31,
	2020		2019		2018
	(In thousands, except share data)
Net (loss) income	$	(1,625,133)	$	(2,002,358)	$	430,560
Basic Shares	160,231,335		160,341,125		174,675,840
Basic EPS	$	(10.14)	$	(12.49)	$	2.46
Effect of dilutive securities:
Stock options and awards	0		0		722,866
Dilutive Shares	160,231,335		160,341,125		175,398,706
Dilutive EPS	$	(10.14)	$	(12.49)	$	2.45

For the Year Ended December 31,
2018 2017 2016
Income Shares
Per
Share
Loss Shares
Per
Share
Loss Shares Per Share
(In thousands, except share data)
Basic:
Net income (loss) $ 430,560
174,675,840
$ 2.46
$ 435,152
179,834,146
$ 2.42
$ (979,709 ) 122,952,866
$ (7.97 )
Effect of dilutive securities:

Stock options and awards —
722,866

—
418,878

—
—

Diluted:

Net income (loss) $ 430,560
175,398,706
$ 2.45
$ 435,152
180,253,024
$ 2.41
$ (979,709 ) 122,952,866
$ (7.97 )

There were no0 potential ~~shares of common stock that were considered anti-dilutive for the years ended December 31, 2018 and 2017. There were 539,988~~ shares of common stock that were considered anti-dilutive for the year ended ~~2016.~~December 31, 2020, 3,867,084 shares for the year ended December 31, 2019, and 0 potential shares of common stock that were considered anti-dilutive for the year ended December 31, 2018.

~~F-31~~

~~Table of Contents~~13.DERIVATIVE INSTRUMENTS

~~Index to Financial Statements~~


~~13.~~	~~DERIVATIVE INSTRUMENTS~~

Natural Gas, Oil and Natural Gas Liquids Derivative Instruments

The Company seeks to ~~reduce its exposure~~mitigate risks related to unfavorable changes in natural gas, oil and ~~NGLs~~NGL prices, which are subject to significant and often volatile fluctuation, by entering into over-the-counter fixed price swaps, basis swaps, collars and various types of option contracts. These contracts allow the Company to ~~predict with greater certainty~~mitigate the ~~effective oil,~~impact of declines in future natural gas, oil and ~~NGLs~~NGL prices by effectively locking in floor price for a certain level of the Company’s production. However, these hedge contracts also limit the benefit to ~~be received for hedged production and benefit operating cash flows and earnings~~the Company in periods when the future market prices ~~are less than the fixed prices provided in the contracts. However, the Company will not benefit from market prices~~of natural gas, oil and NGL that are higher than the ~~fixed prices in the contracts for~~ hedged ~~production.~~prices.

Fixed price swaps are settled monthly based on differences between the fixed price specified in the contract and the referenced settlement price. When the referenced settlement price is less than the price specified in the contract, the Company receives an amount from the counterparty based on the price difference multiplied by the volume. Similarly, when the referenced settlement price exceeds the price specified in the contract, the Company pays the counterparty an amount based on

Table of Contents

Index to Financial Statement s

the price difference multiplied by the volume. The prices contained in these fixed price swaps are based on the NYMEX Henry Hub for natural ~~gas and Mont Belvieu for propane, pentane and ethane.~~gas. Below is a summary of the Company's open fixed price swap positions as of December 31, ~~2018.~~

2020.

Location Daily Volume (MMBtu/day)
Weighted
Average Price
2019 NYMEX Henry Hub 1,254,000
$ 2.83
2020 NYMEX Henry Hub 204,000
$ 2.77


	Index	Daily Volume (MMBtu/day)	Weighted Average Price
2021	NYMEX Henry Hub	410,000	$	2.75

The Company entered into costless collars based off the NYMEX Henry Hub natural gas index. Each two-way price collar has a set floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, the Company will cash-settle the difference with the counterparty.

Location Daily Volume (Bbls/day)
Weighted
Average Price
2019 Mont Belvieu C2 1,000
$ 18.48
2019 Mont Belvieu C3 4,000
$ 28.87
2019 Mont Belvieu C5 500
$ 54.08

Index

Daily Volume (MMBtu/day)

Weighted Average Floor/Ceiling Price

2021

NYMEX Henry Hub

250,000

$2.46/$2.81

2022

NYMEX Henry Hub

20,000

$2.80/$3.40

~~During~~In the ~~fourth~~third quarter of ~~2018,~~2019, the Company early terminated all of its fixed price swaps for oil based on both Argus Louisiana Light Sweet Crude and NYMEX West Texas Intermediate scheduled to settle during 2019 covering 5,000 Bbls/day. These early terminations resulted in approximately $0.4 million of settlement losses which are included in net (loss) gain on natural gas, oil, and NGL derivatives in the accompanying consolidated statement of operations.

~~The~~ Company sold call options in exchange for a premium, and used the associated premiums received to enhance the fixed price for a portion of the fixed price natural gas swaps ~~listed above.~~primarily for 2020. Each short call option has an established ceiling price. When the referenced settlement price is above the price ceiling established by these short call options, the Company pays its counterparty an amount equal to the difference between the referenced settlement price and the price ceiling multiplied by the hedged contract volumes.

Location Daily Volume (MMBtu/day)
Weighted
Average Price
January 2019 - March 2019 NYMEX Henry Hub 50,000
$ 3.13
April 2019 - December 2019 NYMEX Henry Hub 30,000
$ 3.10

For a portion of the natural gas fixed price swaps listed above, the counterparties had the option to extend the original terms an additional twelve months for the period January 2019 through December 2019. In December 2018, the counterparties chose to exercise all natural gas fixed price swaps, resulting in an additional 100,000 MMBtu per day at a weighted average price of $3.05 per MMBtu, which is included in the natural gas fixed price swaps listed above.


	Index	Daily Volume (MMBtu/day)	Weighted Average Price
2022	NYMEX Henry Hub	153,000	$	2.90
2023	NYMEX Henry Hub	628,000	$	2.90

In addition, the Company ~~has~~ entered into natural gas basis swap ~~positions, which settle on the pricing index to basis differential of Transco Zone 4 to NYMEX Henry Hub.~~positions. As of December 31, ~~2018,~~2020, the Company had the following natural gas basis swap positions open:


	Gulfport Pays	Gulfport Receives	Daily Volume (MMBtu/day)	Weighted Average Fixed Spread
2021	Rex Zone 3	NYMEX Plus Fixed Spread	35,000	$	(0.21)
2021	Tetco M2	NYMEX Plus Fixed Spread	60,000	$	(0.67)

Contingent Consideration Arrangement

The purchase and sale agreement for ~~Transco Zone 4.~~the sale of the Company's non-core assets located in the WCBB and Hackberry fields of Louisiana included a contingent consideration arrangement that entitles the Company to receive bonus payments if commodity prices exceed specified thresholds. The calculated fair value of this contingent payment arrangement was approximately $1.1 million as of the closing date of the divestiture. See below for threshold and potential payment amounts.

Period

Threshold(1)

Payment to be received(2)

January 2021 - June 2021

Greater than or equal to $60.65

150,000

Between $52.62 - $60.65

Calculated Value(3)

Less than or equal to $52.62

_____________________

(1) Based on the "WTI NYMEX + Argus LLS Differential," as published by Argus Media.

(2) Payment will be assessed monthly from July 2020 through June 2021. If threshold is met, payment shall be received within five business days after the end of each calendar month.

(3) If average daily price, as defined in (1), is greater than $52.62 but less than $60.65, payment received will be $150,000 multiplied by a fraction, the numerator of which is the amount determined by subtracting $52.62 from such average daily price, and the denominator of which is $8.03.

~~F-32~~

Table of Contents

Index to Financial ~~Statements~~Statement

Location Daily Volume (MMBtu/day) Hedged Differential
2019 Transco Zone 4 60,000
$ (0.05 )
2020 Transco Zone 4 60,000
$ (0.05 )

Balance sheet presentation

The Company reports the fair value of derivative instruments on the consolidated balance sheets as derivative instruments under current assets, noncurrent assets, current liabilities, and noncurrent liabilities on a gross basis. The Company determines the current and noncurrent classification based on the timing of expected future cash flows of individual trades. The following table presents the fair value of the Company's derivative instruments on a gross basis at December 31, ~~2018~~2020 and ~~2017:~~

2019:

December 31,
2018 2017
(In thousands)
Short-term derivative instruments - asset $ 21,352
$ 78,847
Long-term derivative instruments - asset $ —
$ 8,685
Short-term derivative instruments - liability $ 20,401
$ 32,534
Long-term derivative instruments - liability $ 13,992
$ 2,989


	December 31,
	2020		2019
	(In thousands)
Commodity derivative instruments	$	27,146	$	125,383
Contingent consideration arrangement	0		818
Total short-term derivative instruments – asset	$	27,146	$	126,201

Commodity derivative instruments	322		0
Contingent consideration arrangement	0		563
Total long-term derivative instruments – asset	$	322	$	563

Total short-term derivative instruments – liability	$	11,641	$	303

Total long-term derivative instruments – liability	$	36,604	$	53,135

Gains and losses

The following table presents the gain and loss recognized in net gain (loss) ~~gain~~ on natural gas, oil and NGL derivatives in the accompanying consolidated statements of operations for the years ended December 31, ~~2018, 2017,~~2020, 2019, and ~~2016.~~

2018.

Net (loss) gain on derivative instruments
For the Year Ended December 31,
2018 2017 2016
(In thousands)
Natural gas derivatives $ (116,130 ) $ 232,143
$ (165,933 )
Oil derivatives (13,084 ) (3,350 ) (5,387 )
Natural gas liquids derivatives 5,735
(15,114 ) (3,186 )
Total $ (123,479 ) $ 213,679
$ (174,506 )

~~The Company delivered approximately 78% of its 2018 production under fixed price swaps.~~


	Net gain (loss) on derivative instruments
	For the Year Ended December 31,
	2020		2019		2018
	(In thousands)
Natural gas derivatives	$	23,765	$	194,450	$	(116,130)
Oil derivatives	43,510		7,035		(13,084)
NGL derivatives	(603)		6,632		5,735
Contingent consideration arrangement	(1,381)		243		0
Total	$	65,291	$	208,360	$	(123,479)

Offsetting of derivative assets and liabilities

As noted above, the Company records the fair value of derivative instruments on a gross basis. The following table presents the gross amounts of recognized derivative assets and liabilities in the consolidated balance sheets and the amounts that are subject to offsetting under master netting arrangements with counterparties, all at fair value.


	As of December 31, 2018										As of December 31, 2020
	Derivative instruments, gross			Netting adjustments			Derivative instruments, net				Derivative instruments, gross		Netting adjustments		Derivative instruments, net
	(In thousands)										(In thousands)
Derivative assets	$	21,352		$	(19,289	)	$	2,063		Derivative assets	$	27,468	$	(25,730)	$	1,738
Derivative liabilities	$	(34,393	)	$	19,289		$	(15,104	)	Derivative liabilities	$	(48,245)	$	25,730	$	(22,515)

~~F-33~~

Table of Contents

Index to Financial ~~Statements~~Statement

As of December 31, 2017
Derivative instruments, gross Netting adjustments Derivative instruments, net
(In thousands)
Derivative assets $ 87,532
$ (22,199 ) $ 65,333
Derivative liabilities $ (35,523 ) $ 22,199
$ (13,324 )

~~Concentration of Credit Risk~~

By using derivative instruments that are not traded on an exchange, the Company is exposed to the credit risk of its counterparties. Credit risk is the risk of loss from counterparties not performing under the terms of the derivative instrument. When the fair value of a derivative instrument is positive, the counterparty is expected to owe the Company, which creates credit risk. To minimize the credit risk in derivative instruments, it is the Company's policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The Company's derivative contracts are with multiple counterparties to lessen its exposure to any individual counterparty. Additionally, the Company uses master netting agreements to minimize credit risk exposure. The creditworthiness of the Company's counterparties is subject to periodic review. None of the Company's derivative instrument contracts contain credit-risk related contingent features. Other than as provided by the Company's revolving credit facility, the Company is not required to provide credit support or collateral to any of its counterparties under its derivative instruments, nor are the counterparties required to provide credit support to the Company.


~~14.~~			~~FAIR VALUE MEASUREMENTS~~

The Company records certain financial and non-financial assets and liabilities on the balance sheet at fair value. Fair value is the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. Market or observable inputs are the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. Fair value measurements are classified and disclosed in one of the following categories:

~~Level 1 – Quoted prices in active markets for identical assets and liabilities.~~

Level 2 – Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active and model-derived valuations whose inputs are observable or whose significant value drivers are observable.

~~Level 3 – Significant inputs to the valuation model are unobservable.~~

Valuation techniques that maximize the use of observable inputs are favored. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. Reclassifications of fair value between Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter.

~~The following tables summarize the Company’s financial and non-financial liabilities by valuation level as of December 31, 2018 and 2017:~~

December 31, 2018
Level 1 Level 2 Level 3
(In thousands)
Assets:
Derivative Instruments

$ —
$ 21,352
$ —
Liabilities:
Derivative Instruments

$ —
$ 34,393
$ —

~~F-34~~

~~Table of Contents~~

~~Index to Financial Statements~~

December 31, 2017
Level 1 Level 2 Level 3
(In thousands)
Assets:
Derivative Instruments $ —
$ 87,532
$ —
Liabilities:
Derivative Instruments
$ —
$ 35,523
$ —

The Company estimates the fair value of all derivative instruments using industry-standard models that considered various assumptions including current market and contractual prices for the underlying instruments, implied volatility, time value, nonperformance risk, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be supported by observable data.

The estimated fair values of proved oil and gas properties assumed in business combinations are based on a discounted cash flow model and market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and risk-adjusted discount rates. The estimated fair values of unevaluated oil and gas properties was based on geological studies, historical well performance, location and applicable mineral lease terms. Based on the unobservable nature of certain of the inputs, the estimated fair value of the oil and gas properties assumed is deemed to use Level 3 inputs. The asset retirement obligations assumed as part of the business combination were estimated using the same assumptions and methodology as described below. See Note 2 for further discussion of the Company's acquisitions.

The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Given the unobservable nature of the inputs, including plugging costs and reserve lives, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. See Note 3 for further discussion of the Company’s asset retirement obligations. Asset retirement obligations incurred and downward revisions recognized during the year ended December 31, 2018 were approximately $1.8 million and $0.4 million, respectively.

The fair value of the common stock received from Mammoth Energy in connection with the Company’s contribution of all of its membership interests in Sturgeon, Stingray Energy and Stingray Cementing was estimated using Level 1 inputs, as the price per share was a quoted price in an active market for identical Mammoth Energy common shares.

Due to the unobservable nature of the inputs, the fair value of the Company's investment in Grizzly was estimated using assumptions that represent Level 3 inputs. The Company estimated the fair value of the investment as of March 31, 2016 to be approximately $39.1 million. See Note 4 for further discussion of the Company's investment in Grizzly.


~~15.~~	~~RELATED PARTY TRANSACTIONS~~

~~In the ordinary course of business, the Company has conducted business activities with certain related parties.~~

Stingray Cementing provides well cementing services. Stingray Cementing was previously 50% owned by the Company until its contribution to Mammoth Energy in June 2017 as discussed above in Note 4. At the date of the contribution, the Company owed Stingray Cementing approximately $0.5 million.

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. Stingray Energy was previously 50% owned by the Company until its contribution to Mammoth Energy in June 2017 as discussed above in Note 4. At the date of the contribution, the Company owed Stingray Energy approximately $1.6 million.

As of December 31, 2018, the Company held approximately 21.9% of Mammoth Energy's outstanding common stock as discussed above in Note 4. Approximately $2.0 million and $2.1 million of services provided by Mammoth Energy are included in lease operating expenses in the consolidated statements of operations for the years ended December 31, 2018 and 2017, respectively. Approximately $139.7 million and $196.5 million of services provided by Mammoth Energy are included in oil and natural gas properties before elimination of intercompany profits on the accompanying consolidated balance sheets at

~~F-35~~

~~Table of Contents~~

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	As of December 31, 2019
	Derivative instruments, gross		Netting adjustments		Derivative instruments, net
	(In thousands)
Derivative assets	$	126,764	$	(53,438)	$	73,326
Derivative liabilities	$	(53,438)	$	53,438	$	0

~~December 31, 2018 and 2017, respectively. At December 31, 2018 and 2017, the Company owed Mammoth Energy approximately $10.9 million and $32.0 million, respectively, related to these services.~~

The Company previously held a 25% interest in Strike Force, who develops natural gas gathering assets in dedicated areas. In May 2018, the Company sold its interest in Strike Force as discussed above in Note 4. At December 31, 2017, the Company owed approximately $8.4 million to Strike Force for these related services. Approximately $18.5 million and $23.1 million of services provided by Strike Force are included in midstream gathering and processing on the accompanying consolidated statement of operations for the years ended December 31, 2018 and 2017, respectively.


~~16.~~	~~COMMITMENTS~~

~~Plugging and Abandonment Funds~~

In connection with the Company's acquisition in 1997 of the remaining 50% interest in its WCBB properties, the Company assumed the seller’s (Chevron) obligation to contribute approximately $18,000 per month through March 2004 to a plugging and abandonment trust and the obligation to plug a minimum of 20 wells per year for 20 years commencing March 11, 1997. Beginning in 2009, the Company could access the trust for use in plugging and abandonment charges associated with the property, although it has not yet done so. As of December 31, 2018, the plugging and abandonment trust totaled approximately $3.1 million. At December 31, 2018, the Company had plugged 555 wells at WCBB since it began its plugging program in 1997, which management believes fulfills its current minimum plugging obligation.

~~Contributions to 401(k) Plan~~

Gulfport sponsors a 401(k) and Profit Sharing plan under which eligible employees may contribute up to 100% of their total compensation up to the maximum pre-tax threshold through salary deferrals. Also under the plan, the Company will make a bi-weekly contribution on behalf of each employee equal to at least 3% of his or her salary, regardless of the employee’s participation in salary deferrals and may also make additional discretionary contributions. During the years ended December 31, 2018, 2017 and 2016, Gulfport incurred $2.6 million, $3.0 million, and $1.7 million, respectively, in contributions expense related to this plan.

~~Employmentand Separation Agreements~~

The Company was party to an employment agreement with Michael G. Moore, its former Chief Executive Officer and President, which provided for a minimum salary level, subject to review and potential increases by the Compensation Committee and/or the Board of Directors, as well as participation in the Company's incentive plans and other employee benefits. Effective October 29, 2018, Mr. Moore stepped down from his position as the Chief Executive Officer and President of the Company and as a member of its board of directors. In connection with Mr. Moore's departure, the Company entered into a separation and release agreement with Mr. Moore, effective as that date. Under the terms of his separation agreement the Company paid Mr. Moore separation payments in the aggregate amount of $400,000 in December 2018. Also, the Company agreed to reimburse Mr. Moore's portion of COBRA premiums for a maximum of six months, which reimbursement will cease at any time he becomes eligible for group medical coverage from another employer. The separation agreement also includes a release of claims by Mr. Moore against the Company, its directors, stockholders, employees, agents, attorneys, consultants and affiliates.

The Company has also entered into employment agreements with certain members of management that provide for one-year terms commencing as of January 1, 2017 (the “Initial Period”), which automatically extend for successive one-year periods unless the Company or the executive elects to not extend the term by giving written notice to the other party at least 30 days' prior to the end of the Initial Period or any anniversary thereof. The agreements provide for, among other things, compensation, benefits and severance payments. The employment agreements also contains certain termination and change of control provisions.

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~~Firm Transportation and Sales Commitments~~

~~The Company had approximately 2,300,000 MMBtu per day of firm sales contracted with third parties. The table below presents these commitments at December 31, 2018 as follows:~~

(MMBtu per day)
2019 663,000
2020 526,000
2021 372,000
2022 272,000
2023 255,000
Thereafter 212,000
Total 2,300,000

~~The Company also had approximately $3.5 billion of firm transportation contracted with third parties. The table below presents these commitments at December 31, 2018 as follows:~~

(In thousands)
2019 $ 251,644
2020 247,581
2021 246,620
2022 246,620
2023 244,352
Thereafter 2,267,501
Total $ 3,504,318

~~Operating Leases~~

~~The Company leases office facilities under non-cancellable operating leases exceeding one year. Future minimum lease commitments under these leases at December 31, 2018 are as follows:~~

(In thousands)
2019 $ 144
2020 90
2021 37
Total $ 271

~~Presented below is rent expense for the years ended December 31, 2018, 2017 and 2016, respectively.~~

For the years ended December 31,
2018 2017 2016
(In thousands)
Rent expense $ 196

$ 343

$ 840

~~Other Commitments~~

Effective October 1, 2014, the Company entered into a Sand Supply Agreement with Muskie Proppant LLC (“Muskie”), a subsidiary of Mammoth Energy. Effective August 3, 2018, the Company extended the agreement through December 31, 2021.

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Pursuant to this agreement, as amended, the Company has agreed to purchase annual and monthly amounts of proppant sand subject to exceptions specified in the agreement at agreed pricing plus agreed costs and expenses. Failure by either Muskie or the Company to deliver or accept the minimum monthly amount results in damages calculated per ton based on the difference between the monthly obligation amount and the amount actually delivered or accepted, as applicable. The Company incurred $2.2 million related to non-utilization fees during the year ended December 31, 2018. The Company did not incur any non-utilization fees during the year ended 2017.

Effective October 1, 2014, the Company entered into an Amended and Restated Master Services Agreement for pressure pumping services with Stingray Pressure Pumping LLC (“Stingray Pressure”), a subsidiary of Mammoth Energy. Pursuant to this agreement, as amended effective July 1, 2018, Stingray Pressure has agreed to provide hydraulic fracturing, stimulation and related completion and rework services to the Company and the Company has agreed to pay Stingray Pressure a monthly service fee plus the associated costs of the services provided. The Company has the right to suspend services of one crew and only one crew at any point in time without payment, fee or other obligation associated with the suspended crew, given appropriate notification of suspension. See Note 15 for further discussion of amounts paid by the Company to Mammoth Energy.

As of December 31, 2018, the Company has drilling rig contracts with various terms extending to February 2021 to ensure rig availability in its key operating areas. A portion of these future costs will be borne by other interest owners.

~~Future minimum commitments under these agreements at December 31, 2018 are as follows:~~

(In thousands)
2019 $ 89,022
2020 67,203
2021 48,744
Total $ 204,969


~~17.~~	~~CONTINGENCIES~~

In two separate complaints, one filed by the State of Louisiana and the Parish of Cameron in the 38th Judicial District Court for the Parish of Cameron on February 9, 2016 and the other filed by the State of Louisiana and the District Attorney for the 15^th ~~Judicial District of the State of Louisiana in the 15~~^th Judicial District Court for the Parish of Vermilion on July 29, 2016, the Company was named as a defendant, among 26 oil and gas companies, in the Cameron Parish complaint and among more than 40 oil and gas companies in the Vermilion Parish complaint, or the Complaints. The Complaints were filed under the State and Local Coastal Resources Management Act of 1978, as amended, and the rules, regulations, orders and ordinances adopted thereunder, which the Company referred to collectively as the CZM Laws, and allege that certain of the defendants’ oil and gas exploration, production and transportation operations associated with the development of the East Hackberry and West Hackberry oil and gas fields, in the case of the Cameron Parish complaint, and the Tigre Lagoon and Lac Blanc oil and gas fields, in the case of the Vermilion Parish complaint, were conducted in violation of the CZM Laws. The Complaints allege that such activities caused substantial damage to land and waterbodies located in the coastal zone of the relevant Parish, including due to defendants’ design, construction and use of waste pits and the alleged failure to properly close the waste pits and to clear, re-vegetate, detoxify and return the property affected to its original condition, as well as the defendants’ alleged discharge of waste into the coastal zone. The Complaints also allege that the defendants’ oil and gas activities have resulted in the dredging of numerous canals, which had a direct and significant impact on the state coastal waters within the relevant Parish and that the defendants, among other things, failed to design, construct and maintain these canals using the best practical techniques to prevent bank slumping, erosion and saltwater intrusion and to minimize the potential for inland movement of storm-generated surges, which activities allegedly have resulted in the erosion of marshes and the degradation of terrestrial and aquatic life therein. The Complaints also allege that the defendants failed to re-vegetate, refill, clean, detoxify and otherwise restore these canals to their original condition. In these two petitions, the plaintiffs seek damages and other appropriate relief under the CZM Laws, including the payment of costs necessary to clear, re-vegetate, detoxify and otherwise restore the affected coastal zone of the relevant Parish to its original condition, actual restoration of such coastal zone to its original condition, and the payment of reasonable attorney fees and legal expenses and pre-judgment and post judgment interest.

The Company was served with the Cameron complaint in early May 2016 and with the Vermilion complaint in early September 2016. The Louisiana Attorney General and the Louisiana Department of Natural Resources intervened in both the

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Cameron Parish suit and the Vermilion Parish suit. Shortly after the Complaints were filed, certain defendants removed the cases to the United States District Court for the Western District of Louisiana. In both cases, the plaintiffs filed motions to remand the lawsuits to state court, which were ultimately granted by the district courts. However, on May 23, 2018, a group of defendants again removed the Cameron Parish and Vermilion Parish lawsuits to federal court. In response, the plaintiffs again filed motions to remand the cases to state court. The removing defendants have opposed plaintiffs’ motions to remand. On January 16, 2019, the federal district court held a hearing on plaintiffs motion to remand. The court took the matter under advisement and has not yet issued a ruling. Further action in the cases will be stayed until the courts rule on the motions to remand. Also, shortly after the May 23, 2018 removal, the removing defendants filed motions with the United States Judicial Panel on Multidistrict Litigation (the “MDL Panel”) requesting that the Cameron Parish and Vermilion Parish lawsuits be consolidated with 40 similar lawsuits so that pre-trial proceedings in the cases could be coordinated. The MDL Panel denied the motion to consolidate the lawsuits. Due to the procedural posture of the lawsuits, the cases are still in their early stages and the parties have conducted very little discovery. As a result, the Company has not had the opportunity to evaluate the applicability of the allegations made in plaintiffs' complaints to the Company's operations and management cannot determine the amount of loss, if any, that may result.

In addition, due to the nature of the Company's business, it is, from time to time, involved in routine litigation or subject to disputes or claims related to its business activities. While the outcome of the pending litigation, disputes or claims cannot be predicted with certainty, in the opinion of the Company's management, none of these matters, if decided adversely, will have a material adverse effect on its financial condition, cash flows or results of operations.

~~Insurance Proceeds~~

For the years ended December 31, 2018 and 2016 the Company was reimbursed $0.2 million and $5.7 million, respectively, net of related legal fees by its insurance provider, which is included in insurance proceeds in the accompanying consolidated statements of operations. There were no insurance proceeds received in the year ended December 31, 2017.

Concentration of Credit Risk

14.RESTRUCTURING AND LIABILITY MANAGEMENT EXPENSES

In the third quarter of 2020 and fourth quarter of 2019, the Company announced and completed workforce reductions representing approximately 10% and 13%, respectively, of its headcount. Restructuring charges related to the reduction in workforce primarily consisted of one-time employee-related termination benefits. Additionally, the Company incurred charges related to financial and legal advisors engaged to assist with the evaluation of a range of liability management alternatives during 2020 prior to the filing of the Chapter 11 Cases.

The following table summarizes the expenses related to the Company's reductions in workforce as well as expenses incurred related to liability management efforts in the accompanying consolidated statements of operations for the years ended December 31, 2020 and 2019:


	For the Year Ended December 31,
	2020		2019
	(in thousands)
Reduction in workforce	$	1,460	$	4,611
Liability management	29,387		0
Total restructuring and liability management expenses	$	30,847	$	4,611

15.FAIR VALUE MEASUREMENTS

Level 1 – Quoted prices in active markets for identical assets and liabilities.

Level 3 – Significant inputs to the valuation model are unobservable.

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Financial assets and liabilities

The following tables summarize the Company’s financial assets and liabilities by valuation level as of December 31, 2020 and 2019:


	December 31, 2020
	Level 1		Level 2		Level 3
	(In thousands)
Assets:
Derivative Instruments	$	0	$	27,468	$	0
Contingent consideration arrangement	$	0	$	0	$	6,200
Total assets	$	0	$	27,468	$	6,200
Liabilities:
Derivative Instruments	$	0	$	48,245	$	0


	December 31, 2019
	Level 1		Level 2		Level 3
	(In thousands)
Assets:
Derivative Instruments	$	0	$	126,764	$	0
Liabilities:
Derivative Instruments	$	0	$	53,438	$	0

As discussed in Note 3, the water infrastructure sale included a contingent consideration arrangement. As of December 31, 2020, the fair value of the contingent consideration was $6.2 million, of which $1.1 million is included in prepaid expenses and other assets and $5.1 million is included in other assets in the accompanying consolidated balance sheets. The fair value of the contingent consideration arrangement is calculated using discounted cash flow techniques and is based on internal estimates of the Company's future development program and water production levels. Given the unobservable nature of the inputs, the fair value measurement of the contingent consideration arrangement is deemed to use Level 3 inputs. The Company has elected the fair value option for this contingent consideration arrangement and, therefore, records changes in fair value in earnings. As a result of a reduction in the future anticipated contingent consideration since the acquisition date, the Company recognized a loss of $16.6 million on changes in fair value of the contingent consideration during the year ended December 31, 2020, which is included in other expense (income) in the accompanying consolidated statements of operations. Settlements under the contingent consideration arrangement totaled $0.3 million during the year ended December 31, 2020.

Non-financial assets and liabilities

The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Given the unobservable nature of the inputs, including plugging costs and reserve lives, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. See Note 4 for further discussion of the Company’s asset retirement obligations. Asset retirement obligations incurred during the year ended December 31, 2020 were approximately $2.4 million.

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The Company did not record any other than temporary impairments on its equity method investments during the year ended December 31, 2020, however the Company recorded impairments on its investments during the year ended December 31, 2019. Due to the unobservable nature of the inputs, the fair value of the Company's investment in Grizzly as of December 31, 2019 was estimated using assumptions that represent Level 3 inputs. The fair value of the Company's investment in Mammoth Energy as of December 31, 2019 was estimated using Level 1 inputs, as the price per share was a quoted price in an active market for identical Mammoth Energy common shares.

Fair value of other financial instruments

The carrying amounts on the accompanying consolidated balance sheet for cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, and current debt are carried at cost, which approximates market value due to their short-term nature. Long-term debt related to the Company's construction loan is carried at cost, which approximates market value based on the borrowing rates currently available to the Company with similar terms and maturities. See Note 6 for fair value of Company's long-term debt.

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 0 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.

17.COMMITMENTS

Firm Transportation and Gathering Agreements

The Company has contractual commitments with pipeline carriers for future gathering and transportation of natural gas from the Company's producing wells to downstream markets. Under certain of these agreements, the Company has minimum daily volume commitments. The Company is also obligated under certain of these arrangements to pay a demand charge for firm capacity rights on pipeline systems regardless of the amount of pipeline capacity utilized by the Company. If the Company does not utilize the capacity, it often can release it to other counterparties, thus reducing its potential liability. Commitments related to future firm transportation and gathering agreements are not recorded as obligations in the accompanying consolidated balance sheets; however, they are reflected in the Company's estimates of proved reserves.

Additionally, one of the requirements provided for in the RSA is that the Company must permanently reduce its future demand reservation fees owed over the life of all of its firm transportation agreements, taken as a whole, by at least 50% of the amount of all such fees owed on October 31, 2020, as calculated on a PV-10 basis. Additionally, the Company must reduce the future firm transportation demand reservation volumes over the life of all of its firm transportation agreements, taken as a whole, by at least 35%. The below table reflects the Company's obligations as of December 31, 2020 excluding contemplation of contracts to be rejected throughout the Chapter 11 Cases.

A summary of these commitments at December 31, 2020 are set forth in the table below:

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	(In thousands)
2021	$	370,343
2022	380,979
2023	379,171
2024	358,990
2025	272,123
Thereafter	2,013,119
Total	$	3,774,725

Future Sales Commitments

The Company has entered into various firm sales contracts with third parties to deliver and sell natural gas. The Company expects to fulfill its delivery commitments primarily with production from proved developed reserves. The Company's proved reserves have generally been sufficient to satisfy its delivery commitments during the three most recent years, and it expects such reserves will continue to be the primary means of fulfilling its future commitments. However, where the Company's proved reserves are not sufficient to satisfy its delivery commitments, it can and may use spot market purchases of third party production to satisfy these commitments.

A summary of these commitments at December 31, 2020 are set forth in the table below:


			(MMBtu per day)
2021			88,000
2022			58,000
2023			17,000
2024			0
2025			0
Thereafter			0
Total			163,000

Contributions to 401(k) Plan

Gulfport sponsors a 401(k) plan under which eligible employees may contribute a portion of their total compensation up to the maximum pre-tax threshold through salary deferrals. The plan is considered a Safe Harbor 401(k) and provides a company match on 100% of salary deferrals that do not exceed 4% of compensation in addition to a match of 50% of salary deferrals that exceed 4% but do not exceed 6% of compensation. The Company may also make discretionary elective contributions to the plan. During the years ended December 31, 2020, 2019 and 2018, Gulfport incurred $2.6 million, $2.9 million, and $2.6 million, respectively, in contributions expense related to this plan.

18. CONTINGENCIES

Litigation and Regulatory Proceedings

The Company is involved in a number of litigation and regulatory proceedings that may result in material liabilities, including those described below. Many of these proceedings are in early stages, and many of them seek or may seek damages and penalties, the amount of which is indeterminate. The Company's total accrued liabilities in respect of litigation and regulatory proceedings is determined on a case-by-case basis and represents an estimate of probable losses after considering, among other factors, the progress of each case or proceeding, its experience and the experience of others in similar cases or proceedings, and the opinions and views of legal counsel. Significant judgment is required in making these estimates and their final liabilities may ultimately be materially different.

The Company, along with a number of other oil and gas companies, has been named as a defendant in 2 separate complaints, one filed by the State of Louisiana and the Parish of Cameron in the 38th Judicial District Court for the Parish of Cameron on February 9, 2016 and the other filed by the State of Louisiana and the District Attorney for the 15th Judicial District

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of the State of Louisiana in the 15th Judicial District Court for the Parish of Vermilion on July 29, 2016 (together, the "Complaints"). The Complaints allege that certain of the defendants’ operations violated the State and Local Coastal Resources Management Act of 1978, as amended, and the rules, regulations, orders and ordinances adopted thereunder (the "CZM Laws") by causing substantial damage to land and waterbodies located in the coastal zone of the relevant Parish. The plaintiffs seek damages and other appropriate relief under the CZM Laws, including the payment of costs necessary to clear, re-vegetate, detoxify and otherwise restore the affected coastal zone of the relevant Parish to its original condition, actual restoration of such coastal zone to its original condition, and the payment of reasonable attorney fees and legal expenses and interest. The United States District Court for the Western District of Louisiana issued orders remanding the cases to their respective state court, and the defendants have appealed the remand orders to the 5th Circuit Court of Appeals.

In July 2019, Pigeon Land Company, Inc., a successor in interest to certain of the Company's legacy Louisiana properties, filed an action against the Company and a number of other oil and gas companies in the 16th Judicial District Court for the Parish of Iberia in Louisiana. The suit alleged negligence, strict liability and various violations of Louisiana statutes relating to property damage in connection with the historic development of the Company's Louisiana properties and sought unspecified damages (including punitive damages), an injunction to return the affected property to its original condition, and the payment of reasonable attorney fees and legal expenses and interest. This matter was voluntarily dismissed without prejudice on December 8, 2020.

In September 2019, a stockholder of Mammoth Energy filed a derivative action on behalf of Mammoth Energy against members of Mammoth Energy’s board of directors, including a director designated by the Company, and its significant stockholders, including the Company, in the United States District Court for the Western District of Oklahoma. In January 2020, plaintiffs consolidated actions against the same defendants in the United States District Court for the District of Delaware. The consolidated and amended complaint alleges, among other things, that the Company breached its fiduciary duties and misappropriated information as a controlling shareholder of Mammoth Energy in connection with Mammoth Energy’s activities in Puerto Rico following Hurricane Maria and the Company's secondary offering of Mammoth Energy common stock in June 2018. The complaint seeks unspecified damages, the payment of reasonable attorney fees and legal expenses and interest and to force Mammoth Energy and its board of directors to make specified corporate governance reforms.

In October 2019, Kelsie Wagner, in her capacity as trustee of various trusts and on behalf of the trusts and other similarly situated royalty owners, filed an action against us in the District Court of Grady County, Oklahoma. The suit alleged that the Company underpaid royalty owners and seeks unspecified damages for violations of the Oklahoma Production Revenue Standards Act and fraud. This matter is settled in principal and a voluntary dismissal without prejudice is anticipated.

In March 2020, Robert F. Woodley, individually and on behalf of all others similarly situated, filed a federal securities class action against the Company, David M. Wood, Keri Crowell and Quentin R. Hicks in the United States District Court for the Southern District of New York. The complaint alleges that the Company made materially false and misleading statements regarding the Company’s business and operations in violation of the federal securities laws and seeks unspecified damages, the payment of reasonable attorneys’ fees, expert fees and other costs, pre-judgment and post-judgment interest, and such other and further relief that may be deemed just and proper.

In June 2020, Sam L. Carter, derivatively on behalf of the Company, filed an action against certain of our current and former executive officers and directors in the United States District Court for the District of Delaware. The complaint alleged that the defendants breached their fiduciary duties to the Company in connection with certain alleged materially false and misleading statements regarding our business and operations in violation of the federal securities laws. The complaint sought to recover unspecified damages from the defendants, the implementation of specified corporate governance reforms, reasonable attorneys’ and experts’ fees, costs and expenses, and such other relief as may be deemed just and proper. The complaint was voluntarily dismissed without prejudice on October 6, 2020.

The Company filed a lawsuit against Stingray Pressure Pumping LLC, a subsidiary of Mammoth Energy (“Stingray”), for breach of contract and to terminate the Master Services Agreement for pressure pumping services, effective as of October 1, 2014, as amended (the “Master Services Agreement”), between Stingray and the Company. In March 2020, Stingray filed a counterclaim against the Company in the Superior Court of the State of Delaware. The counterclaim alleges that the Company has breached the Master Services Agreement. The counterclaim seeks actual damages, and Stingray filed claims in the Chapter 11 proceedings totaling $43.4 million related to breach of contract damages, attorneys' fees and interest.

In April 2020, Bryon Lefort, individually and on behalf of similarly situated individuals, filed an action against the Company in the United States District Court for the Southern District of Ohio Eastern Division. The complaint alleges that the Company violated the Fair Labor Standards Act (“FLSA”), the Ohio Wage Act and the Ohio Prompt Pay Act by classifying the plaintiffs as independent contractors and paying them a daily rate with no overtime compensation for hours worked in excess of 40 hours per week. The complaint seeks to recover unpaid regular and overtime wages, liquidated damages in an amount equal

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to 6 of all unpaid overtime compensation, the payment of reasonable attorney fees and legal expenses and pre-judgment and post-judgment interest, and such other damages that may be owed to the workers.

In August 2020, Muskie filed an action against the Company in the Superior Court of the State of Delaware for breach of contract. The complaint alleges that the Company breached its obligation to purchase a certain amount of proppant sand each month or make designated shortfall payments under the Sand Supply Agreement, effective October 1, 2014, as amended (the “Sand Supply Agreement”), between Muskie and the Company, and seeks payment of unpaid shortfall payments, and Muskie filed a claim in the Chapter 11 proceedings for $3.4 million.

SEC Investigation

The SEC has commenced an investigation with respect to certain actions by former Company management, including alleged improper personal use of Company assets, and potential violations by former management and the Company of the Sarbanes-Oxley Act of 2002 in connection with such actions. On February 24, 2021, without admitting or denying any of findings contained in the order, Gulfport resolved the SEC investigation through an administrative order that Gulfport violated Sections 13(a), 13(b)(2)(A), 13(b)(2)(B) and 14(a) of the Exchange Act and Rules 12b-20, 13a-1, 14a-3 and 14a-9. Under the administrative order and pursuant to Section 21C of the Exchange Act, Gulfport agreed to cease and desist from committing or causing any violations and any future violations of Sections 13(a), 13(b)(2)(A), 13(b)(2)(B) and 14(a) of the Exchange Act and Rules 12b-20, 13a-1, 14a-3 and 14a-9 thereunder. Based on the company’s extensive cooperation and prompt remedial efforts, the SEC did not impose a monetary penalty.

Business Operations

The Company is involved in various lawsuits and disputes incidental to its business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions.

Environmental Contingencies

The nature of the oil and gas business carries with it certain environmental risks for Gulfport and its subsidiaries. They have implemented various policies, programs, procedures, training and audits to reduce and mitigate such environmental risks. They conduct periodic reviews, on a company-wide basis, to assess changes in their environmental risk profile. Environmental reserves are established for environmental liabilities for which economic losses are probable and reasonably estimable. The Company manages its exposure to environmental liabilities in acquisitions by using an evaluation process that seeks to identify pre-existing contamination or compliance concerns and address the potential liability. Depending on the extent of an identified environmental concern, they may, among other things, exclude a property from the transaction, require the seller to remediate the property to their satisfaction in an acquisition or agree to assume liability for the remediation of the property.

The Company received several Finding of Violation ("FOVs") from the USEPA alleging violations of the Clean Air Act in Ohio. The Company entered into a settlement with the Department of Justice and USEPA agreeing to pay $1.7 million and invest in improvements at 17 well pads. The settlement was filed with the U.S. District Court for the Southern District of Ohio in January 2020 and was fully paid in October 2020.

Other Matters

Based on management’s current assessment, they are of the opinion that no pending or threatened lawsuit or dispute relating to its business operations is likely to have a material adverse effect on their future consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates.

Concentration of Credit Risk

Gulfport operates in the oil and natural gas industry principally in the states of Ohio ~~Oklahoma~~ and ~~Louisiana~~Oklahoma with sales to refineries, re-sellers such as marketers, and other end users. While certain of these customers are affected by periodic downturns in the economy in general or in their specific segment of the oil and gas industry, Gulfport believes that its level of credit-related losses due to such economic fluctuations has been immaterial and will continue to be immaterial to the Company’s results of operations in the long term.

The Company maintains cash balances at several banks. Accounts at each institution are insured by the Federal Deposit Insurance ~~Corporation up to $250,000.~~Corporation. At December 31, ~~2018,~~2020, Gulfport held no cash in excess of insured limits in these ~~banks totaling $50.3 million.~~banks.

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During the year ended December 31, 2020, one customer accounted for approximately 12% of the Company's total sales. During the year ended December 31, 2019, one customer accounted for approximately 14% of the Company's total sales. During the year ended December 31, 2018, two customers accounted for approximately 17% and 10% of the Company's total sales. During the year ended December 31, 2017, one customer accounted for approximately 40% of the Company's total sales. During the year ended December 31, 2016, three customers accounted for approximately 59%, 12% and 10% of the Company's total sales. The Company does not believe that the loss of any of these customers would have a material adverse effect on its ~~oil,~~ natural gas, oil and condensate and NGL sales as alternative customers are readily available.


~~18.~~	~~CONDENSED CONSOLIDATING FINANCIAL INFORMATION~~

On April 21, 2015, the Company issued $350.0 million in aggregate principal amount of the 2023 Notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. In connection with the 2023 Notes Offering, the Company and its subsidiary guarantors entered into a registration rights agreement, dated as of April 21, 2015, pursuant to which the Company agreed to file a registration statement with respect to an offer to exchange the 2023 Notes for a new issue of substantially identical debt securities registered under the Securities Act. The exchange offer for the 2023 Notes was completed on October 13, 2015.

On October 14, 2016, the Company issued $650.0 million in aggregate principal amount of the 2024 Notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. The net proceeds from the issuance of the 2024 Notes, together with cash on hand, were used to repurchase or redeem all of the then-outstanding 2020 Notes in October 2016.

19.SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED)

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On December 21, 2016, the Company issued $600.0 million in aggregate principal amount of the 2025 Notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. The Company used the net proceeds from the issuance of the 2025 Notes, together with the net proceeds from the December 2016 underwritten offering of the Company’s common stock and cash on hand, to fund the cash portion of the purchase price for the Vitruvian Acquisition.

In connection with the 2024 Notes Offering and the 2025 Notes Offering, the Company and its subsidiary guarantors entered into two registration rights agreements, pursuant to which the Company agreed to file a registration statement with respect to offers to exchange the 2024 Notes and the 2025 Notes for new issues of substantially identical debt securities registered under the Securities Act. The exchange offers for the 2024 Notes and the 2025 Notes were completed on September 13, 2017.

On October 11, 2017, the Company issued $450.0 million in aggregate principal amount of the 2026 Notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. A portion of the net proceeds from the issuance of the 2026 Notes was used to repay all of the Company's outstanding borrowings under its secured revolving credit facility on October 11, 2017 and the balance was used to fund the remaining outspend related to the Company's 2017 capital development plans.

In connection with the 2026 Notes offering, the Company and its subsidiary guarantors entered into a registration rights agreement pursuant to which the Company agreed to file a registration statement with respect to an offer to exchange the 2026 Notes for a new issue of substantially identical debt securities registered under the Securities Act. On January 18, 2018, the Company filed a registration statement on Form S-4 with respect to an offer to exchange the 2026 Notes for substantially identical debt securities registered under the Securities Act, which registration statement was declared effective by the SEC on February 12, 2018. The exchange offer relating to the 2026 notes closed on March 22, 2018.

The 2023 Notes, the 2024 Notes, the 2025 Notes and the 2026 Notes are guaranteed on a senior unsecured basis by all existing consolidated subsidiaries that guarantee the Company's secured revolving credit facility or certain other debt (the "Guarantors"). The 2023 Notes, the 2024 Notes, the 2025 Notes and the 2026 Notes are not guaranteed by Grizzly Holdings, Inc. (the "Non-Guarantor"). The Guarantors are 100% owned by Gulfport (the "Parent"), and the guarantees are full, unconditional, joint and several. There are no significant restrictions on the ability of the Parent or the Guarantors to obtain funds from each other in the form of a dividend or loan.

The following condensed consolidating balance sheets, statements of operations, statements of comprehensive (loss) income and statements of cash flows are provided for the Parent, the Guarantors and the Non-Guarantor and include the consolidating adjustments and eliminations necessary to arrive at the information for the Company on a condensed consolidated basis. The information has been presented using the equity method of accounting for the Parent's ownership of the Guarantors and the Non-Guarantor.

~~F-40~~

~~Table of Contents~~

~~Index to Financial Statements~~

~~CONDENSED CONSOLIDATING BALANCE SHEETS~~

~~(Amounts in thousands)~~

December 31, 2018
Parent Guarantors Non-Guarantor Eliminations Consolidated
Assets
Current assets:
Cash and cash equivalents $ 25,585
$ 26,711
$ 1
$ —
$ 52,297
Accounts receivable - oil and natural gas sales 146,075
64,125
—
—
210,200
Accounts receivable - joint interest and other 16,212
6,285
—
—
22,497
Accounts receivable - intercompany 671,633
319,464
—
(991,097 ) —
Prepaid expenses and other current assets 8,433
2,174
—
—
10,607
Short-term derivative instruments 21,352
—
—
—
21,352
Total current assets 889,290
418,759
1
(991,097 ) 316,953
Property and equipment:
Oil and natural gas properties, full-cost accounting 7,044,550
2,983,015
—
(729 ) 10,026,836
Other property and equipment 91,916
751
—
—
92,667
Accumulated depletion, depreciation, amortization and impairment (4,640,059 ) (39 ) —
—
(4,640,098 )
Property and equipment, net 2,496,407
2,983,727
—
(729 ) 5,479,405
Other assets:
Equity investments and investments in subsidiaries 2,856,988
—
44,259
(2,665,126 ) 236,121
Inventories 3,620
1,134
—
—
4,754
Other assets 12,624
1,178
—
1
13,803
Total other assets 2,873,232
2,312
44,259
(2,665,125 ) 254,678
Total assets $ 6,258,929
$ 3,404,798
$ 44,260
$ (3,656,951 ) $ 6,051,036

Liabilities and stockholders' equity
Current liabilities:
Accounts payable and accrued liabilities $ 419,107
$ 99,273
$ —
$ —
$ 518,380
Accounts payable - intercompany 320,259
670,708
130
(991,097 ) —
Short-term derivative instruments 20,401
—
—
—
20,401
Current maturities of long-term debt 651
—
—
—
651
Total current liabilities 760,418
769,981
130
(991,097 ) 539,432
Long-term derivative instruments 13,992
—
—
—
13,992
Asset retirement obligation - long-term 66,859
13,093
—
—
79,952
Deferred tax liability 3,127
—
—
—
3,127
Long-term debt, net of current maturities 2,086,765
—
—
—
2,086,765
Total liabilities 2,931,161
783,074
130
(991,097 ) 2,723,268

Stockholders' equity:
Common stock 1,630
—
—
—
1,630
Paid-in capital 4,227,532
1,915,598
261,626
(2,177,224 ) 4,227,532
Accumulated other comprehensive loss (56,026 ) —
(53,783 ) 53,783
(56,026 )
(Accumulated deficit) retained earnings (845,368 ) 706,126
(163,713 ) (542,413 ) (845,368 )
Total stockholders' equity 3,327,768
2,621,724
44,130
(2,665,854 ) 3,327,768
Total liabilities and stockholders' equity $ 6,258,929
$ 3,404,798
$ 44,260
$ (3,656,951 ) $ 6,051,036

~~F-41~~

~~Table of Contents~~

~~Index to Financial Statements~~

~~CONDENSED CONSOLIDATING BALANCE SHEETS~~

~~(Amounts in thousands)~~

December 31, 2017
Parent Guarantors Non-Guarantor Eliminations Consolidated
Assets
Current assets
Cash and cash equivalents $ 67,908
$ 31,649
$ —
$ —
$ 99,557
Accounts receivable - oil and natural gas 112,686
34,087
—
—
146,773
Accounts receivable - joint interest and other 15,435
20,005
—
—
35,440
Accounts receivable - intercompany 554,439
63,374
—
(617,813 ) —
Prepaid expenses and other current assets 4,719
193
—
—
4,912
Short-term derivative instruments 78,847
—
—
—
78,847
Total current assets 834,034
149,308
—
(617,813 ) 365,529
Property and equipment:
Oil and natural gas properties, full-cost accounting, 6,562,147
2,607,738
—
(729 ) 9,169,156
Other property and equipment 86,711
43
—
—
86,754
Accumulated depletion, depreciation, amortization and impairment (4,153,696 ) (37 ) —
—
(4,153,733 )
Property and equipment, net 2,495,162
2,607,744
—
(729 ) 5,102,177
Other assets:
Equity investments and investments in subsidiaries 2,361,575
77,744
57,641
(2,194,848 ) 302,112
Long-term derivative instruments 8,685
—
—
—
8,685
Deferred tax asset 1,208
—
—
—
1,208
Inventories 5,816
2,411
—
—
8,227
Other assets 12,483
7,331
—
—
19,814
Total other assets 2,389,767
87,486
57,641
(2,194,848 ) 340,046
Total assets $ 5,718,963
$ 2,844,538
$ 57,641
$ (2,813,390 ) $ 5,807,752

Liabilities and stockholders' equity
Current liabilities:
Accounts payable and accrued liabilities $ 416,249
$ 137,361
$ —
$ (1 ) $ 553,609
Accounts payable - intercompany 63,373
554,313
127
(617,813 ) —
Asset retirement obligation - current 120
—
—
—
120
Short-term derivative instruments 32,534
—
—
—
32,534
Current maturities of long-term debt 622
—
—
—
622
Total current liabilities 512,898
691,674
127
(617,814 ) 586,885
Long-term derivative instruments 2,989
—
—
—
2,989
Asset retirement obligation - long-term 63,141
11,839
—
—
74,980
Other non-current liabilities —
2,963
—
—
2,963
Long-term debt, net of current maturities 2,038,321
—
—
—
2,038,321
Total liabilities 2,617,349
706,476
127
(617,814 )
2,706,138

Stockholders' equity:
Common stock 1,831
—
—
—
1,831
Paid-in capital 4,416,250
1,915,598
259,307
(2,174,905 ) 4,416,250
Accumulated other comprehensive loss (40,539 ) —
(38,593 ) 38,593
(40,539 )
(Accumulated deficit) retained earnings (1,275,928 ) 222,464
(163,200 ) (59,264 ) (1,275,928 )
Total stockholders' equity 3,101,614
2,138,062
57,514
(2,195,576 ) 3,101,614
Total liabilities and stockholders' equity $ 5,718,963
$ 2,844,538
$ 57,641
$ (2,813,390 ) $ 5,807,752

~~F-42~~

~~Table of Contents~~

~~Index to Financial Statements~~

~~CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS~~

~~(Amounts in thousands)~~

Year Ended December 31, 2018
Parent Guarantors Non-Guarantor Eliminations Consolidated

Total revenues $ 839,241
$ 515,803
$ —
$ —
$ 1,355,044

Costs and expenses:
Lease operating expenses 66,947
24,693
—
—
91,640
Production taxes 17,140
16,340
—
—
33,480
Midstream gathering and processing expenses 199,607
90,581
—
—
290,188
Depreciation, depletion and amortization 486,661
3
—
—
486,664
General and administrative expenses 59,303
(2,673 ) 3
—
56,633
Accretion expense 3,228
891
—
—
4,119
832,886
129,835
3
—
962,724

INCOME (LOSS) FROM OPERATIONS 6,355
385,968
(3 ) —
392,320

OTHER (INCOME) EXPENSE:
Interest expense 137,894
(2,621 ) —
—
135,273
Interest income (287 ) (27 ) —
—
(314 )
Litigation settlement 1,075
—
—
—
1,075
Insurance proceeds (231 ) —
—
—
(231 )
Gain on sale of equity method investments (28,349 ) (96,419 ) —
—
(124,768 )
(Income) loss from equity method investments and investments in subsidiaries (532,869 ) (694 ) 510
483,149
(49,904 )
Other (income) expense, net (1,369 ) (33 ) —
2,100
698
(424,136 ) (99,794 ) 510
485,249
(38,171 )

INCOME (LOSS) BEFORE INCOME TAXES 430,491
485,762
(513 ) (485,249 ) 430,491
INCOME TAX BENEFIT (69 ) —
—
—
(69 )

NET INCOME (LOSS) $ 430,560
$ 485,762
$ (513 ) $ (485,249 ) $ 430,560

~~F-43~~

~~Table of Contents~~

~~Index to Financial Statements~~

~~CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS~~

~~(Amounts in thousands)~~

Year Ended December 31, 2017
Parent Guarantors Non-Guarantor Eliminations Consolidated

Total revenues $ 1,010,989
$ 309,314
$ —
$ —
$ 1,320,303

Costs and expenses:
Lease operating expenses 65,793
14,453
—
—
80,246
Production taxes 15,100
6,026
—
—
21,126
Midstream gathering and processing expenses 187,678
61,317
—
—
248,995
Depreciation, depletion and amortization 364,625
4
—
—
364,629
General and administrative expenses 55,589
(2,654 ) 3
—
52,938
Accretion expense 1,246
365
—
—
1,611
Acquisition expense —
2,392
—
—
2,392
690,031
81,903
3
—
771,937

INCOME (LOSS) FROM OPERATIONS 320,958
227,411
(3 ) —
548,366

OTHER (INCOME) EXPENSE:
Interest expense 112,732
(4,534 ) —
—
108,198
Interest income (988 ) (21 ) —
—
(1,009 )
Gain on sale of equity method investments (12,523 ) —
—
—
(12,523 )
(Income) loss from equity method investments and investments in subsidiaries (213,607 ) 1,955
2,189
227,243
17,780
Other (income) expense, net (1,617 ) (324 ) —
900
(1,041 )
(116,003 ) (2,924 ) 2,189
228,143
111,405

INCOME (LOSS) BEFORE INCOME TAXES 436,961
230,335
(2,192 ) (228,143 ) 436,961
INCOME TAX EXPENSE 1,809
—
—
—
1,809

NET INCOME (LOSS) $ 435,152
$ 230,335
$ (2,192 ) $ (228,143 ) $ 435,152

~~F-44~~

~~Table of Contents~~

~~Index to Financial Statements~~

~~CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS~~

~~(Amounts in thousands)~~

Year Ended December 31, 2016
Parent Guarantors Non-Guarantor Eliminations Consolidated

Total revenues $ 381,931
$ 3,979
$ —
$ —
$ 385,910

Costs and expenses:
Lease operating expenses 68,034
843
—
—
68,877
Production taxes 13,121
155
—
—
13,276
Midstream gathering and processing expenses 165,400
572
—
—
165,972
Depreciation, depletion and amortization 245,970
4
—
—
245,974
Impairment of oil and natural gas properties 715,495
—
—
—
715,495
General and administrative expenses 43,896
(490 ) 3
—
43,409
Accretion expense 1,057
—
—
—
1,057
1,252,973
1,084
3
—
1,254,060

(LOSS) INCOME FROM OPERATIONS (871,042 ) 2,895
(3 ) —
(868,150 )

OTHER (INCOME) EXPENSE:
Interest expense 63,529
1
—
—
63,530
Interest income (1,230 ) —
—
—
(1,230 )
Insurance proceeds (5,718 ) —
—
—
(5,718 )
Loss on debt extinguishment 23,776
—
—
—
23,776
Gain on sale of equity method investments (3,391 ) —
—
—
(3,391 )
Loss (income) from equity method investments and investments in subsidiaries 34,469
(89 ) 25,150
(22,154 ) 37,376
Other expense (income), net 145
(16 ) —
—
129
111,580
(104 ) 25,150
(22,154 ) 114,472

(LOSS) INCOME BEFORE INCOME TAXES (982,622 ) 2,999
(25,153 ) 22,154
(982,622 )
INCOME TAX BENEFIT (2,913 ) —
—
—
(2,913 )

NET (LOSS) INCOME $ (979,709 )
$ 2,999

$ (25,153 )
$ 22,154

$ (979,709 )

~~F-45~~

~~Table of Contents~~

~~Index to Financial Statements~~

~~CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS)~~

~~(Amounts in thousands)~~

Year Ended December 31, 2018
Parent Guarantors Non-Guarantor Eliminations Consolidated

Net income (loss) $ 430,560
$ 485,762
$ (513 ) $ (485,249 ) $ 430,560
Foreign currency translation adjustment (15,487 ) (297 ) (15,190 ) 15,487
(15,487 )
Other comprehensive loss (income) (15,487 ) (297 ) (15,190 ) 15,487
(15,487 )
Comprehensive income (loss) $ 415,073
$ 485,465
$ (15,703 ) $ (469,762 ) $ 415,073

Year Ended December 31, 2017
Parent Guarantors Non-Guarantor Eliminations Consolidated

Net income (loss) $ 435,152
$ 230,335
$ (2,192 ) $ (228,143 ) $ 435,152
Foreign currency translation adjustment 12,519
182
12,337
(12,519 ) 12,519
Other comprehensive income (loss) 12,519
182
12,337
(12,519 ) 12,519
Comprehensive income (loss) $ 447,671
$ 230,517
$ 10,145
$ (240,662 ) $ 447,671

Year Ended December 31, 2016
Parent Guarantors Non-Guarantor Eliminations Consolidated

Net (loss) income $ (979,709 ) $ 2,999
$ (25,153 ) $ 22,154
$ (979,709 )
Foreign currency translation adjustment 2,119
778
1,341
(2,119 ) $ 2,119
Other comprehensive income (loss) 2,119
778
1,341
(2,119 ) 2,119
Comprehensive (loss) income $ (977,590 ) $ 3,777
$ (23,812 ) $ 20,035
$ (977,590 )

~~F-46~~

~~Table of Contents~~

~~Index to Financial Statements~~

~~CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS~~

~~(Amounts in thousands)~~

Year Ended December 31, 2018
Parent Guarantors Non-Guarantor Eliminations Consolidated

Net cash provided by operating activities $ 543,817
$ 208,670
$ —
$ 1
$ 752,488

Net cash (used in) provided by investing activities (429,483 ) (213,608 ) (2,318 ) 2,318
(643,091 )

Net cash (used in) provided by financing activities (156,657 ) —
2,319
(2,319 ) (156,657 )

Net (decrease) increase in cash and cash equivalents (42,323 ) (4,938 ) 1
—
(47,260 )

Cash and cash equivalents at beginning of period 67,908
31,649
—
—
99,557

Cash and cash equivalents at end of period $ 25,585
$ 26,711
$ 1
$ —
$ 52,297

Year Ended December 31, 2017
Parent Guarantors Non-Guarantor Eliminations Consolidated

Net cash provided by operating activities $ 392,680
$ 287,209
$ —
$ —
$ 679,889

Net cash (used in) provided by investing activities (2,216,615 ) (1,674,690 ) (2,280 ) 1,419,417
(2,474,168 )

Net cash provided by (used in) financing activities 432,961
1,417,137
2,280
(1,419,417 ) 432,961

Net (decrease) increase in cash and cash equivalents (1,390,974 ) 29,656
—
—
(1,361,318 )

Cash and cash equivalents at beginning of period 1,458,882
1,993
—
—
1,460,875

Cash and cash equivalents at end of period $ 67,908
$ 31,649
$ —
$ —
$ 99,557

Year Ended December 31, 2016
Parent Guarantors Non-Guarantor Eliminations Consolidated

Net cash provided by (used in) operating activities $ 336,330
$ (9,486 ) $ (2 ) $ 11,001
$ 337,843

Net cash (used in) provided by investing activities (720,582 ) (22,500 ) (15,472 ) 37,972
(720,582 )

Net cash provided by (used in)financing activities 1,730,640
33,500
15,473
(48,973 ) 1,730,640

Net increase (decrease) in cash and cash equivalents 1,346,388
1,514
(1 ) —
1,347,901

Cash and cash equivalents at beginning of period 112,494
479
1
—
112,974

Cash and cash equivalents at end of period $ 1,458,882
$ 1,993
$ —
$ —
$ 1,460,875

~~F-47~~

~~Table of Contents~~

~~Index to Financial Statements~~


~~19.~~	~~SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED)~~

The Company owns a ~~24.9999%~~24.5% interest in Grizzly. However, Grizzly ~~which interest is shown~~did not have any material activity or proved reserves in the years presented below. As such, amounts related to Grizzly have been omitted below.

The following is historical revenue and cost information relating to the Company’s oil and gas operations located entirely in the United States:

Capitalized Costs Related to Oil and Gas Producing Activities

2018 2017
(In thousands)
Proven properties $ 7,153,799
$ 6,256,182
Unproven properties 2,873,037
2,912,974
10,026,836
9,169,156
Accumulated depreciation, depletion, amortization and impairment reserve (4,613,293 ) (4,136,777 )
Net capitalized costs $ 5,413,543
$ 5,032,379

Equity investment in Grizzly Oil Sands ULC
Proven properties $ 67,475
$ 73,818
Unproven properties 79,605
86,540
147,080
160,358
Accumulated depreciation, depletion, amortization and impairment reserve (1,553 ) (1,693 )
Net capitalized costs $ 145,527
$ 158,665


	2020		2019
	(In thousands)
Proved properties	$	9,359,866	$	8,909,069
Unproved properties	1,457,043		1,686,666
	10,816,909		10,595,735
Accumulated depreciation, depletion, amortization and impairment	(8,778,759)		(7,191,957)
Net capitalized costs	$	2,038,150	$	3,403,778

Costs Incurred in Oil and Gas Property Acquisition and Development Activities


	2020		2019		2018
	(In thousands)
Acquisition	$	15,260	$	37,598	$	119,444
Development	276,622		594,673		714,269
Exploratory	0		9,762		22,081
Total	$	291,882	$	642,033	$	855,794

2018 2017 2016
(In thousands)
Acquisition $ 124,558
$ 1,951,281
$ 152,887
Development 603,676
994,237
423,998
Exploratory 21,840
—
—
Recompletions 7,915
14,289
16,386
Capitalized asset retirement obligation 1,452
42,270
10,971
Total $ 759,441
$ 3,002,077
$ 604,242

Equity investment in Grizzly Oil Sands ULC
Acquisition $ 238
$ 503
$ 357
Development —
—
—
Exploratory —
—
—
Capitalized asset retirement obligation (285 ) (524 ) 784
Total $ (47 ) $ (21 ) $ 1,141

Capitalized interest is included as part of the cost of oil and natural gas properties. The Company capitalized $0.9 million, $3.4 million and $4.5 million during 2020, 2019, 2018, respectively, based on the Company's weighted average cost of borrowings used to finance expenditures.

In addition to capitalized interest, the Company capitalized internal costs totaling $25.0 million, $30.1 million and $37.7 million during 2020, 2019, and 2018, respectively, which were directly related to the acquisition, exploration and development of the Company's oil and natural gas properties.

~~F-48~~

Table of Contents

Index to Financial ~~Statements~~Statement

Results of Operations for Producing Activities

The following schedule sets forth the revenues and expenses related to the production and sale of oil and natural gas. The income tax expense is calculated by applying the current statutory tax rates to the revenues after deducting costs, which include depreciation, depletion and amortization allowances, after giving effect to the permanent differences. The results of operations exclude general office overhead and interest expense attributable to oil and gas production.


	2018			2017			2016				2020		2019		2018
	(In thousands)										(In thousands)
Revenues	$	1,355,044		$	1,320,303		$	385,910		Revenues	$	801,251	$	1,354,766	$	1,675,180
Production costs	(415,308		)	(350,367		)	(248,125		)	Production costs	(537,609)		(620,412)		(611,965)
Depletion	(476,517		)	(358,792		)	(243,098		)	Depletion	(229,702)		(539,379)		(476,517)
Impairment	—			—			(715,495		)	Impairment	(1,357,099)		(2,039,770)		0
	463,219			611,144			(820,808		)
Income tax expense (benefit)
Current	254			3,362			—
Deferred	(322		)	(3,602		)	—
	(68		)	(240		)	—
Income tax (expense) benefit										Income tax (expense) benefit	(7,290)		7,563		68
Results of operations from producing activities	$	463,287		$	611,384		$	(820,808	)	Results of operations from producing activities	$	(1,330,449)	$	(1,837,232)	$	586,766
Depletion per Mcf of gas equivalent (Mcfe)	$	0.96		$	0.90		$	0.92		Depletion per Mcf of gas equivalent (Mcfe)	$	0.61	$	1.08	$	0.96

Results of Operations from equity method investment in Grizzly Oil Sands ULC
Revenues	$	—		$	—		$	—
Production costs	—			—			(13		)
Depletion	—			—			—
	—			—			(13		)
Income tax expense	—			—			—
Results of operations from producing activities	$	—		$	—		$	(13	)

Oil and Natural Gas Reserves

The following table presents estimated volumes of proved developed and undeveloped oil and gas reserves as of December 31, ~~2018, 2017~~2020, 2019 and ~~2016~~2018 and changes in proved reserves during the last three years. The reserve reports use an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month period ended December 31, ~~2018, 2017~~2020, 2019 and ~~2016,~~2018, in accordance with guidelines of the SEC applicable to reserves estimates. ~~Volumes for oil are stated in thousands of barrels (MBbls) and volumes for natural gas are stated in millions of cubic feet (MMcf).~~ The prices used for the ~~2018~~2020 reserve report are ~~$65.56~~$39.54 per barrel of oil, ~~$3.10~~$1.99 per MMbtu and ~~$32.02~~$15.40 per barrel for ~~NGLs,~~NGL, adjusted by lease for transportation fees and regional price differentials, and for oil and gas reserves, respectively. The prices used at December 31, ~~2017~~2019 and ~~2016~~2018 for reserve report purposes are ~~$51.34~~$55.85 per barrel, ~~$2.98~~$2.58 per MMbtu and ~~$18.40~~$21.25 per barrel for ~~NGLs~~NGL and ~~$42.75~~$65.56 per barrel, ~~$2.48~~$3.10 per MMbtu and ~~$9.91~~$32.02 per barrel for ~~NGLs,~~NGL, respectively.

Gulfport emphasizes that the volumes of reserves shown below are estimates which, by their nature, are subject to revision. The estimates are made using all available geological and reservoir data, as well as production performance data. These estimates are reviewed annually and revised, either upward or downward, as warranted by additional performance data.

~~F-49~~100

Table of Contents

Index to Financial ~~Statements~~Statement s


	Oil (MMBbl)	Natural Gas (Bcf)	NGL (MMBbl)	Natural Gas Equivalent (Bcfe)
Proved Reserves
December 31, 2017	19	4,825	76	5,395
Purchases of reserves	0	0	0	0
Extensions and discoveries	5	622	10	711
Sales of reserves	0	(43)	0	(45)
Revisions of prior reserve estimates	0	(827)	1	(821)
Current production	(3)	(444)	(6)	(497)
December 31, 2018	21	4,134	81	4,743
Purchases of reserves	0	0	0	0
Extensions and discoveries	4	997	13	1,097
Sales of reserves	(2)	(63)	0	(77)
Revisions of prior reserve estimates	(2)	(562)	(27)	(734)
Current production	(2)	(458)	(5)	(502)
December 31, 2019	18	4,048	62	4,528
Purchases of reserves	0	0	0	0
Extensions and discoveries	1	216	3	240
Sales of reserves	0	(74)	0	(75)
Revisions of prior reserve estimates	(4)	(1,564)	(23)	(1,725)
Current production	(2)	(345)	(4)	(380)
December 31, 2020	13	2,281	38	2,588
Proved developed reserves
December 31, 2018	10	1,813	41	2,115
December 31, 2019	8	1,757	30	1,984
December 31, 2020	7	1,358	22	1,527
Proved undeveloped reserves
December 31, 2018	11	2,321	40	2,628
December 31, 2019	10	2,291	32	2,544
December 31, 2020	7	923	16	1,061
Totals may not sum or recalculate due to rounding.

In 2020, the Company experienced extensions of 239.8 Bcfe of estimated proved reserves, which were primarily attributable to the Company's continued development of its Utica and SCOOP acreages. Of the total extensions, 150.6 Bcfe was attributable to the addition of 14 PUD locations in the Utica field, 87.8 Bcfe was attributable to the addition of 8 PUD locations in the SCOOP field. The Company experienced total downward revisions of approximately 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. An additional 720.3 Bcfe in downward revisions was a result of the exclusion of 48 PUD locations in the Utica field and 31 PUD locations in the SCOOP field, which was a result of changes in the Company's schedule that moved development of these PUD locations beyond five years of initial booking. The development plan change reflects the Company's commitment to capital discipline, 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.

In 2019, the Company experienced extensions of 1.1 Tcfe of estimated proved reserves, which were primarily attributable to the Company's continued development of its Utica and SCOOP acreages. Of the total extensions, 793.5 Bcfe was attributable to the addition of 72 PUD locations in the Utica field, 302.9 Bcfe was attributable to the addition of 37 PUD locations in the SCOOP field. The Company experienced total downward revisions of approximately 733.8 Bcfe in estimated proved reserves, of which 347.2 Bcfe was a result of the exclusion of 9 PUD locations in the Utica field and 22 PUD locations in the SCOOP

101

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2018 2017 2016
Oil Natural Gas Natural Gas Liquids Oil Natural Gas Natural Gas Liquids Oil Natural Gas Natural Gas Liquids
(MBbls) (MMcf) (MBbls) (MBbls) (MMcf) (MBbls) (MBbls) (MMcf) (MBbls)
Proved Reserves
Beginning of the period 19,157
4,825,310
75,766
5,546
2,167,068
20,127
6,458
1,560,145
17,736
Purchases in oil and natural gas reserves in place —
—
—
15,132
1,098,644
53,617
—
—
—
Extensions and discoveries 5,205
622,271
9,631
951
1,594,734
4,619
1,217
1,082,220
7,677
Sales of oil and natural gas reserves in place (134 ) (43,444 ) (112 ) —
—
—
—
—
—
Revisions of prior reserve estimates (377 ) (826,506 ) 1,228
107
314,925
2,737
(3 ) (247,703 ) (1,439 )
Current production (2,801 ) (443,742 ) (5,993 ) (2,579 ) (350,061 ) (5,334 ) (2,126 ) (227,594 ) (3,847 )
End of period 21,050
4,133,889
80,520
19,157
4,825,310
75,766
5,546
2,167,068
20,127
Proved developed reserves 9,570
1,813,184
40,810
10,245
1,616,930
36,247
4,882
744,797
14,299
Proved undeveloped reserves 11,480
2,320,705
39,710
8,912
3,208,380
39,519
664
1,422,271
5,828

Equity investment in Grizzly Oil Sands ULC
Beginning of the period —
—
—
—
—
—
—
—
—
Purchases in oil and natural gas reserves in place —
—
—
—
—
—
—
—
—
Extensions and discoveries —
—
—
—
—
—
—
—
—
Revisions of prior reserve estimates —
—
—
—
—
—
—
—
—
Current production —
—
—
—
—
—
—
—
—
End of period —
—
—
—
—
—
—
—
—
Proved developed reserves —
—
—
—
—
—
—
—
—
Proved undeveloped reserves —
—
—
—
—
—
—
—
—
field, which was a result of changes in the Company's schedule that moved development of these PUD locations beyond five years of initial booking. The development plan change reflects the Company's commitment capital discipline and funding future activities within cash flow. An additional 296.4 Bcfe in downward revisions was the result of commodity price changes. Commodity prices experienced volatility throughout 2019 and the 12-month average price for natural gas decreased from $3.10 per MMBtu for 2018 to $2.58 per MMBtu for 2019, the 12- month average price for NGL decreased from $32.02 per barrel for 2018 to $21.25 per barrel for 2019, and the 12-month average price for crude oil decreased from $65.56 per barrel for 2018 to $55.85 per barrel for 2019. The Company also experienced downward revisions of 90.2 Bcfe from a combination of working interest changes, optimization of well design in the current commodity price environment and well performance.

In 2018, the Company experienced extensions and discoveries of 711.2 Bcfe of estimated proved reserves, which were primarily attributable to the Company's continued development of its Utica ~~Shale~~ and SCOOP acreages. Of the total extensions and discoveries, 556.3 Bcfe was attributable to the addition of 75 PUD locations in the Utica field, 90.1 Bcfe was attributable to the addition of 11 PUD locations in the SCOOP field and 3.0 Bcfe was attributable to the addition of 13 PUD locations in the Southern Louisiana fields as a result of the Company's current development plan that refocused some activity within existing fields. This change reflects the Company's ongoing efforts to optimize the development program with well selection based on economic returns, commodity mix and surface considerations.

In 2018, the Company experienced downward revisions of 1.0 Tcfe in estimated proved reserves with the exclusion of 127 PUD locations in the Company's Utica field and 12 PUD locations in the Company's SCOOP field, which was primarily the result of changes in the Company's development schedule moving development in excess of five years from initial booking. The development plan change, as approved by the Company's senior management and board of directors, is a result of continued focus on free cash flow generation. This downward revision was partially offset by upward revisions of 82.4 Bcfe in estimated proved reserves in 2018 due to changes in wellbore lateral length, 67.6 Bcfe due to changes in ownership interest, 27.9 Bcfe due to an increase in pricing and 8.3 Bcfe due to changes in well performance. In addition, the Company sold

~~F-50~~

~~Table of Contents~~

~~Index to Financial Statements~~

approximately 44.9 Bcfe of proved undeveloped oil and natural gas reserves associated with various non-operated interests, the majority of which were in the Company's Utica field.

In 2017, the Company purchased 1.5 Tcfe through its acquisition of SCOOP properties discussed in Note 2. Also in 2017, the Company experienced extensions and discoveries of 1.6 Tcfe of estimated proved reserves primarily attributable to the continued development of the Company's Utica Shale acreage. In 2017, the Company experienced upward revisions of 201.3 Bcfe in estimated proved reserves due to an increase in well performance, 214.1 Bcfe due to the increase in pricing and 95.9 Bcfe due to changes in its ownership interests. These positive revisions are partially offset by downward revisions of 133.0 Bcfe due to a decline in well performance specific to one area in the Company's Utica field and a decline of 45.7 Bcfe in estimated proved reserves in 2017 primarily due to the exclusion of ten PUD locations in the Company's Utica field, five of which are operated by the Company and five of which are operated by other operators, that were excluded due to changes in drilling schedules. Additional downward revision of 0.6 Bcfe was due to the removal of two PUD locations in the Company's Southern Louisiana fields that had not been drilled within five years of initial booking.

In 2016, the Company experienced extensions and discoveries of 1.1 Tcfe of estimated proved reserves attributable to the continued development of the Company's Utica Shale acreage. The Company experienced downward revisions of 227.9 Bcfe due to lower commodity prices on 67 PUD locations, including the loss of 35 of the 67 PUD locations as they were no longer economic, as well as downward revisions of 17.4 Bcfe due to rescheduling the drilling timeline of four PUD locations in excess of five years of initial booking resulting in the removal of these four PUD locations. In addition, the Company experienced upward revisions of 26.7 Bcfe attributable to improved performance of 34 PUD locations as a result of 14.5% production increases due to well performance of offset producers as well as lower lease operated and capital expenditures.

Discounted Future Net Cash Flows

The following tables present the estimated future cash flows, and changes therein, from Gulfport’s proven oil and gas reserves as of December 31, ~~2018, 2017~~2020, 2019 and ~~2016~~2018 using an unweighted average first-of-the-month price for the period January through December 31, ~~2018, 2017~~2020, 2019 and ~~2016.~~2018.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves


	Year ended December 31,
	2020		2019		2018
	(In millions)
Future cash flows	$	4,079	$	10,451	$	14,483
Future development and abandonment costs	(652)		(2,058)		(2,438)
Future production costs	(2,325)		(4,513)		(5,068)
Future production taxes	(137)		(333)		(456)
Future income taxes	0		0		(943)
Future net cash flows	965		3,547		5,578
10% discount to reflect timing of cash flows	(425)		(1,844)		(2,596)
Standardized measure of discounted future net cash flows	$	540	$	1,703	$	2,982

102

Year ended December 31,
2018 2017 2016
(In thousands)
Future cash flows $ 14,483,197
$ 11,202,692
$ 3,354,168
Future development and abandonment costs (2,437,853 ) (3,005,217 ) (1,165,025 )
Future production costs (5,067,554 ) (2,152,821 ) (924,167 )
Future production taxes (455,840 ) (289,944 ) (69,447 )
Future income taxes (943,293 ) (573,965 ) (14,545 )
Future net cash flows 5,578,657
5,180,745
1,180,984
10% discount to reflect timing of cash flows (2,595,932 ) (2,537,181 ) (492,944 )
Standardized measure of discounted future net cash flows $ 2,982,725
$ 2,643,564
$ 688,040

Equity investment in Grizzly Oil Sands ULC Standardized measure of discounted cash flows
Future cash flows $ —
$ —
$ —
Future development and abandonment costs —
—
—
Future production costs —
—
—
Future production taxes —
—
—
Future income taxes —
—
—
Future net cash flows —
—
—
10% discount to reflect timing of cash flows

Standardized measure of discounted future net cash flows $ —
$ —
$ —

~~F-51~~

Table of Contents

Index to Financial ~~Statements~~Statement

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves


	Year ended December 31,
	2020		2019		2018
	(In millions)
Sales and transfers of oil and gas produced, net of production costs	$	(264)	$	(734)	$	(1,063)
Net changes in prices, production costs, and development costs	(954)		(1,372)		591
Acquisition of oil and gas reserves in place	0		0		0
Extensions and discoveries	38		388		519
Previously estimated development costs incurred during the period	215		406		402
Revisions of previous quantity estimates, less related production costs	(255)		(321)		(357)
Sales of oil and gas reserves in place	(6)		(49)		(26)
Accretion of discount	170		298		264
Net changes in income taxes	0		425		(185)
Change in production rates and other	(109)		(319)		194
Total change in standardized measure of discounted future net cash flows	$	(1,165)	$	(1,278)	$	339

20.SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

Year ended December 31,
2018 2017 2016
(In thousands)
Sales and transfers of oil and gas produced, net of production costs $ (1,063,215 ) $ (756,257 ) $ (312,291 )
Net changes in prices, production costs, and development costs 590,519
913,714
(146,518 )
Acquisition of oil and gas reserves in place —
703,866
—
Extensions and discoveries 519,137
618,039
186,909
Previously estimated development costs incurred during the period 402,156
390,673
176,218
Revisions of previous quantity estimates, less related production costs (356,933 ) 155,200
(38,448 )
Sales of oil and gas reserves in place (25,882 ) —
—
Accretion of discount 264,356
68,804
76,433
Net changes in income taxes (185,157 ) (231,545 ) (6,495 )
Change in production rates and other 194,180
93,030
(12,099 )
Total change in standardized measure of discounted future net cash flows $ 339,161
$ 1,955,524
$ (76,291 )

Equity investment in Grizzly Oil Sands ULC Changes in standardized measure of discounted cash flows
Sales and transfers of oil and gas produced, net of production costs $ —
$ —
$ —
Net changes in prices, production costs, and development costs —
—
—
Acquisition of oil and gas reserves in place —
—
—
Extensions and discoveries —
—
—
Previously estimated development costs incurred during the period —
—
—
Revisions of previous quantity estimates, less related production costs —
—
—
Accretion of discount —
—
—
Net changes in income taxes —
—
—
Change in production rates and other —
—
—
Total change in standardized measure of discounted future net cash flows $ —
$ —
$ —

~~F-52~~

~~Table of Contents~~

~~Index to Financial Statements~~


~~20.~~	~~SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)~~

The following table summarizes quarterly financial data for the years ended December 31, ~~2018~~2020 and ~~2017:~~2019:


	2020
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(In thousands)
Revenues	$	299,338	$	186,301	$	136,176	$	244,727
(Loss) income from operations	(480,087)		(555,750)		(346,400)		19,632
Income tax expense	7,290		0		0		0
Net loss	(517,538)		(561,068)		(380,963)		(165,564)
Loss per share:
Basic	$	(3.24)	$	(3.51)	$	(2.37)	$	(1.03)
Diluted	$	(3.24)	$	(3.51)	$	(2.37)	$	(1.03)

	2019
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(In thousands)
Revenues	$	372,462	$	512,451	$	341,745	$	336,468
(Loss) income from operations	93,011		218,456		(570,955)		(1,444,205)
Income tax (benefit) expense	0		(179,331)		(144,047)		315,815
Net income (loss)	62,242		234,956		(484,802)		(1,814,754)
Income (loss) per share:
Basic	$	0.38	$	1.47	$	(3.04)	$	(11.36)
Diluted	$	0.38	$	1.47	$	(3.04)	$	(11.36)

2018

First
Quarter

Second
Quarter

Third
Quarter

Fourth
Quarter
(In thousands)
Revenues $ 325,392
$ 252,740
$ 360,962
$ 415,950
Income from operations 110,318
13,791
113,576
154,635
Income tax benefit (69 ) —
—
—
Net income 90,090
111,319
95,150
134,001
Income per share:
Basic $ 0.50
$ 0.64
$ 0.55
$ 0.78
Diluted $ 0.50
$ 0.64
$ 0.55
$ 0.78

2017

First
Quarter

Second
Quarter

Third
Quarter

Fourth
Quarter
(In thousands)
Revenues $ 333,004
$ 323,953
$ 265,498
$ 397,848
Income from operations 181,683
143,175
50,483
173,025
Income tax expense (benefit) —
—
2,763
(954 )
Net income 154,455
105,936
18,235
156,526
Income per share:
Basic $ 0.91
$ 0.58
$ 0.10
$ 0.85
Diluted $ 0.91
$ 0.58
$ 0.10
$ 0.85

103

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21. SUBSEQUENT EVENTS

Subsequent to December 31, 2020 and as of March 1, 2021, the Company entered into the following natural gas, oil, and NGL derivative contracts as it works toward fulfilling minimum hedging requirements as provided for in the RSA:

Period

Type of Derivative Instrument

Index

Daily Volume(1)

Weighted
Average Price

July 2021 - December 2021

Swaps

NYMEX WTI

2,250

$53.07

July 2021 - December 2021

Swaps

Mont Belvieu C3

3,100

$27.80

January 2022 - June 2022

Swaps

Mont Belvieu C3

1,000

$27.30

April 2021 - May 2021

Basis Swaps

Tetco M2

36,443

$(0.61)

February 2021 - October 2021

Basis Swaps

Rex Zone 3

94,505

$(0.22)

July 2021 - December 2021

Costless Collars

NYMEX Henry Hub

210,000

$2.67/$3.15

January 2022 - March 2022

Costless Collars

NYMEX Henry Hub

340,000

$2.82/$3.40

(1) Volume units for gas instruments are presented as MMBtu/day while oil and NGL is presented in Bbls/day.

104

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ITEM 9.			CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.


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 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,

105

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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

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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 (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

Definition and limitations of internal control over financial reporting

/s/ GRANT THORNTON LLP

Oklahoma City, Oklahoma

March 5, 2021

107

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ITEM 9B.			OTHER INFORMATION

Not applicable.

PART III


ITEM 10.			DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The names of executive officers and certain other senior officers of the Company and their ages, titles and biographies as of the date hereof are incorporated by reference from Item 1 of Part I of this report. The other information called for by this Item 10 is incorporated herein by reference to the definitive proxy statement to be filed by Gulfport pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 30, 2021 (the 2021 Proxy Statement).


ITEM 11.			EXECUTIVE COMPENSATION

The information called for by this Item 11 is incorporated herein by reference to the 2021 Proxy Statement.


ITEM 12.			SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information called for by this Item 12 is incorporated herein by reference to the 2021 Proxy Statement.


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.


ITEM 14.			PRINCIPAL ACCOUNTING FEES AND SERVICES

The information called for by this Item 14 is incorporated herein by reference to the 2021 Proxy Statement.

108

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PART IV


ITEM 15.			EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) The following financial statements, financial statement schedules and exhibits are filed as part of this report:

1.Financial Statements. Gulfport's consolidated financial statements are included in Item 8 of Part II of this report. Reference is made to the accompanying Index to Financial Statements.

2.Financial Statement Schedules. No financial statement schedules are applicable or required.

3.Exhibits. The exhibits listed below in the Index of Exhibits are filed, furnished or incorporated by reference pursuant to the requirements of Item 601 of Regulation S-K.


INDEX OF EXHIBITS
		Incorporated by Reference
Exhibit Number	Description	Form	SEC File Number	Exhibit	Filing Date	Filed or Furnished Herewith
3.1	Restated Certificate of Incorporation.	8-K	000-19514	3.1	4/26/2006

3.2	Certificate of Amendment No. 1 to Restated Certificate of Incorporation.	10-Q	000-19514	3.2	11/6/2009

3.3	Certificate of Amendment No. 2 to Restated Certificate of Incorporation.	8-K	000-19514	3.1	7/23/2013

3.4	Second Amended and Restated Bylaws of Gulfport Energy Corporation.	8-K	000-19514	3.1	2/27/2020

3.5	First Amendment to the Second Amended and Restated Bylaws of Gulfport Energy Corporation	8-K	001-19514	3.1	5/29/2020

3.6	Certificate of Designation of Series B Junior Participating Preferred Stock of Gulfport Energy Corporation	8-A	001-19514	3.1	4/30/2020

4.1	Form of Common Stock certificate.	SB-2	333-115396	4.1	7/22/2004

4.2	Indenture, dated as of April 21, 2015, among the Company, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as trustee (including the form of the Company’s 6.625% Senior Notes due 2023).	8-K	000-19514	4.1	4/21/2015

4.3	Indenture, dated as of October 14, 2016, among Gulfport Energy Corporation, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as trustee (including the form of Gulfport Energy Corporation’s 6.000% Senior Notes due 2024).	8-K	000-19514	4.1	10/19/2016

4.4	Indenture, dated as of December 21, 2016, among Gulfport Energy Corporation, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as trustee (including the form of Gulfport Energy Corporation’s 6.375% Senior Notes due 2025).	8-K	000-19514	4.1	12/21/2016

109

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Index to Financial Statement s


4.5	Indenture, dated as of October 11, 2017, among Gulfport Energy Corporation, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as trustee (including the form of Gulfport Energy Corporation’s 6.375% Senior Notes due 2026).	8-K	000-19514	4.1	10/11/2017

4.6	Tax Benefits Preservation Plan, dated as of April 30, 2020, between Gulfport Energy Corporation and Computershare Trust Company, N.A., as rights agent (which includes the Form of Rights Certificate as Exhibit B thereto)	8-A	001-19514	4.1	4/30/2020

10.1+	2019 Amended and Restated Stock Incentive Plan	DEF 14A	000-19514	Appendix A	4/30/19

10.2+	2019 Amended and Restated Stock Incentive Plan Form of Performance Share Award Agreement.	8-K	000-19514	10.3	8/12/19

10.3+	2014 Executive Annual Incentive Compensation Plan.	8-K	000-19514	10.1	4/7/2014

10.4+	Form of Stock Option Agreement.	8-K	000-19514	10.2	4/26/2006

10.5+	Form of Restricted Stock Award Agreement.	10-K	000-19514	10.3	2/28/2014

10.6+	2013 Restated Stock Incentive Plan.	S-4	333-189992	10.1	7/17/2013

10.7+	Gulfport Energy Corporation 2020 Incentive Plan.	8-K	000-19514	10.1	3/17/2020

10.8+	Form of 2020 Cash Award under Gulfport Energy Corporation 2020 Incentive Plan.	8-K	000-19514	10.2	3/17/2020

10.9	Employment Agreement, entered into and effective as of August 1, 2019, by and between Gulfport Energy Corporation and David M. Wood.	10-Q	000-19514	10.3	8/2/2019

10.10	Employment Agreement, entered into and effective as of August 1, 2019, by and between Gulfport Energy Corporation and Donnie Moore.	10-Q	000-19514	10.4	8/2/2019

10.11	Employment Agreement, entered into and effective as of August 1, 2019, by and between Gulfport Energy Corporation and Patrick K. Craine.	10-Q	000-19514	10.5	8/2/2019

10.12	Employment Agreement, effective as of August 26, 2019, by and between Gulfport Energy Corporation and Quentin Hicks.	8-K	000-19514	10.1	8/12/19

10.13	Employment Agreement dated November 13, 2020, by and between the Company and Michael Sluiter.	8-K	001-19514	10.4	11/16/2020

10.14	Amended and Restated Credit Agreement, dated as of December 27, 2013, by and among the Company, as borrower, The Bank of Nova Scotia, as administrative agent, sole lead arranger and sole bookrunner, Amegy Bank National Association, as syndication agent, KeyBank National Association, as documentation agent, and the other lenders party thereto.	8-K	000-19514	10.1	1/3/2014

110

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Index to Financial Statement s


10.15	First Amendment to Amended and Restated Credit Agreement, dated as of April 23, 2014, among Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent, sole lead arranger and sole bookrunner, Amegy Bank National Association, as syndication agent, KeyBank National Association, as documentation agent, and the other lenders party thereto.	8-K	000-19514	10.1	4/28/2014

10.16	Second Amendment to Amended and Restated Credit Agreement, dated as of November 26, 2014, among Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent, and the lenders party thereto.	8-K	000-19514	10.1	12/3/2014

10.17	Third Amendment to Amended and Restated Credit Agreement, dated as of April 10, 2015, among the Company, as borrower, The Bank of Nova Scotia, as administrative agent, and the lenders party thereto.	8-K	000-19514	10.1	4/15/2015

10.18	Fourth Amendment to Amended and Restated Credit Agreement, dated as of May 29, 2015, among the Company, as borrower, the Bank of Nova Scotia, as administrative agent, and the lenders party thereto.	10-Q	000-19514	10.2	8/7/2015

10.19	Fifth Amendment to Amended and Restated Credit Agreement, dated as of September 18, 2015, among the Company, as borrower, The Bank of Nova Scotia, as administrative agent, and the lenders party thereto.	8-K	000-19514	10.1	9/24/2015

10.20	Sixth Amendment, dated February 19, 2016, to Amended and Restated Credit Agreement, dated as of September 18, 2015, among the Company, as borrower, The Bank of Nova Scotia, as administrative agent, and the lenders party thereto.	10-Q	000-19514	10.2	5/5/2016

10.21	Seventh Amendment to Amended and Restated Credit Agreement, dated as of December 13, 2016, among Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent, and the lenders party thereto.	8-K	000-19514	10.1	12/15/2016

10.22	Eighth Amendment to Amended and Restated Credit Agreement, entered into as of March 29, 2017, among Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent and L/C issuer, and the lenders party thereto.	8-K	000-19514	10.1	4/4/2017

10.23	Ninth Amendment to Amended and Restated Credit Agreement, entered into as of May 4, 2017, among Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent and L/C issuer, the existing lenders named therein and JPMorgan Chase Bank, N.A., Commonwealth Bank of Australia, ABN, AMRO Capital USA LLC, Fifth Third Bank and Canadian Imperial Bank of Commerce, New York branch, as new lenders.	10-Q	000-19514	10.2	5/9/2017

111

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Index to Financial Statement s


10.24	Tenth Amendment to Amended and Restated Credit Agreement, dated as of October 4, 2017, among Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent, and the lenders party thereto.	8-K	000-19514	10.1	10/5/2017

10.25	Eleventh Amendment to Amended and Restated Credit Agreement, dated as of November 21, 2017, among Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent, and the lenders party thereto.	8-K	000-19514	10.1	11/28/2017

10.26	Twelfth Amendment to Amended and Restated Credit Agreement, dated as of May 21, 2018, among Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent, and the lenders party thereto.	8-K	000-19514	10.1	5/25/2018

10.27	Thirteenth Amendment to the Amended and Restated Credit Agreement, dated as of November 28, 2018, between Gulfport Energy Corporation, as Borrower, The Bank of Nova Scotia, as Administrative Agent and the lenders party thereto.	8-K	000-19514	10.1	12/4/2018

10.28	Fourteenth Amendment to the Amended and Restated Credit Agreement, dated as of June 3, 2019, between Gulfport Energy Corporation, as Borrower, The Bank of Nova Scotia, as Administrative Agent and the lenders party thereto.	8-K	000-19514	10.1	6/7/2019

10.29	Fifteenth Amendment to the Amended and Restated Credit Agreement, dated as of May 1, 2020, between Gulfport Energy Corporation, as Borrower, the Bank of Nova Scotia, as Administrative Agent and the lenders party thereto.	10-Q	001-19514	10.3	8/7/2020

10.30	Sixteenth Amendment to the Amended and Restated Credit Agreement, dated as of July 27, 2020, between Gulfport Energy Corporation, as Borrower, the Bank of Nova Scotia, as Administrative Agent and the lenders party thereto	8-K	001-19514	10.1	7/30/2020

10.31	First Forbearance Agreement and Amendment to Amended and Restated Credit Agreement, dated as of October 15, 2020, by and among the Gulfport Energy Corporation, as Borrower, the Bank of Nova Scotia, as Administrative Agent and the lender party thereto.	8-K	001-19514	10.1	10/16/2020

10.32	Second Forbearance Agreement and Amendment to Amended and Restated Credit Agreement, dated as of October 26, 2020, by and among the Gulfport Energy Corporation, as Borrower, the Bank of Nova Scotia, as Administrative Agent and the lender party thereto.	8-K	001-19514	10.1	10/29/2020

10.33	Restructuring Support Agreement, dated November 13, 2020.	8-K	001-19514	10.2	11/16/2020

10.34	Backstop Commitment Agreement, dated November 13, 2020 (incorporated by reference to Exhibit D of the Restructuring Support Agreement attached as Exhibit 10.33 hereto).	8-K	001-19514	10.2	11/16/2020

112

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Index to Financial Statement s

10.35

Form of DIP Credit Agreement (incorporated by reference to Exhibit E of the Restructuring Support Agreement attached as Exhibit 10.33 hereto).

8-K

001-19514

10.4

11/16/2020

10.36

Senior Secured Super Priority Debtor-in-Possession Credit Agreement, dated as of November 17, 2020, by and among the Company, as borrower, The Bank of Nova Scotia, as administrative agent, and the other lenders party thereto.

8-K

001-19514

10.1

11/20/2020

10.37 #

Sand Supply Agreement, effective as of October 1, 2014, by and between Muskie Proppant LLC and Gulfport Energy Corporation.

10-Q

000-19514

10.1

11/7/2014

10.38 #

Amendment to Sand Supply Agreement, dated as of November 3, 2015, by and between Muskie Proppant LLC and Gulfport Energy Corporation.

10-Q

000-19514

10.2

11/5/2015

10.39

Second Amendment to Sand Supply Agreement, dated as of August 6, 2018, between Gulfport Energy Corporation and Muskie Proppant LLC.

10-Q

000-19514

10.2

11/1/2018

10.40 #

Amended and Restated Master Services Agreement, effective as of October 1, 2014, by and between Gulfport Energy Corporation and Stingray Pressure Pumping LLC.

10-Q

000-19514

10.2

11/7/2014

10.41 #

Amendment to Amended and Restated Master Services Agreement, dated as of February 18, 2016 to be effective as of January 1, 2016, by and between Gulfport Energy Corporation and Stingray Pressure Pumping LLC.

10-K

000-19514

10.19

2/19/2016

10.42 #

Amendment No. 2, dated as of July 10, 2018, between Stingray Pressure Pumping, LLC and Gulfport Energy Corporation to that certain Amended & Restated Master Services Agreement for Pressure Pumping Services, effective as of October 1, 2014, as amended effective January 1, 2016.

10-Q

000-19514

10.2

8/2/2018

10.43 +

Form of Indemnification Agreement.

S-4

333-199905

10.1

11/6/2014

Code of Ethics.

8-K

000-19514

2/14/2006

Subsidiaries of the Registrant.

23.1

Consent of Grant Thornton LLP.

23.2

Consent of Netherland, Sewell & Associates, Inc.

31.1

Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.

31.2

Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.

113

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Index to Financial Statement s

32.1

Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.

32.2

Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.

99.1

Report of Netherland, Sewell & Associates, Inc.

101.INS

Inline XBRL Instance Document.

11.SCH*

Inline XBRL Taxonomy Extension Schema Document.

101.CAL

Inline XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF

Inline XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB

Inline XBRL Taxonomy Extension Labels Linkbase Document.

101.PRE

Inline XBRL Taxonomy Extension Presentation Linkbase Document.


*			Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The registrant hereby undertakes to furnish supplemental copies of any of the omitted schedules upon request by the SEC.


**			The Company agrees to furnish a copy of any of its unfiled long-term debt instruments to the Securities and Exchange Commission upon request.


+			Management contract, compensatory plan or arrangement.


#			Confidential treatment has been requested for portions of this exhibit. These portions have been omitted and submitted separately to the Securities and Exchange Commission.

114

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Index to Financial Statement s

SIGNATURES

In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: March 5, 2021


GULFPORT ENERGY CORPORATION

~~21.~~By:	~~SUBSEQUENT EVENTS~~	/s/ QUENTIN HICKS
		Quentin Hicks Chief Financial Officer

~~Derivatives~~

In ~~February 2019,~~accordance with the ~~Company entered into a natural gas basis swap position for 2020, which settles~~Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the ~~pricing index to basis differential of Inside FERC to the NYMEX Henry Hub natural gas price, for approximately 10,000 MMBtu of natural gas per day at a differential of~~ ~~$0.54 per MMBtu.~~dates indicated.

~~Stock Repurchase Program~~

~~In January 2019, the board of directors of the Company approved a stock repurchase program to acquire up to $400.0 million of the Company's outstanding common stock within the next 24~~ months. Purchases under the repurchase program may be made from time to time in open market or privately negotiated transactions, and will be subject to market conditions, applicable legal requirements, contractual obligations and other factors. The repurchase program does not require the Company to acquire any specific number of shares. The Company intends to purchase shares under the repurchase program opportunistically with available funds while maintaining sufficient liquidity to fund its 2019 capital development program. This repurchase program is authorized to extend through December 31, 2020 and may be suspended from time to time, modified, extended or discontinued by the board of directors of the Company at any time. The Company has ~~not made any such purchases of its common stock under this program as of February 28, 2019.~~

Date:

March 5, 2021

By:

/s/ DAVID M. WOOD

David M. Wood
Chief Executive Officer and President, Director
(Principal Executive Officer)

Date:

March 5, 2021

By:

/s/ ALVIN BLEDSOE

Alvin Bledsoe
Chairman of the Board and Director

Date:

March 5, 2021

By:

/s/ QUENTIN HICKS

Quentin Hicks
Chief Financial Officer
(Principal Accounting and Financial Officer)

Date:

March 5, 2021

By:

/s/ DEBORAH G. ADAMS

Deborah G. Adams
Director

Date:

March 5, 2021

By:

/s/ SAMANTHA HOLROYD

Samantha Holroyd
Director

Date:

March 5, 2021

By:

/s/ VALERIE JOCHEN

Valerie Jochen
Director

Date:

March 5, 2021

By:

/s/ C. DOUG JOHNSON

C. Doug Johnson
Director

Date:

March 5, 2021

By:

/s/ BEN T. MORRIS

Ben T. Morris
Director

Date:

March 5, 2021

By:

/s/ JOHN W. SOMERHALDER II

John W. Somerhalder II
Director

~~F-53~~

115



								Proved Reserves
Field	Average NRI/WI (1)	Productive Wells		Non-Productive Wells		Developed Acreage (2)		Gas	Oil	NGLs	Total
Field	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



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	—



	SEC Pricing 2018		2-month Average 2019
Henry Hub Natural Gas (per MMBtu)	$	3.10	$	3.90
WTI Crude Oil (per Bbl)	$	65.56	$	48.17



	Year Ended December 31,
	2018		2017 (1)
SCOOP
Net Production
Oil (MBbls)	1,710		1,083
Natural gas (MMcf)	64,258		40,501
NGL (Mgal)	138,261		84,283
Total (MMcfe)	94,268		59,038
Average Sales Price Without the Impact of Derivatives:
Oil ($/Bbl)	$	62.36	$	48.70
Natural gas ($/Mcf)	$	2.67	$	2.68
NGL ($/Gal)	$	0.75	$	0.62
Average Production Costs ($/Mcfe)	$	0.20	$	0.19



	Price Range of Common Stock
	High		Low
2017
First Quarter	$	22.35	$	15.66
Second Quarter	17.82		12.47
Third Quarter	15.09		10.90
Fourth Quarter	15.08		11.73
2018
First Quarter	$	13.74	$	8.11
Second Quarter	12.70		8.60
Third Quarter	13.41		10.07
Fourth Quarter	11.67		6.18



Period	Total number of shares purchased⁽²⁾	Average price paid per share		Total number of shares purchased as part of publicly announced plans or programs ⁽²⁾	Approximate maximum dollar value of shares that may yet be purchased under the plans or programs ⁽¹⁾
October 2018	—	$	—	—	$	90,003,000
November 2018	28,584	$	8.81	—	$	90,003,000
December 2018	10,212,483	$	8.81	10,212,483	$	—
Total	10,241,067	$	8.81	10,212,483



	Location	Daily Volume (MMBtu/day)	Weighted Average Price
2019	NYMEX Henry Hub	1,254,000	$	2.83
2020	NYMEX Henry Hub	204,000	$	2.77



	Location	Daily Volume (Bbls/day)	Weighted Average Price
2019	Mont Belvieu C2	1,000	$	18.48
2019	Mont Belvieu C3	4,000	$	28.87
2019	Mont Belvieu C5	500	$	54.08



	Location	Daily Volume (MMBtu/day)	Hedged Differential
2019	Transco Zone 4	60,000	$	(0.05	)
2020	Transco Zone 4	60,000	$	(0.05	)



	(In thousands)
December 31, 2015	$	(55,175	)
December 31, 2016	$	(51,709	)
December 31, 2017	$	(39,190	)
December 31, 2018	$	(54,677	)



	(In thousands)
Consideration:
Cash, net of purchase price adjustments	$	1,354,093
Fair value of Gulfport’s common stock issued	464,639
Total Consideration	$	1,818,732

Estimated Fair value of identifiable assets acquired and liabilities assumed:
Oil and natural gas properties
Proved properties	$	362,264
Unproved properties	1,462,957
Asset retirement obligations	(6,489		)
Total fair value of net identifiable assets acquired	$	1,818,732



	Period from
	February 17, 2017
	to
	December 31, 2017
	(In thousands)
Revenue	$	213,368



	Number of Unvested Restricted Shares		Weighted Average Grant Date Fair Value
Unvested shares as of January 1, 2016	484,239		$	43.51
Granted	451,241		27.78
Vested	(252,566	)	43.94
Forfeited	(69,858	)	33.43
Unvested shares as of December 31, 2016	613,056		$	32.90
Granted	876,846		$	15.14
Vested	(423,977	)	29.90
Forfeited	(89,898	)	27.91
Unvested shares as of December 31, 2017	976,027		$	18.71
Granted	1,579,911		9.90
Vested	(626,671	)	18.05
Forfeited	(393,456	)	12.23
Unvested shares as of December 31, 2018	1,535,811		$	11.57



	As of December 31, 2017
	Derivative instruments, gross			Netting adjustments			Derivative instruments, net
	(In thousands)
Derivative assets	$	87,532		$	(22,199	)	$	65,333
Derivative liabilities	$	(35,523	)	$	22,199		$	(13,324	)



	(MMBtu per day)
2019	663,000
2020	526,000
2021	372,000
2022	272,000
2023	255,000
Thereafter	212,000
Total	2,300,000



	(In thousands)
2019	$	251,644
2020	247,581
2021	246,620
2022	246,620
2023	244,352
Thereafter	2,267,501
Total	$	3,504,318



	For the years ended December 31,
	2018		2017		2016
	(In thousands)
Rent expense	$	196	$	343	$	840



	December 31, 2018
	Parent			Guarantors			Non-Guarantor			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	25,585		$	26,711		$	1		$	—		$	52,297
Accounts receivable - oil and natural gas sales	146,075			64,125			—			—			210,200
Accounts receivable - joint interest and other	16,212			6,285			—			—			22,497
Accounts receivable - intercompany	671,633			319,464			—			(991,097		)	—
Prepaid expenses and other current assets	8,433			2,174			—			—			10,607
Short-term derivative instruments	21,352			—			—			—			21,352
Total current assets	889,290			418,759			1			(991,097		)	316,953
Property and equipment:
Oil and natural gas properties, full-cost accounting	7,044,550			2,983,015			—			(729		)	10,026,836
Other property and equipment	91,916			751			—			—			92,667
Accumulated depletion, depreciation, amortization and impairment	(4,640,059		)	(39		)	—			—			(4,640,098		)
Property and equipment, net	2,496,407			2,983,727			—			(729		)	5,479,405
Other assets:
Equity investments and investments in subsidiaries	2,856,988			—			44,259			(2,665,126		)	236,121
Inventories	3,620			1,134			—			—			4,754
Other assets	12,624			1,178			—			1			13,803
Total other assets	2,873,232			2,312			44,259			(2,665,125		)	254,678
Total assets	$	6,258,929		$	3,404,798		$	44,260		$	(3,656,951	)	$	6,051,036

Liabilities and stockholders' equity
Current liabilities:
Accounts payable and accrued liabilities	$	419,107		$	99,273		$	—		$	—		$	518,380
Accounts payable - intercompany	320,259			670,708			130			(991,097		)	—
Short-term derivative instruments	20,401			—			—			—			20,401
Current maturities of long-term debt	651			—			—			—			651
Total current liabilities	760,418			769,981			130			(991,097		)	539,432
Long-term derivative instruments	13,992			—			—			—			13,992
Asset retirement obligation - long-term	66,859			13,093			—			—			79,952
Deferred tax liability	3,127			—			—			—			3,127
Long-term debt, net of current maturities	2,086,765			—			—			—			2,086,765
Total liabilities	2,931,161			783,074			130			(991,097		)	2,723,268

Stockholders' equity:
Common stock	1,630			—			—			—			1,630
Paid-in capital	4,227,532			1,915,598			261,626			(2,177,224		)	4,227,532
Accumulated other comprehensive loss	(56,026		)	—			(53,783		)	53,783			(56,026		)
(Accumulated deficit) retained earnings	(845,368		)	706,126			(163,713		)	(542,413		)	(845,368		)
Total stockholders' equity	3,327,768			2,621,724			44,130			(2,665,854		)	3,327,768
Total liabilities and stockholders' equity	$	6,258,929		$	3,404,798		$	44,260		$	(3,656,951	)	$	6,051,036



	Year Ended December 31, 2017
	Parent			Guarantors			Non-Guarantor			Eliminations			Consolidated

Total revenues	$	1,010,989		$	309,314		$	—		$	—		$	1,320,303

Costs and expenses:
Lease operating expenses	65,793			14,453			—			—			80,246
Production taxes	15,100			6,026			—			—			21,126
Midstream gathering and processing expenses	187,678			61,317			—			—			248,995
Depreciation, depletion and amortization	364,625			4			—			—			364,629
General and administrative expenses	55,589			(2,654		)	3			—			52,938
Accretion expense	1,246			365			—			—			1,611
Acquisition expense	—			2,392			—			—			2,392
	690,031			81,903			3			—			771,937

INCOME (LOSS) FROM OPERATIONS	320,958			227,411			(3		)	—			548,366

OTHER (INCOME) EXPENSE:
Interest expense	112,732			(4,534		)	—			—			108,198
Interest income	(988		)	(21		)	—			—			(1,009		)
Gain on sale of equity method investments	(12,523		)	—			—			—			(12,523		)
(Income) loss from equity method investments and investments in subsidiaries	(213,607		)	1,955			2,189			227,243			17,780
Other (income) expense, net	(1,617		)	(324		)	—			900			(1,041		)
	(116,003		)	(2,924		)	2,189			228,143			111,405

INCOME (LOSS) BEFORE INCOME TAXES	436,961			230,335			(2,192		)	(228,143		)	436,961
INCOME TAX EXPENSE	1,809			—			—			—			1,809

NET INCOME (LOSS)	$	435,152		$	230,335		$	(2,192	)	$	(228,143	)	$	435,152



	Year Ended December 31, 2016
	Parent			Guarantors			Non-Guarantor			Eliminations			Consolidated

Total revenues	$	381,931		$	3,979		$	—		$	—		$	385,910

Costs and expenses:
Lease operating expenses	68,034			843			—			—			68,877
Production taxes	13,121			155			—			—			13,276
Midstream gathering and processing expenses	165,400			572			—			—			165,972
Depreciation, depletion and amortization	245,970			4			—			—			245,974
Impairment of oil and natural gas properties	715,495			—			—			—			715,495
General and administrative expenses	43,896			(490		)	3			—			43,409
Accretion expense	1,057			—			—			—			1,057
	1,252,973			1,084			3			—			1,254,060

(LOSS) INCOME FROM OPERATIONS	(871,042		)	2,895			(3		)	—			(868,150		)

OTHER (INCOME) EXPENSE:
Interest expense	63,529			1			—			—			63,530
Interest income	(1,230		)	—			—			—			(1,230		)
Insurance proceeds	(5,718		)	—			—			—			(5,718		)
Loss on debt extinguishment	23,776			—			—			—			23,776
Gain on sale of equity method investments	(3,391		)	—			—			—			(3,391		)
Loss (income) from equity method investments and investments in subsidiaries	34,469			(89		)	25,150			(22,154		)	37,376
Other expense (income), net	145			(16		)	—			—			129
	111,580			(104		)	25,150			(22,154		)	114,472

(LOSS) INCOME BEFORE INCOME TAXES	(982,622		)	2,999			(25,153		)	22,154			(982,622		)
INCOME TAX BENEFIT	(2,913		)	—			—			—			(2,913		)

NET (LOSS) INCOME	$	(979,709	)	$	2,999		$	(25,153	)	$	22,154		$	(979,709	)