DOCUMENTS INCORPORATED BY REFERENCE

Portions of Gulfport Energy Corporation’s Proxy Statement for the 2020 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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(1)	Of the 16 gross wells we drilled in 2019, six were completed as producing wells and 10 were in various stages of completion as of December 31, 2019.

(2)	Of the 10 gross wells we drilled in 2019, five were completed as producing wells, four were in various stages of completion and one was being drilled as of December 31, 2019.

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

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(1)	Utica and SCOOP accounted for approximately 71% and 29%, respectively, of our estimated proved reserves by volume as of December 31, 2019.

(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, 2019, 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, 2019. The prices used in our PV-10 measure were $55.85 per barrel and $2.58 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, 2019. 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, 2019, primarily as a result of significant net operating loss carryforwards that can be used to offset income taxes on future taxable income.

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•	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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(1)	We acquired our SCOOP assets through an acquisition completed on February 17, 2017. See Note 2 in the notes to our consolidated financial statements for additional discussion of this acquisition.

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•	reporting of workplace injuries and illnesses;

•	industrial hygiene monitoring;

•	worker protection and workplace safety;

•	approval or permits to drill and to conduct operations;

•	provision of financial assurances (such as bonds) covering drilling and well operations;

•	calculation and disbursement of royalty payments and production taxes;

•	seismic operations and data;

•	location, drilling, cementing and casing of wells;

•	well design and construction of pad and equipment;

•	construction and operations activities in sensitive areas, such as wetlands, coastal regions or areas that contain endangered or threatened species, their habitats, or sites of cultural significance;

•	method of completing wells;

•	hydraulic fracturing;

•	water withdrawal;

•	well production and operations, including processing and gathering systems;

•	emergency response, contingency plans and spill prevention plans;

•	air emissions and fluid discharges;

•	climate change;

•	use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations;

•	surface usage, maintenance, monitoring and the restoration of properties associated with well pads, pipelines, impoundments and access roads;

•	plugging and abandoning of wells; and

•	transportation of production.

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

•	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;

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•	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;

•	technological advances affecting energy consumption;

•	risks associated with operating drilling rigs;

•	the effectiveness of worldwide conservation measures;

•	the availability, proximity and capacity of 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 to agree to and maintain oil price and production controls;

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

•	weather conditions;

•	acts of terrorism; and

•	domestic and global economic conditions.

•	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,

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•	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 revolving credit facility are at variable interest rates.

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•	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;

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•	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.

•	limit our ability to plan for, or react to, market conditions, to meet capital needs or otherwise to restrict our activities or business plan;

•	adversely affect our ability to finance our operations, enter into acquisitions or divestitures to engage in other business activities that would be in our interest; or

•	withstand a continuing future downturn in our business.

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•	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.

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•	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 production, including due to inadequate midstream infrastructure or constrained 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 availability of services or delivery of equipment; and

•	unexpected or unforeseen changes in regulatory policy, and political or public opinions.

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•	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;

•	selection of technology; and

•	the rate of production of the reserves.

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•	any acquisition would be successfully integrated into our operations and internal controls;

•	the due diligence conducted prior to an acquisition would uncover situations that could result in financial or legal exposure, such as title defects and potential environmental and other liabilities;

•	post-closing purchase price adjustments will be realized in our favor;

•	any investment, acquisition, disposition or integration would not divert management resources from the operation of our business; and

•	any investment, acquisition, or disposition or integration would not have a material adverse effect on our financial condition, results of operations, cash flows or reserves.

•	recoverable reserves;

•	future oil and natural gas prices and their applicable differentials;

•	operating costs; and

•	potential environmental and other liabilities.

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•	denial of or delay in receiving requisite regulatory approvals or permits;

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

•	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.

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•	During the year ended December 31, 2019, we entered into several agreements to divest of certain non-core assets as part of our strategic initiatives to focus development in our core operating areas. These non-core divestitures consisted of the following:

◦

We sold our non-core assets located in the West Cote Blanche Bay ("WCBB") and Hackberry fields of Louisiana for a purchase price of approximately $19.7 million, subject to customary closing terms and adjustments. We received approximately $9.2 million in cash and retained contingent overriding royalty interests. In addition, we could also receive contingent payments based on commodity prices exceeding specified thresholds over the two years following the closing date. The buyer assumed all plugging and abandonment liabilities associated with these assets, which totaled approximately $30.0 million at the divestiture date. The sale closed on July 3, 2019.

◦	We sold certain non-operated interests in the Utica Shale for cash proceeds of $29.0 million subject to customary closing terms and adjustments. The sale closed on December 30, 2019.

◦	We sold certain overriding royalty interests associated with assets we held in the Bakken for cash proceeds of approximately $7.0 million subject to customary closing terms and adjustments. The sale closed on December 11, 2019.

◦

In December 2019, we entered into an agreement to divest our water infrastructure assets across our SCOOP position to a third-party water service provider. This transaction closed on January 2, 2020. We received $50.0 million in cash upon closing and have an opportunity to earn potential additional incentive payments over the next 15 years, subject to our ability to meet certain thresholds which will be driven by, among other things, our future development program and future water production levels. The agreement contains no

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During the year ended December 31, 2019, we used borrowings under our revolving credit facility to repurchase in the open market approximately $190.1 million aggregate principal amount of our outstanding 6.625% Senior Notes due 2023 ("2023 Notes"), 6.000% Senior Notes due 2024 ("2024 Notes"), 6.375% Senior Notes due 2025 ("2025 Notes"), and 6.375% Senior Notes due 2026 ("2026 Notes") (collectively the "Notes"), for $138.8 million. We recognized a $48.6 million gain on debt extinguishment, which included retirement of unamortized issuance costs and fees associated with the repurchased debt.

•	Production increased 1% to approximately 501,742 MMcfe for the year ended December 31, 2019 from approximately 496,505 MMcfe for the year ended December 31, 2018.

•	During 2019, we spud 26 gross (23.2 net) wells, turned to sales 61 gross (54.1 net) operated wells, participated in an additional 47 gross (2.5 net) wells that were drilled by other operators on our Utica Shale and SCOOP acreage. Of our 26 new wells spud during 2019, 11 were completed as producing wells and, at year end, 14 were in various stages of completion and one was being drilled.

•	During the year ended December 31, 2019, we reduced our unit lease operating expense by 10% to $0.17 per Mcfe from $0.18 per Mcfe during the year ended December 31, 2018.

•	During the year ended December 31, 2019, we reduced our general and administrative expense by 4% to $48.0 million from $50.0 million during the year ended December 31, 2018.

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(1)	See Note 5 of the notes to our consolidated financial statements included in Item 8 of this report for a description of our long-term debt.

(2)	See Note 16 of the notes to our consolidated financial statements included in Item 8 of this report for a description of our firm transportation contracts.

(3)	See Note 9 of the notes to our consolidated financial statements included in Item 8 of this report for a description of our operating lease liabilities.

(4)	This table does not include derivative liabilities or the estimated discounted cost for future abandonment of oil and natural gas properties. See Notes 12 and 3 of the notes to our consolidated financial statements included in Item 8 of this report, respectively.

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(1)	Includes Niobrara and Bakken

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•	Swaps: We receive a fixed price and pay a floating market price to 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 excess on sold call options, and we receive the excess on bought call options. If the market price settles below the fixed price of the call option, no payment is due from either party.

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(1)

In the third quarter of 2019, we 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 primarily for 2020 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.

(2)

The purchase and sale agreement for the sale of our non-core assets located in the WCBB and Hackberry fields of Louisiana included a contingent consideration arrangement that entitles us 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.

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•	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 reserve specialists, made inquiries of those reservoir engineers regarding the process followed and judgments made to estimate the Company’s proved reserve volumes and read the report prepared by the Company’s reserve specialists.

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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 interests. 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.

•	We tested the effectiveness of controls over management’s estimates of the realization of the deferred tax assets, including those over management’s corporate model which was the basis for the forecast of future taxable income, management’s tax planning strategies and the determination of whether it is more likely than not that the deferred tax assets will be realized prior to expiration.

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•	With the assistance of our income tax specialists, we evaluated the forecast of future taxable income considering whether the estimated future sources of taxable income were of the appropriate character to utilize the net operating loss carryforwards and other temporary differences giving rise to the deferred tax assets under current tax law.

•	With the assistance of our income tax specialists, we evaluated management’s Internal Revenue Code Section 382 ownership change calculations.

•	We tested the reasonableness of management’s corporate model used to estimate future taxable income by comparing the estimates to the following:

◦	Historical taxable income.

◦	Internal communications with the board of directors.

◦	Evidence obtained in other areas of the audit.

◦	Management’s history of carrying out its stated plans and its ability to carry out its plans considering contractual commitments, available financing, or debt covenants.

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(1)	No taxes were recorded for the years ended December 31, 2019, 2018 and 2017.

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1.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Business

Gulfport Energy Corporation (“Gulfport” or the "Company"), a Delaware corporation formed in 1997, is an independent natural gas-weighted exploration and production company focused on the exploration, acquisition and production of natural gas, crude oil and natural gas liquids ("NGL") in the United States. The Company's principal properties are located in Eastern Ohio targeting the Utica formation and in central Oklahoma targeting the SCOOP Woodford and SCOOP Springer formations.

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.

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, Gulfport MidCon, LLC, Mule Sky LLC and GRUS, LLC. All intercompany balances and transactions are eliminated in consolidation.

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 allowance was deemed necessary at December 31, 2019 and December 31, 2018.

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, 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 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 at December 31, 2019, the Company recognized a ceiling test impairment of $2.0 billion for the year ended December 31, 2019.

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 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 proved oil and gas reserves. Oil and gas properties not subject to amortization consist of the cost of unproved leaseholds and totaled approximately $1.7 billion and $2.9 billion at December 31, 2019 and December 31, 2018, respectively. These costs are reviewed quarterly by management for impairment. If impairment 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’ 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, 2016	$	(51,709	)
December 31, 2017	$	(39,190	)
December 31, 2018	$	(54,677	)
December 31, 2019	$	(45,484	)

Net Income per Common Share

Basic net 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 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 income per common share are illustrated in Note 11.

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Income Taxes

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 2005 – 2018 U.S. federal and 1999 - 2018 state income tax returns remain open to examination by tax authorities, due to net operating losses. As of December 31, 2019, the Company has no 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.

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 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.

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") 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 8 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 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. During the year ended December 31, 2019, the Company recorded an impairment of $160.8 million related to its investment in Mammoth Energy Services, Inc. ("Mammoth Energy") and an impairment of $32.4 million related to its investment in Grizzly Oil Sands ULC ("Grizzly"). There were no impairment charges recorded for the years ended December 31, 2017 and December 31, 2018. See Note 4 for further discussion of Mammoth Energy and Grizzly impairments.

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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 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.

Derivative Instruments

The Company utilizes commodity derivatives to manage the price risk associated with forecasted sale of its natural gas, crude oil and NGL production. All derivative instruments are recognized as assets or liabilities in the consolidated balance 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

Certain reclassifications have been made to prior period financial statements and related disclosures to conform to current period presentation. These reclassifications have no impact on previous reported total assets, total liabilities, net (loss) income or total operating cash flows.

Statements of Cash Flows

During the third quarter of 2019, the Company identified that certain activities were misclassified between cash flows from operating activities and cash flows from investing activities. These activities had been included in accounts payable, accrued liabilities and other and presented as cash flows from operating activities while they should have been presented as additions to oil and natural gas properties in cash flows from investing activities.  The Company corrected the previously presented statements of cash flows for these additions and in doing so, for the year ended December 31, 2018, the consolidated statements of cash flows and the condensed consolidating statements of cash flows were adjusted to increase net cash flows provided by operating activities by $33.8 million with a corresponding increase in net cash flows used in investing activities. The Company has evaluated the effect of the incorrect presentation, both qualitatively and quantitatively, and concluded that it did not have a material impact on any previously filed annual or quarterly consolidated financial statements.

Recent Accounting Pronouncements

In January 2019, the Company adopted Accounting Standards Update ("ASU") No. 2016-02, Leases (Topic 842) on a prospective basis using the simplified transition method permitted by ASU 2018-11, Leases (Topic 842): Targeted Improvements. See Note 9 for further discussion of the lease standard.

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. Subsequent to ASU 2016-13, the FASB issued several related ASU’s to clarify the application of the credit loss standard.

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The guidance is effective for periods after December 15, 2019, with early adoption permitted. The Company adopted the standard as of January 1, 2020 with no material effect on its consolidated financial statements and related disclosures.

2.	ACQUISITIONS AND DIVESTITURES

Sale of Southern Louisiana Assets

In December 2018, the Company entered into an agreement to sell its non-core assets located in the West Cote Blanche Bay ("WCBB") and Hackberry fields of Louisiana to an undisclosed third party for a purchase price of approximately $19.7 million. The sale closed on July 3, 2019, subject to customary post-closing terms and conditions, with an effective date of August 15, 2018. The Company received approximately $9.2 million in cash and retained contingent overriding royalty interests. In addition, the Company could also receive contingent payments based on commodity prices exceeding specified thresholds over the two years following the closing date. See Note 12 for further discussion of the contingent consideration arrangement, which was determined to be 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.

Sale of Non-operated Utica Interests

In December 2019, the Company entered into an agreement to divest certain non-operated interests in the Utica Shale 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 of purchase price adjustments, the Company received approximately $7.0 million of total proceeds.

Vitruvian Acquisition

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 certain assets of Vitruvian II Woodford, LLC (“Vitruvian”), an unrelated third-party seller (the “Vitruvian Acquisition”). The assets included in the Vitruvian Acquisition include 46,400 net surface acres located in Grady, Stephens and Garvin Counties, Oklahoma. 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 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 expenses of 2.4 million were incurred during the year ended December 31, 2017 related to the Vitruvian Acquisition.

For the period from the acquisition date of February 17, 2017 to December 31, 2017, the assets acquired in the Vitruvian Acquisition 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

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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

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 intended to be a projection of future results.

		December 31, 2017
		(In thousands, except share data)
Pro forma revenue		$	1,356,202
Pro forma net income		$	448,398
Pro forma earnings per share (basic)		$	2.49
Pro forma earnings per share (diluted)		$	2.49

3.	PROPERTY AND EQUIPMENT

The major categories of property and equipment and related accumulated depletion, depreciation, amortization and impairment as of December 31, 2019 and 2018 are as follows:

	December 31,
	2019				2018
	(In thousands)
Oil and natural gas properties	$	10,595,735			$	10,026,836
Other depreciable property and equipment	91,198				87,146
Land	5,521				5,521
Total property and equipment	10,692,454				10,119,503
Accumulated depletion, depreciation, amortization and impairment	(7,228,660		)		(4,640,098		)
Property and equipment, net	$	3,463,794			$	5,479,405

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 year ended December 31, 2019, the Company incurred $2.0 billion of impairments as a result of its oil and natural gas properties exceeding its calculated ceiling. 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, to a lesser degree, proved reserves. No impairment of oil and natural gas properties was required under the ceiling test for the years ended December 31, 2018 and 2017.

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 $30.1 million, $37.7 million and $35.7 million for the years ended December 31, 2019, 2018 and 2017, 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 $1.08, $0.96 and $0.90 per Mcfe for the years ended December 31, 2019, 2018 and 2017, respectively.

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The following is a summary of Gulfport’s oil and natural gas properties not subject to amortization as of December 31, 2019:

	Costs Incurred in
	2019				2018				2017				Prior to 2017				Total
	(In thousands)
Acquisition costs	$	9,089			$	98,870			$	756,963			$	806,982			$	1,671,904
Exploration costs	259				—				—				—				259
Development costs	1,213				548				869				10,325				12,955
Capitalized interest	888				413				247				—				1,548
Total oil and natural gas properties not subject to amortization	$	11,449			$	99,831			$	758,079			$	817,307			$	1,686,666

The following table summarizes the Company’s non-producing properties excluded from amortization by area as of December 31, 2019:

	December 31, 2019
	(In thousands)
Utica	$	976,593
MidContinent	709,739
Other	334
	$	1,686,666

As of December 31, 2018, approximately $2.9 billion of non-producing leasehold costs was not 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 extension terms which could extend this time frame beyond five years.

A reconciliation of the Company's asset retirement obligation for the years ended December 31, 2019 and 2018 is as follows:

	December 31,
	2019				2018
	(In thousands)
Asset retirement obligation, beginning of period	$	79,952			$	75,100
Liabilities incurred	5,935				1,827
Liabilities settled	(273		)		(719		)
Liabilities removed due to divestitures	(30,146		)		—
Accretion expense	3,939				4,119
Revisions in estimated cash flows	948				(375		)
Asset retirement obligation as of end of period	$	60,355			$	79,952

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4.	EQUITY INVESTMENTS

Investments accounted for by the equity method consist of the following as of December 31, 2019 and 2018:

				Carrying Value								Loss (income) from equity method investments
	Approximate Ownership %			December 31,								For the Year Ended December 31,
				2019				2018				2019				2018				2017
				(In thousands)
Investment in Tatex Thailand II, LLC	23.5	%		$	—			$	—			$	(2,086	)		$	(241	)		$	(549	)
Investment in Tatex Thailand III, LLC(1)	—	%		—				—				—				—				(183		)
Investment in Grizzly Oil Sands ULC	24.9999	%		21,000				44,259				32,710				510				2,189
Investment in Timber Wolf Terminals LLC(2)	—	%		—				—				—				536				8
Investment in Windsor Midstream LLC	22.5	%		39				39				—				(9		)		25,233
Investment in Stingray Cementing LLC(3)	—	%		—				—				—				—				205
Investment in Blackhawk Midstream LLC(4)	—	%		—				—				—				(38		)		—
Investment in Stingray Energy Services LLC(3)	—	%		—				—				—				—				282
Investment in Sturgeon Acquisitions LLC(3)	—	%		—				—				—								(71		)
Investment in Mammoth Energy Services, Inc.(3)	21.8	%		11,005				191,823				179,524				(49,969		)		(11,288		)
Investment in Strike Force Midstream LLC(5)	—	%		—				—				—				(693		)		1,954
				$	32,044			$	236,121			$	210,148			$	(49,904	)		$	17,780

_____________________

(1)	In December 2017, the Company received its final distribution from Tatex Thailand III, LLC ("Tatex III"), which was dissolved in 2017.

(2)	On June 5, 2018, the Company received its final distribution from Timber Wolf Terminals LLC ("Timber Wolf"), which was dissolved in 2018.

(3)	On June 5, 2017, Mammoth Energy acquired Stingray Cementing LLC, Stingray Energy Services LLC and Sturgeon Acquisitions LLC. See below under Mammoth Energy Services, Inc. for information regarding these transactions.

(4)	On December 31, 2018, the Company received its final distribution from Blackhawk Midstream LLC ("Blackhawk"), which was dissolved in 2018.

(5)	On May 1, 2018, the Company sold its 25% interest in Strike Force Midstream LLC ("Strike Force") to EQT Midstream Partners, LP for proceeds of $175.0 million in cash. As a result of 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.

The tables below summarize financial information for the Company's equity investments, as of December 31, 2019 and 2018.

Summarized balance sheet information:

	December 31,
	2019				2018
	(In thousands)
Current assets	$	421,326			$	471,733
Noncurrent assets	$	1,260,075			$	1,302,488
Current liabilities	$	132,569			$	239,975
Noncurrent liabilities	$	163,241			$	94,575

Summarized results of operations:

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	December 31,
	2019				2018				2017
	(In thousands)
Gross revenue	$	625,012			$	1,729,778			$	755,374
Net (loss) income	$	(76,523	)		$	253,451			$	(37,102	)

Tatex Thailand II, LLC

The Company has an indirect ownership interest in Tatex Thailand II, LLC (“Tatex”) and received $2.1 million in distributions from Tatex during the year ended December 31, 2019, of which $1.9 million related to proceeds from the sale of its interest in APICO (“APICO”), an international oil and gas exploration company. The Company received $0.2 million in distributions from Tatex during the year ended December 31, 2018. Tatex previously held an 8.5% interest in APICO before selling its interest in June 2019. 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.

Grizzly Oil Sands ULC

The Company, through its wholly owned subsidiary Grizzly Holdings Inc. ("Grizzly Holdings"), owns a 24.9999% interest in Grizzly, a Canadian unlimited liability company. The remaining interest in Grizzly is owned by Grizzly Oil Sands Inc. As of December 31, 2019, Grizzly had approximately 830,000 acres under lease in the Athabasca, Peace River and Cold Lake oil sands regions of Alberta, Canada.

The Company reviewed its investment in Grizzly at December 31, 2019 for impairment based on certain qualitative and quantitative factors. The Company engaged an independent third party to assist management in determining fair value calculations of its investment. As a result of the calculated fair values and other qualitative factors, the Company concluded that an other than temporary impairment was indicated. This resulted in recording an impairment loss of $32.4 million for the year ended December 31, 2019, which is included in loss from equity method investments, net in the accompanying consolidated statements of operations. The Company reviewed its investment in Grizzly for impairment at December 31, 2018 and 2017 and determined no impairment was required.

The Company paid $0.4 million in cash calls during 2019 prior to its election to cease funding further capital calls. The Company paid $2.3 million in cash calls during the year ended December 31, 2018. Grizzly’s functional currency is the Canadian dollar. The Company's investment in Grizzly was increased by a $9.0 million foreign currency translation gain, decreased by a $15.2 million foreign currency translation loss and increased by a $12.3 million foreign currency translation gain for the years ended December 31, 2019, 2018 and 2017, respectively. The Company had $44.8 million and $53.8 million in accumulated other comprehensive loss in its accompanying consolidated balance sheets related to Grizzly at December 31, 2019 and December 31, 2018, respectively, that will be included in the calculations of future charge related to a sale or abandonment.

Windsor Midstream LLC

At December 31, 2019, 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 years ended December 31, 2019 and 2018.

The Company has determined that Midstream is a variable interest entity ("VIE") but that the Company is not the primary beneficiary because it does not have a controlling financial interest in Midstream. This entity is considered a VIE because the limited partners lack substantive kick-out or participating rights over the general partner. The general partner has power to direct the activities that most significantly impact Midstream's economic performance. 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.

Mammoth Energy Services, Inc.

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On June 5, 2017, the Company contributed all of its membership interests in three entities to Mammoth Energy in exchange for approximately 2.0 million shares of Mammoth Energy common stock. The Company accounted for this contribution as a sale of financial assets and recognized a gain of $12.5 million, which is included in gain on sale of equity method investments in the accompanying consolidated statements of operations for the year ended December 31, 2017.

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 $4.5 million. Following the sales of these shares, the Company owned 9,829,548 shares, or 21.9% 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 was $176.7 million based on the quoted market price of Mammoth Energy's common stock.

5.	LONG-TERM DEBT

Long-term debt consisted of the following items as of December 31:

	2019				2018
	(In thousands)
Revolving credit agreement(1)	$	120,000			$	45,000
6.625% senior unsecured notes due 2023	329,467				350,000
6.000% senior unsecured notes due 2024	603,428				650,000
6.375% senior unsecured notes due 2025	529,525				600,000
6.375% senior unsecured notes due 2026	397,529				450,000
Net unamortized debt issuance costs(2)	(23,751		)		(30,733		)
Construction loan	22,453				23,149
Less: current maturities of long term debt	(631		)		(651		)
Debt reflected as long term	$	1,978,020			$	2,086,765

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Maturities of long-term debt (excluding unamortized debt issuance costs) as of December 31, 2019 are as follows:

	(In thousands)
2020	$	631
2021	120,663
2022	694
2023	330,194
2024	604,186
Thereafter	946,034
Total	$	2,002,402

(1) The Company has entered into a senior secured revolving credit facility, as amended (the "revolving credit facility"), with The Bank of Nova Scotia, as the lead arranger and administrative agent and other lenders. The revolving credit facility matures on December 13, 2021. On June 3, 2019, the Company further amended its revolving credit facility to, among other things, allow the Company to designate certain of its subsidiaries as unrestricted subsidiaries and to include LIBOR replacement provisions. The borrowing base was reaffirmed at $1.4 billion, and the Company's elected commitment amount remained at $1.0 billion. On November 25, 2019, the borrowing base under the Company's revolving credit facility was reduced to $1.2 billion, and the Company's elected commitment remained at $1.0 billion.

As of December 31, 2019, $120.0 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 $243.6 million of letters of credit, was $636.4 million. The Company's wholly-owned subsidiaries have guaranteed the obligations of the Company under the revolving credit facility.

At December 31, 2019, amounts borrowed under the credit facility bore interest at a weighted average rate of 3.30%.

The Company was in compliance with all covenants related to its outstanding indebtedness at December 31, 2019.

(2) Loan issuance costs related to the 6.625% Senior Notes due 2023 (the "2023 Notes"), the 6.000% Senior Notes due 2024 (the "2024 Notes"), the 6.375% Senior Notes due 2025 (the "2025 Notes") and the 6.375% Senior Notes due 2026 (the "2026 Notes") (collectively the “Notes”) have been presented as a reduction to the principal amount of the Notes. At December 31, 2019, total unamortized debt issuance costs were $3.3 million for the 2023 Notes, $6.9 million for the 2024 Notes, $9.6 million for the 2025 Notes and $3.9 million for the 2026 Notes. In addition, loan commitment fee costs for the construction loan agreement described below were $0.1 million at December 31, 2019.

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, 2019, the Company used borrowings under its revolving credit facility to repurchase in the open market approximately $190.1 million aggregate principal amount of its outstanding Notes for $138.8 million in cash. This included approximately $20.5 million principal amount of the 2023 Notes, $46.6 million principal amount of the 2024 Notes, $70.5 million principal amount of the 2025 Notes, and $52.5 million principal amount of the 2026 Notes. The Company recognized a $48.6 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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	2019				2018				2017
	(In thousands)
Cash paid for interest	$	142,664			$	132,995			$	107,548
Change in accrued interest	(3,834		)		7,266				12,524
Capitalized interest	(3,372		)		(4,470		)		(9,470		)
Amortization of loan costs	6,328				6,121				5,011
Total interest expense	$	141,786			$	141,912			$	115,613

The Company capitalized approximately $3.4 million and $4.5 million in interest expense to undeveloped oil and natural gas properties during the years ended December 31, 2019 and 2018, respectively.

Fair Value of Debt

At December 31, 2019, the carrying value of the outstanding debt represented by the Notes was approximately $1.8 billion. Based on the quoted market prices (Level 1), the fair value of the Notes was determined to be approximately $1.3 billion at December 31, 2019.

6.	CHANGES IN CAPITALIZATION

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 did not require the Company to acquire any specific number of shares. This repurchase program was authorized to extend through December 31, 2018 and 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. Purchases under the repurchase program may be made from time to time in open market or privately negotiated transactions, and are 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. This repurchase program is authorized to extend through December 31, 2020. The program was suspended in the fourth quarter of 2019, but may be reactivated in the future depending on our projected leverage profile, commodity price outlook and market conditions.

7.	STOCK-BASED COMPENSATION

The Company adopted the 2005 Stock Incentive Plan ("2005 Plan") in January 2005. The 2005 Plan was amended and restated in April 2013 with the 2013 Restated Stock Incentive Plan ("2013 Plan"). During 2019, the Company further amended and restated the 2013 Plan with the 2019 Amended and Restated Stock Incentive Plan ("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, 2019, the Company has awarded 8,673,254 restricted stock units and 2,009,144 performance vesting restricted stock units under the 2019 Plan.

During the years ended December 31, 2019, 2018 and 2017 the Company’s stock-based compensation cost was $10.7 million, $11.3 million and $10.6 million, respectively, of which the Company capitalized $5.8 million, $4.5 million and $4.2

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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.

The following table summarizes restricted stock unit and performance vesting restricted stock unit activity for the twelve months ended December 31, 2019, 2018 and 2017: 

	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, 2017	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			$	—			$	—
Granted	4,011,073			3.74				2,009,144				2.85
Vested	(676,108	)		12.89				—				—
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

Restricted Stock Units

Restricted stock units awarded under the 2019 Plan generally vest over a period of 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, 2019 related to outstanding restricted stock units was $14.6 million. The expense is expected to be recognized over a weighted average period of 2.10 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, 2019. Unrecognized compensation expense as of December 31, 2019 related to performance vesting restricted stock units was $4.2 million. The expense is expected to be recognized over a weighted average period of 2.38 years.

8.	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

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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 satisfied at 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 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.

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 that have a contractual term greater than one year have no long-term fixed consideration.

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 $121.2 million and $210.2 million as of December 31, 2019 and December 31, 2018, respectively, and are reported in accounts receivable - oil and natural gas sales in the accompanying consolidated balance sheets. The Company currently has no assets or liabilities related to its revenue contracts, including no upfront or rights to deficiency payments.

Prior-Period Performance Obligations

The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain 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. For the year ended December 31, 2019, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

9.	LEASES

Effective January 1, 2019, the Company adopted ASU No. 2016-02, Leases (Topic 842). The new standard supersedes the previous lease guidance by requiring lessees to recognize a right-of-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 Company adopted the new standard on a prospective basis using the simplified transition method permitted by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements. 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 exceeding one year. No cumulative-effect adjustment to retained earnings was required upon adoption of the new standard. The comparative information has not been restated and continues to be reported under the historic accounting standards in effect for those periods. The Company elected the package of practical expedients permitted under the new standard, which among other things, allows for lease and non-lease components in a contract to be accounted for as a single lease component for all asset classes and the carry forward of historical lease classifications.

Nature of Leases

The Company has operating leases associated with drilling rig commitments, pressure pumping services, field offices and other equipment with remaining lease terms with contractual durations in excess of 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 third parties to ensure rig availability in its key operating areas. The Company has concluded its drilling rig contracts are operating leases as the assets are identifiable and the evaluation that 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 and expire at various dates through 2020. 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 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 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 these costs are borne by other interest owners.

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 and a related party. 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 through 2021 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. The Company has determined that the agreement with Stingray Pressure is an operating lease due to the implicit identification of assets and the evaluation that the Company has the right to control the identified assets. The operating lease liability associated with this agreement is based on the minimum contractual obligations, which is the monthly service fee for one crew, and does 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 these costs are borne by other interest owners. On December 18, 2019, the Company filed a lawsuit against Stingray Pressure to terminate this agreement. As the outcome of this lawsuit is unknown, the related right of use asset and operating lease liability are still recognized as of December 31, 2019 in the accompanying consolidated balance sheets.

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.

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 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.

Maturities of operating lease liabilities as of December 31, 2019 were as follows:

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		(In thousands)
2020		$	36,415
2021		22,569
2022		115
2023		90
2024		30
Total lease payments		$	59,219
Less: Imputed interest		(1,781		)
Total		$	57,438

Lease cost for the year ended December 31, 2019 consisted of the following:

	(In thousands)
Operating lease cost		$	24,960
Operating lease cost - related party		22,440
Variable lease cost		2,172
Variable lease cost - related party		66,924
Short-term lease cost		834
Total lease cost(1)		$	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 year ended December 31, 2019 related to leases was as follows:

Cash paid for amounts included in the measurement of lease liabilities		(In thousands)
Operating cash flows from operating leases		182
Investing cash flow from operating leases		24,263
Investing cash flow from operating leases - related party		84,750

10.	INCOME TAXES

The income tax provision consists of the following:

	2019				2018				2017
	(In thousands)
Current:
State	$	—			$	(1,530	)		$	2,167
Federal	(7		)		253				3,362
Deferred:
State	(7,556		)		1,530				(118		)
Federal	—				(322		)		(3,602		)
Total income tax (benefit) expense provision	$	(7,563	)		$	(69	)		$	1,809

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A reconciliation of the statutory federal income tax amount to the recorded expense follows:

	2019				2018				2017
	(In thousands)
Income (loss) before federal income taxes	$	(2,009,921	)		$	430,491			$	436,961
Expected income tax at statutory rate	(422,083		)		90,403				152,936
State income taxes	(28,316		)		(511		)		2,299
Other differences	3,372				1,078				5,731
Remeasurement due to Tax Cut and Jobs Act	—				—				190,034
Change in valuation allowance due to current year activity	439,464				(91,039		)		(158,704		)
Change in valuation allowance due to Tax Cuts and Jobs Act	—				—				(190,487		)
Income tax (benefit) expense recorded	$	(7,563	)		$	(69	)		$	1,809

The tax effects of temporary differences and net operating loss carryforwards, which give rise to deferred tax assets and liabilities at December 31, 2019, 2018 and 2017 are estimated as follows: 

	2019				2018				2017
	(In thousands)
Deferred tax assets:
Net operating loss carryforward	$	269,851			$	164,363			$	120,626
Oil and gas property basis difference	289,850				3,595				151,260
Investment in pass through entities	58,951				8,620				12,343
Stock-based compensation expense	1,440				616				813
Business energy investment tax credit	370				369				369
Charitable contributions carryover	297				269				255
Change in fair value of derivative instruments	11,219				2,761				—
Foreign tax credit carryforwards	943				2,009				2,074
Accrued liabilities	669				834				285
ARO liability	12,744				16,923				15,897
Non-oil and gas property basis difference	—				104				171
Lease liability	12,128				—				—
State net operating loss carryover	13,258				11,526				6,954
Interest expense carryforward	23,818				—				—
Total deferred tax assets	695,538				211,989				311,047
Valuation allowance for deferred tax assets	(647,575		)		(211,987		)		(298,830		)
Deferred tax assets, net of valuation allowance	47,963				2				12,217
Deferred tax liabilities:
Non-oil and gas property basis difference	1,859				—				—
Change in fair value of derivative instruments	26,410				2				11,009
Right of use asset	12,128				—				—
Other	3				—				—
Total deferred tax liabilities	40,400				2				11,009
Net deferred tax asset	$	7,563			$	—			$	1,208

The company recognized an income tax benefit of $7.6 million in 2019 and an income tax benefit of $69.0 thousand in 2018. The income tax benefit for 2019 consists mainly of a partial release of valuation allowance that was maintained against

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our Oklahoma deferred tax asset, as the Company believes that it can utilize a portion of its Oklahoma state NOL through carrybacks and carryforwards to offset Oklahoma sourced income from the sale of assets.

The Company has an available federal tax net operating loss carryforward estimated at approximately $1.3 billion as of December 31, 2019. This carryforward will begin to expire in the year 2023. The Company also has state net operating loss carryovers of $244.5 million that began to expire in 2019 and federal foreign tax credit carryovers of $0.9 million which began to expire in 2019.

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, 2019, the Company determined a valuation allowance was necessary with respect to its deferred tax assets, except for its Oklahoma state NOL. The more significant evidential matter relates to the Company’s recent cumulative losses resulting primarily from impairments to the full cost pool during 2019 and the decline in commodity prices. At December 31, 2019, the Company has recorded a total valuation allowance of $647.6 million related to the federal and state net deferred tax assets for which it believes do not meet the more likely than not threshold.

There was an increase of $439.5 million, a decrease of $86.8 million and a decrease of $347.0 million to the valuation allowance during 2019, 2018 and 2017, respectively. The increase in the valuation allowance in 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 pre-tax income. The decrease in the valuation allowance in 2017 was primarily due to pre-tax income and remeasurement of deferred tax assets due to the Tax Cuts and Jobs Act.

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% 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 the Company. As of December 31, 2019, the Company has completed a Section 382 analysis, which reflects that no ownership change has occurred to further limit the use of NOL carryforwards or other tax attributes. There are conditions that exist that are beyond the Company’s control which could cause an ownership change in the future and create a significant limitation on the Company's ability to utilize those tax attributes.

As of December 31, 2019, the Company has recorded a liability associated with uncertain tax positions of $3.1 million.

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11.	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,
	2019											2018											2017
	Loss				Shares			Per Share				Income				Shares			Per Share				Income				Shares			Per Share
	(In thousands, except share data)
Basic:
Net (loss) income	$	(2,002,358	)		160,341,125			$	(12.49	)		$	430,560			174,675,840			$	2.46			$	435,152			179,834,146			$	2.42
Effect of dilutive securities:
Stock options and awards	—				—							—				722,866							—				418,878
Diluted:
Net (loss) income	$	(2,002,358	)		160,341,125			$	(12.49	)		$	430,560			175,398,706			$	2.45			$	435,152			180,253,024			$	2.41

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12.	DERIVATIVE INSTRUMENTS

Natural Gas, Oil and Natural Gas Liquids Derivative Instruments

The Company seeks to reduce its 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 and various types of option contracts. These contracts allow the Company to predict with greater certainty the effective natural gas, oil and NGL prices to be received for hedged production and benefit operating cash flows and earnings when market prices are less than the fixed prices provided in the contracts. However, the Company will not benefit from market prices that are higher than the fixed prices in the contracts for hedged production.

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 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. Below is a summary of the Company's open fixed price swap positions as of December 31, 2019.

	Index	Daily Volume (MMBtu/day)			Weighted Average Price
2020	NYMEX Henry Hub	548,000			$	2.88

	Index	Daily Volume (Bbls/day)			Weighted Average Price
2020	NYMEX WTI	6,000			59.82

	Index	Daily Volume (Bbls/day)			Weighted Average Price
2020	Mont Belvieu C3	500			$	21.63

In the third quarter of 2019, 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 primarily for 2020 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, 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.

	Index	Daily Volume (MMBtu/day)			Weighted Average Price
2022	NYMEX Henry Hub	628,000			$	2.90
2023	NYMEX Henry Hub	628,000			$	2.90

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, the Company entered into natural gas basis swap positions. As of December 31, 2019, the Company had the following natural gas basis swap positions open:

	Gulfport Pays	Gulfport Receives	Daily Volume (MMBtu/day)			Weighted Average Fixed Spread
2020	Transco Zone 4	NYMEX Plus Fixed Spread	60,000			$	(0.05	)
2020	Fixed Spread	ONEOK Minus NYMEX	10,000			$	(0.54	)

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Contingent Consideration Arrangement

The purchase and sale agreement for 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)
July 2020 - 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.

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, 2019 and 2018:

	December 31,
	2019			2018
	(In thousands)
Commodity derivative instruments	125,383			21,352
Contingent consideration arrangement	818			—
Total short-term derivative instruments – asset	126,201			21,352
Commodity derivative instruments	—			—
Contingent consideration arrangement	563			—
Total long-term derivative instruments – asset	563			—
Total short-term derivative instruments – liability	303			$	20,401
Total long-term derivative instruments – liability	53,135			$	13,992

Gains and losses

The following table presents the gain and loss recognized in net gain (loss) on natural gas, oil and NGL derivatives in the accompanying consolidated statements of operations for the years ended December 31, 2019, 2018, and 2017.

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	Net gain (loss) on derivative instruments
	For the Year Ended December 31,
	2019				2018				2017
	(In thousands)
Natural gas derivatives	$	194,450			$	(116,130	)		$	232,143
Oil derivatives	7,035				(13,084		)		(3,350		)
NGL derivatives	6,632				5,735				(15,114		)
Contingent consideration arrangement	243				—				—
Total	$	208,360			$	(123,479	)		$	213,679

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, 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			$	—

	As of December 31, 2018
	Derivative instruments, gross				Netting adjustments				Derivative instruments, net
	(In thousands)
Derivative assets	$	21,352			$	(19,289	)		$	2,063
Derivative liabilities	$	(34,393	)		$	19,289			$	(15,104	)

Concentration of Credit Risk

13.	RESTRUCTURING COSTS

In the fourth quarter of 2019, the Company announced and completed a workforce reduction representing approximately 13% of its headcount. In connection with the reduction, the Company incurred a total charge of approximately $4.6 million, primarily consisting of one-time employee-related termination benefits, with a remaining liability of $0.2 million at December 31, 2019.

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, 2019 and 2018:

	December 31, 2019
	Level 1				Level 2			Level 3
	(In thousands)
Assets:
Derivative Instruments	$	—			126,764			$	—
Liabilities:
Derivative Instruments	$	—			53,438			$	—

	December 31, 2018
	Level 1				Level 2				Level 3
	(In thousands)
Assets:
Derivative Instruments	$	—			$	21,352			$	—
Liabilities:
Derivative Instruments	$	—			$	34,393			$	—

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.

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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 upward revisions recognized during the year ended December 31, 2019 were approximately $5.9 million and $0.9 million, respectively.

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 financial instruments

15.	RELATED PARTY TRANSACTIONS

In the ordinary course of business, the Company has conducted business activities with certain related parties.

As of December 31, 2019, the Company held approximately 21.8% of Mammoth Energy's outstanding common stock as discussed above in Note 4. Approximately $0.6 million, $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, 2019, 2018 and 2017, respectively. Approximately $109.9 million and $139.7 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 December 31, 2019 and 2018, respectively. At December 31, 2019 and 2018, the Company owed Mammoth Energy approximately $8.4 million and $10.9 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. 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 December 31, 2017, respectively.

16.	COMMITMENTS

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 made bi-weekly contributions 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, 2019, 2018 and 2017, Gulfport incurred $2.9 million, $2.6 million, and $3.0 million, respectively, in contributions expense related to this plan.

Future Sales Commitments

The Company has entered into various firm sales contracts 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 to satisfy the commitments.

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A summary of these commitments at December 31, 2019 are set forth in the table below:

	(MMBtu per day)
2020	326,000
2021	192,000
2022	70,000
2023	17,000
2024	—
Thereafter	—
Total	605,000

Future Firm Transportation Commitments

The Company has contractual commitments with pipeline carriers for future transportation of natural gas from the Company's production areas to downstream markets. Commitments related to future firm transportation agreements are not recorded as obligations in the accompanying consolidated balance sheets; however, they are reflected in the Company's estimates of proved reserves.

A summary of these commitments at December 31, 2019 are set forth in the table below:

	Total MMBtu			(In thousands)
2020	505,080,000			$	274,813
2021	531,075,000			286,626
2022	531,075,000			286,626
2023	515,867,000			282,945
2024	489,525,000			265,568
Thereafter	3,778,217,000			2,163,926
Total	6,350,839,000			$	3,560,504

Other Commitments

Effective October 1, 2014, the Company entered into a Sand Supply Agreement with Muskie Proppant LLC (“Muskie”), a subsidiary of Mammoth Energy and a related party. Pursuant to this agreement, as amended effective August 3, 2018, 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 through 2021. 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 $3.5 million and $2.2 million related to non-utilization fees during the years ended December 31, 2019 and 2018.

Future minimum commitments under these agreements at December 31, 2019 are as follows:

	(In thousands)
2020	$	7,500
2021	7,500
Total	$	15,000

17.	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 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 (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 alleges 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 seeks 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.

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, Saydee Resources, LLC, on behalf of itself and a class of similarly situated royalty holders, filed an action against the Company in the District Court of Grady County Oklahoma. The suit alleges that the Company underpaid royalty holders and seeks unspecified damages for breach of contract, tortious breach of contract, fraud and unjust enrichment.

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 alleges that the Company underpaid royalty owners and seeks unspecified damages for violations of the Oklahoma Production Revenue Standards Act and fraud.

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. We have fully cooperated and intend to continue to cooperate fully with the SEC’s investigation. Although it is not possible to predict the ultimate resolution or financial liability with respect to this matter, the Company believes that the outcome of this matter will not have a material effect on the Company's business, financial condition or results of operations.

Business Operations

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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 United States Environmental Protection Agency ("USEPA") alleging violations of the Clean Air Act in Ohio. The first FOV for one site was dated December 11, 2013.  Two subsequent FOVs incorporated and expanded the scope on January 4, 2017 and April 15, 2019.  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 is pending approval. 

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.

Insurance Proceeds

For the years ended December 31, 2019 and 2018 the Company was reimbursed $0.1 million and $0.2 million, respectively, net of related legal fees by its insurance provider, which is included in other expense (income) in the accompanying consolidated statements of operations. There were no insurance proceeds received in the year ended December 31, 2017.

Concentration of Credit Risk

Gulfport operates in the oil and natural gas industry principally in the states of Ohio and 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. At December 31, 2019, Gulfport held cash in excess of insured limits in these banks totaling $5.6 million.

18.	CONDENSED CONSOLIDATING FINANCIAL INFORMATION

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 revolving credit facility or certain other debt (the "Guarantors"). The Notes are not guaranteed by Grizzly Holdings, Mule Sky LLC ("Mule Sky") or GRUS, LLC ("GRUS")

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(the “Non-Guarantors”). 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. Effective June 1, 2019, the Parent contributed interests in certain oil and gas assets and related liabilities to certain of the Guarantors.

The following condensed consolidating balance sheets, statements of operations, statements of comprehensive income and statements of cash flows are provided for the Parent, the Guarantors and the Non-Guarantors 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-Guarantors.

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CONDENSED CONSOLIDATING BALANCE SHEETS

(Amounts in thousands)

	December 31, 2019
	Parent				Guarantors				Non-Guarantor				Eliminations				Consolidated
Assets
Current assets:
Cash and cash equivalents	$	2,768			$	3,097			$	195			$	—			$	6,060
Accounts receivable - oil and natural gas sales	859				120,351				—				—				121,210
Accounts receivable - joint interest and other	5,279				42,696				—				—				47,975
Accounts receivable - intercompany	1,065,593				843,223				—				(1,908,816		)		—
Prepaid expenses and other current assets	4,047				308				76				—				4,431
Short-term derivative instruments	126,201				—				—				—				126,201
Total current assets	1,204,747				1,009,675				271				(1,908,816		)		305,877
Property and equipment:
Oil and natural gas properties, full-cost accounting	1,314,933				9,273,681				7,850				(729		)		10,595,735
Other property and equipment	92,650				50				4,019				—				96,719
Accumulated depletion, depreciation, amortization and impairment	(1,418,888		)		(5,808,254		)		(1,518		)		—				(7,228,660		)
Property and equipment, net	(11,305		)		3,465,477				10,351				(729		)		3,463,794
Other assets:
Equity investments and investments in subsidiaries	3,064,503				6,332				21,000				(3,059,791		)		32,044
Long-term derivative instruments	563				—				—				—				563
Deferred tax asset	7,563				—				—				—				7,563
Inventories	—				5,182				—				—				5,182
Operating lease assets	14,168				—				—				—				14,168
Operating lease assets - related parties	43,270				—				—				—				43,270
Other assets	10,026				332												10,358
Total other assets	3,140,093				11,846				21,000				(3,059,791		)		113,148
Total assets	$	4,333,535			$	4,486,998			$	31,622			$	(4,969,336	)		$	3,882,819
Liabilities and stockholders' equity
Current liabilities:
Accounts payable and accrued liabilities	$	48,006			$	367,088			$	124			$	—			$	415,218
Accounts payable - intercompany	878,283				1,026,249				4,285				(1,908,817		)		—
Short-term derivative instruments	303				—				—				—				303
Current portion of operating lease liabilities	13,826				—				—				—				13,826
Current portion of operating lease liabilities - related parties	21,220				—				—				—				21,220
Current maturities of long-term debt	631				—				—				—				631
Total current liabilities	962,269				1,393,337				4,409				(1,908,817		)		451,198
Long-term derivative instruments	53,135				—				—				—				53,135
Asset retirement obligation - long-term	—				58,322				2,033				—				60,355
Uncertain tax position liability	3,127				—				—				—				3,127
Non-current operating lease liabilities	342				—				—				—				342
Non-current operating lease liabilities - related parties	22,050				—				—				—				22,050
Long-term debt, net of current maturities	1,978,020				—				—				—				1,978,020
Total liabilities	3,018,943				1,451,659				6,442				(1,908,817		)		2,568,227
Stockholders' equity:
Common stock	1,597				—				—				—				1,597
Paid-in capital	4,207,554				4,171,408				267,557				(4,438,965		)		4,207,554
Accumulated other comprehensive loss	(46,833		)		—				(44,763		)		44,763				(46,833		)
Accumulated deficit	(2,847,726		)		(1,136,069		)		(197,614		)		1,333,683				(2,847,726		)
Total stockholders' equity	1,314,592				3,035,339				25,180				(3,060,519		)		1,314,592
Total liabilities and stockholders' equity	$	4,333,535			$	4,486,998			$	31,622			$	(4,969,336	)		$	3,882,819

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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	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	7,843				2,174				—				—				10,017
Short-term derivative instruments	21,352				—				—				—				21,352
Total current assets	888,700				418,759				1				(991,097		)		316,363
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	4,210				1,134				—				—				5,344
Other assets	12,624				1,178				—				1				13,803
Total other assets	2,873,822				2,312				44,259				(2,665,125		)		255,268
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
Uncertain tax position 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

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CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(Amounts in thousands)

	Year Ended December 31, 2019
	Parent				Guarantors				Non-Guarantor				Eliminations				Consolidated
Total revenues	$	524,089			$	821,919			$	—			$	—			$	1,346,008
Costs and expenses:
Lease operating expenses	26,923				56,075				—				—				82,998
Production taxes	6,117				22,454				—				—				28,571
Midstream gathering and processing expenses	71,420				220,305				—				—				291,725
Depreciation, depletion and amortization	203,921				345,504				683				—				550,108
Impairment of oil and gas properties	—				2,039,770				—				—				2,039,770
General and administrative expenses	71,219				(23,748		)		508				—				47,979
Restructuring costs	4,611				—				—				—				4,611
Accretion expense	1,390				2,549				—				—				3,939
	385,601				2,662,909				1,191				—				3,049,701
INCOME (LOSS) FROM OPERATIONS	138,488				(1,840,990		)		(1,191		)		—				(1,703,693		)
OTHER (INCOME) EXPENSE:
Interest expense	144,645				(2,859		)		—				—				141,786
Interest income	(501		)		(300		)		—				—				(801		)
Gain on debt extinguishment	(48,630		)		—				—				—				(48,630		)
Loss (income) from equity method investments and investments in subsidiaries	2,053,533								32,710				(1,876,095		)		210,148
Other (income) expense, net	(638		)		3,364				—				999				3,725
	2,148,409				205				32,710				(1,875,096		)		306,228
(LOSS) INCOME BEFORE INCOME TAXES	(2,009,921		)		(1,841,195		)		(33,901		)		1,875,096				(2,009,921		)
INCOME TAX BENEFIT	(7,563		)		—				—				—				(7,563		)
NET (LOSS) INCOME	$	(2,002,358	)		$	(1,841,195	)		$	(33,901	)		$	1,875,096			$	(2,002,358	)

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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	52,664				(2,673		)		3				—				49,994
Accretion expense	3,228				891				—				—				4,119
	826,247				129,835				3				—				956,085
INCOME (LOSS) FROM OPERATIONS	12,994				385,968				(3		)		—				398,959
OTHER (INCOME) EXPENSE:
Interest expense	144,533				(2,621		)		—				—				141,912
Interest income	(287		)		(27		)		—				—				(314		)
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	(525		)		(33		)		—				2,100				1,542
	(417,497		)		(99,794		)		510				485,249				(31,532		)
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

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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
Impairment of oil and natural gas properties	—				—				—				—				—
General and administrative expenses	48,174				(2,654		)		3				—				45,523
Accretion expense	1,246				365				—				—				1,611
Acquisition expense	—				2,392				—				—				2,392
	682,616				81,903				3				—				764,522
INCOME (LOSS) FROM OPERATIONS	328,373				227,411				(3		)		—				555,781
OTHER (INCOME) EXPENSE:
Interest expense	120,147				(4,534		)		—				—				115,613
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		)
	(108,588		)		(2,924		)		2,189				228,143				118,820
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

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CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Amounts in thousands)

	Year Ended December 31, 2019
	Parent				Guarantors				Non-Guarantor				Eliminations				Consolidated
Net (loss) income	$	(2,002,358	)		$	(1,841,195	)		$	(33,901	)		$	1,875,096			$	(2,002,358	)
Foreign currency translation adjustment	9,193				173				9,020				(9,193		)		9,193
Other comprehensive loss (income)	9,193				173				9,020				(9,193		)		9,193
Comprehensive income (loss)	$	(1,993,165	)		$	(1,841,022	)		$	(24,881	)		$	1,865,903			$	(1,993,165	)

	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

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CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(Amounts in thousands)

	Year Ended December 31, 2019
	Parent				Guarantors				Non-Guarantor				Eliminations				Consolidated
Net cash provided by operating activities	$	64,037			$	656,443			$	3,510			$	3			$	723,993
Net cash provided by (used in) investing activities	8,605				(680,057		)		(3,751		)		432				(674,771		)
Net cash (used in) provided by financing activities	(95,459		)		—				435				(435		)		(95,459		)
Net (decrease) increase in cash and cash equivalents	(22,817		)		(23,614		)		194				—				(46,237		)
Cash and cash equivalents at beginning of period	25,585				26,711				1				—				52,297
Cash and cash equivalents at end of period	$	2,768			$	3,097			$	195			$	—			$	6,060

	Year Ended December 31, 2018
	Parent				Guarantors				Non-Guarantor				Eliminations				Consolidated
Net cash provided by operating activities	$	560,203			$	226,067			$	—			$	1			$	786,271
Net cash (used in) provided by investing activities	(445,869		)		(231,005		)		(2,318		)		2,318				(676,874		)
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

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19.	SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED)

The Company owns a 24.9999% interest in Grizzly, which interest is shown 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

	2019				2018
	(In thousands)
Proved properties	$	8,909,069			$	7,153,799
Unproved properties	1,686,666				2,873,037
	10,595,735				10,026,836
Accumulated depreciation, depletion, amortization and impairment	(7,191,957		)		(4,613,293		)
Net capitalized costs	$	3,403,778			$	5,413,543
Equity investment in Grizzly Oil Sands ULC
Proved properties	$	64,476			$	67,475
Unproved properties	85,395				79,605
	149,871				147,080
Accumulated depreciation, depletion, amortization and impairment	(1,634		)		(1,553		)
Net capitalized costs	$	148,237			$	145,527

Costs Incurred in Oil and Gas Property Acquisition and Development Activities

	2019				2018				2017
	(In thousands)
Acquisition	$	37,598			$	119,444			$	1,946,416
Development	594,673				714,269				1,138,951
Exploratory	9,762				22,081				9,058
Total	$	642,033			$	855,794			$	3,094,425
Equity investment in Grizzly Oil Sands ULC
Acquisition	$	—			$	238			$	503
Development	—				—				—
Exploratory	849				—				—
Total	$	849			$	238			$	503

Capitalized interest is included as part of the cost of oil and natural gas properties. The Company capitalized $3.4 million, $4.5 million and $9.5 million during 2019, 2018, and 2017, 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 $30.1 million, $37.7 million and $35.7 million during 2019, 2018, and 2017, respectively, which were directly related to the acquisition, exploration and development of the Company's oil and natural gas properties.

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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.

	2019				2018				2017
	(In thousands)
Revenues	$	1,137,648			$	1,478,523			$	1,106,624
Production costs	(403,294		)		(415,308		)		(350,367		)
Depletion	(539,379		)		(476,517		)		(358,792		)
Impairment	(2,039,770		)		—				—
Income tax benefit	7,563				68				240
Results of operations from producing activities	$	(1,837,232	)		$	586,766			$	397,705
Depletion per Mcf of gas equivalent (Mcfe)	$	1.08			$	0.96			$	0.90
Results of Operations from equity method investment in Grizzly Oil Sands ULC
Revenues	$	—			$	—			$	—
Production costs	—				—				—
Depletion	—				—				—
Income tax expense	—				—				—
Results of operations from producing activities	$	—			$	—			$	—

Oil and Natural Gas Reserves

The following table presents estimated volumes of proved developed and undeveloped oil and gas reserves as of December 31, 2019, 2018 and 2017 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, 2019, 2018 and 2017, 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 2019 reserve report are $55.85 per barrel of oil, $2.58 per MMbtu and $21.25 per barrel for NGL, adjusted by lease for transportation fees and regional price differentials, and for oil and gas reserves, respectively. The prices used at December 31, 2018 and 2017 for reserve report purposes are $65.56 per barrel, $3.10 per MMbtu and $32.02 per barrel for NGL and $51.34 per barrel, $2.98 per MMbtu and $18.40 per barrel for 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.

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	2019									2018									2017
	Oil			Natural Gas			NGL			Oil			Natural Gas			NGL			Oil			Natural Gas			NGL
	(Mbbls)			(MMcf)			(Mbbls)			(Mbbls)			(MMcf)			(Mbbls)			(Mbbls)			(MMcf)			(Mbbls)
Proved Reserves
Beginning of the period	21,050			4,133,889			80,520			19,157			4,825,310			75,766			5,546			2,167,068			20,127
Purchases in oil and natural gas reserves in place	—			—			—			—			—			—			15,132			1,098,644			53,617
Extensions and discoveries	3,612			997,014			12,992			5,205			622,271			9,631			951			1,594,734			4,619
Sales of oil and natural gas reserves in place	(2,369	)		(62,557	)		—			(134	)		(43,444	)		(112	)		—			—			—
Revisions of prior reserve estimates	(1,749	)		(561,890	)		(26,909	)		(377	)		(826,506	)		1,228			107			314,925			2,737
Current production	(2,186	)		(458,178	)		(5,074	)		(2,801	)		(443,742	)		(5,993	)		(2,579	)		(350,061	)		(5,334	)
End of period	18,357			4,048,279			61,528			21,050			4,133,889			80,520			19,157			4,825,310			75,766
Proved developed reserves	7,887			1,757,303			29,898			9,570			1,813,184			40,810			10,245			1,616,930			36,247
Proved undeveloped reserves	10,470			2,290,976			31,630			11,480			2,320,705			39,710			8,912			3,208,380			39,519
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	—			—			—			—			—			—			—			—			—

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 Shale 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 nine PUD locations in the Utica field and 22 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 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.

Subsequent to completion of estimates of proved reserves at December 31, 2019, management lowered its 2020 budgeted capital expenditures due to the expectation of continued depressed commodities pricing. All PUD locations in the

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December 31, 2019 proved reserve estimates remained in the development plan and are scheduled to be drilled within five years from the time of initial booking. However, development of several PUD locations was delayed. Management analyzed the impact of the timing of development and determined total proved reserves was materially unchanged and the total PV-10 value of reserves decreased by approximately 0.5%. Management determined these changes were immaterial and did not adjust its estimates of proved reserves at December 31, 2019 for the impact of these timing changes.

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 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 were 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 were operated by the Company and five of which were 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.

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, 2019, 2018 and 2017 using an unweighted average first-of-the-month price for the period January through December 31, 2019, 2018 and 2017.

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Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves  

	Year ended December 31,
	2019				2018				2017
	(In thousands)
Future cash flows	$	10,451,179			$	14,483,197			$	11,202,692
Future development and abandonment costs	(2,058,374		)		(2,437,853		)		(3,005,217		)
Future production costs	(4,512,940		)		(5,067,554		)		(2,152,821		)
Future production taxes	(332,525		)		(455,840		)		(289,944		)
Future income taxes	—				(943,293		)		(573,965		)
Future net cash flows	3,547,340				5,578,657				5,180,745
10% discount to reflect timing of cash flows	(1,843,753		)		(2,595,932		)		(2,537,181		)
Standardized measure of discounted future net cash flows	$	1,703,587			$	2,982,725			$	2,643,564
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	$	—			$	—			$	—

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Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

	Year ended December 31,
	2019				2018				2017
	(In thousands)
Sales and transfers of oil and gas produced, net of production costs	$	(734,354	)		$	(1,063,215	)		$	(756,257	)
Net changes in prices, production costs, and development costs	(1,372,443		)		590,519				913,714
Acquisition of oil and gas reserves in place	—				—				703,866
Extensions and discoveries	388,151				519,137				618,039
Previously estimated development costs incurred during the period	405,979				402,156				390,673
Revisions of previous quantity estimates, less related production costs	(321,397		)		(356,933		)		155,200
Sales of oil and gas reserves in place	(48,547		)		(25,882		)		—
Accretion of discount	298,273				264,356				68,804
Net changes in income taxes	424,628				(185,157		)		(231,545		)
Change in production rates and other	(319,428		)		194,180				93,030
Total change in standardized measure of discounted future net cash flows	$	(1,279,138	)		$	339,161			$	1,955,524
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	$	—			$	—			$	—

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20.	SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

The following table summarizes quarterly financial data for the years ended December 31, 2019 and 2018:

21.	SUBSEQUENT EVENTS

Sale of Water Infrastructure Assets

In December 2019, the Company entered into an agreement to divest its water infrastructure assets across its SCOOP position to a third-party water service provider. This transaction closed on January 2, 2020. The Company received $50.0 million in cash 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 future water production levels. The agreement contains no minimum volume commitments. The assets related to this transaction are included in the amortization base of the full cost pool and the Company does not expect to recognize a gain or loss in the statement of operations.

Derivatives

In January and February 2020, the Company early terminated some of its fixed price swaps for natural gas scheduled to settle in August through November of 2020 covering an average of approximately 294,000 MMBtu of natural gas per day over this four month period. The value of these early terminations was used to enhance the fixed price for new natural gas swaps for April and May of 2020 covering an average of approximately 472,000 MMBtu of natural gas per day over this two month period at a weighted average price of $2.85 per MMBtu.

Debt Repurchases

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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.

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